Document ID: FERC-2010-0120-0002
Agency: ferc
Document Type: Rule
Title: Credit Reforms in Organized Wholesale Electric Markets
Posted Date: 2010-10-27T04:00Z

[Federal Register: October 27, 2010 (Volume 75, Number 207)]
[Rules and Regulations]               
[Page 65942-65964]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr27oc10-4]                         

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

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

 
Credit Reforms in Organized Wholesale Electric Markets

Issued October 21, 2010.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: Pursuant to section 206 of the Federal Power Act, the Federal 
Energy Regulatory Commission amends its regulations to improve the 
management of risk and the subsequent use of credit in the organized 
wholesale electric markets. Each Regional Transmission Organization 
(RTO) and Independent System Operator (ISO) will be required to submit 
a compliance filing including tariff revisions to comply with the 
amended regulations or to demonstrate that its existing tariff already 
satisfies the regulations.

DATES:  Effective Date: This Final Rule will become effective on 
November 26, 2010.

FOR FURTHER INFORMATION CONTACT:

Christina Hayes (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-6194.
Lawrence Greenfield (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-6415.
Scott Miller (Technical Information), Office of Energy Policy and 
Innovation, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, (202) 502-8456.

SUPPLEMENTARY INFORMATION: 

Before Commissioners: Jon Wellinghoff, Chairman; Marc Spitzer, 
Philip D. Moeller, John R. Norris, and Cheryl A. LaFleur.

I. Introduction

    1. This Final Rule adopts reforms to credit policies used in 
organized wholesale electric power markets.\1\
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    \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).
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    2. The Commission has a statutory mandate to ensure that all rates 
charged for the transmission or sale of electric energy in interstate 
commerce are just, reasonable, and not unduly discriminatory or 
preferential; \2\ clear and consistent credit practices are an 
important element of those rates. The management of risk and credit 
necessarily involves balance. If access to credit is too restrictive, 
competition suffers because fewer entities are eligible to participate, 
which can potentially reduce competition. Conversely, if more risk is 
tolerated and access to credit is too easy to obtain, then the market 
is more susceptible to defaults and customers bear the burden of the 
costs that flow from such defaults. In organized wholesale electric 
markets, defaults not supported by collateral are socialized among all 
other market participants.
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    \2\ 16 U.S.C. 824d, 824e (2006).
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    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

[[Page 65943]]

markets under its jurisdiction. The Commission is thus issuing this 
Final Rule, requiring shortened settlement timeframes, restrictions on 
the use of unsecured credit, elimination of unsecured credit in all 
financial transmission rights (FTR) or equivalent markets,\3\ steps to 
address the risk that RTOs and ISOs may not be allowed to use netting 
and set-offs, the establishment of minimum criteria for market 
participation, clarification regarding the organized market 
administrators' ability to invoke ``material adverse change'' to demand 
additional collateral from participants, adopting a standardized grace 
period for ``curing'' collateral calls, and establishing a general 
policy with regard to the differentiation in the applicability of these 
standards and reforms.
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    \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.
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II. Background

A. Development of Credit Practices in Organized Wholesale Electric 
Markets

    5. The Commission has long been actively interested in the credit 
practices of the wholesale electric markets. In crafting the pro forma 
Open Access Transmission Tariff (OATT) in Order No. 888, the Commission 
directed that each transmission provider's tariff include reasonable 
creditworthiness standards.\4\ However, in response to the credit 
downgrades in the energy industry of 2001-2002,\5\ and the resulting 
severe contraction in the credit markets, the Commission held a 
technical conference in which it received significant testimony that it 
should take action regarding credit practices in the organized 
electricity markets.\6\
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    \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. 
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).
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    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.
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    \7\ Policy Statement on Electric Creditworthiness, 109 FERC ] 
61,186 (2004) (Policy Statement).
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    7. Since it was issued, the ISOs and RTOs have made incremental 
progress in implementing the suggestions contained in the Policy 
Statement. However, the results of these efforts have been varied, 
leading to a wide range of risk management and creditworthiness 
practices among ISOs and RTOs. Because currently a default by one 
market participant is routinely socialized among all of the others in 
an ISO or RTO, this variable development of risk management practices 
has left many utilities at risk for a disruption in the market.

B. Credit Crunch of 2008 and Subsequent Events

    8. During the autumn of 2008, large disruptions in the financial 
markets affected the credit markets and reduced the availability of 
credit. The electricity markets were vulnerable to the effects of this 
broader financial crisis as concern grew that default in the organized 
markets could lead to a damaging drop in market liquidity placing the 
markets themselves in jeopardy.\8\ And one of the other effects of the 
crisis in the financial markets at that time was that credit went from 
being relatively plentiful and inexpensive to relatively scarce and 
expensive.\9\
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    \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 three-month Treasury bill (T-Bill) yields indicates 
the ability to obtain commercial credit: the wider the spread, the 
harder it is to obtain commercial credit. According to Bloomberg, 
the spread for 90 day T-Bills to 90 day commercial paper was 448 
basis points on October 13, 2008, compared to an average spread of 
53 basis points between April 1, 1997 and December 31, 2009.
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    9. The Commission held a technical conference in January of 2009 to 
investigate the role of credit in light of the recent financial 
crisis.\10\ While the organized wholesale electric markets had 
generally functioned well overall, there were representations that 
improvements could be made based on the recent experience. Mr. Philip 
Leiber of CAISO stated that defaults in the PJM FTR markets spurred 
credit reforms at CAISO, but the threat of problems from larger market 
participants, especially related to a Bear Stearns subsidiary, also 
``tested our concerns.'' \11\ Others testified about ``recent near-
misses'' in the organized wholesale markets and suggested that the 
Commission should consider improvements in credit practices.\12\
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    \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).
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    10. In light of these events, the Commission proposed that the 
different credit practices among the organized wholesale electric 
markets must be strengthened.

C. Notice of Proposed Rulemaking on Credit Reforms in Organized 
Wholesale Electric Markets

    11. On January 21, 2010, the Commission issued a NOPR pursuant to 
the Commission's responsibility under section 206 of the Federal Power 
Act (FPA).\13\ The Commission proposed the following reforms related to 
the administration of credit in the organized markets: (1) 
Implementation of a billing period of no more than seven days and a 
settlement period of no more than seven days; (2) reduction in the 
allocation of unsecured credit to no more than $50 million per market 
participant and a further aggregate cap per corporate family; (3) 
elimination of unsecured credit for FTR markets, (4) clarification of 
the ISOs/RTOs' status as a party to each transaction so as to eliminate 
any ambiguity or question as to their ability to net and manage 
defaults through the offset of market obligations; (5) establishment of 
minimum criteria for market participation; (6) clarification of when

[[Page 65944]]

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.
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    \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).
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    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\
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    \14\ Id. P 9.
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D. The Need for Credit Reform in the Organized Wholesale Electric 
Markets

    13. Sound credit practices are necessary to prevent a disruption in 
the system, and it is not acceptable to wait until after a disruption 
to implement the necessary standards. The Commission acknowledges the 
short-term costs of compliance with the credit practices required in 
this Final Rule but finds that they are outweighed by the stability 
that those credit practices provide to the markets and their 
participants. Therefore, in compliance filings to be submitted 
providing tariff revisions to comply with the Final Rule, ISOs and RTOs 
should apply these standards to market participants.
    14. The Commission has considered the comments submitted, as well 
as the practices of electricity markets outside the United States and 
in other commodity markets.\15\ The Commission has used the experience 
of these markets in addition to its own review of the organized markets 
in issuing this Final Rule.
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    \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/committees-groups/committees/mc/20080626/20080626-item-03d-
crmsc-market-reform-credit-recommendations.ashx; and CME market 
requirements at http://www.cmegroup.com/clearing/financial-and-
collateral-management.
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    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\
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    \16\ The commenters are listed in an appendix to this Final 
Rule.
    \17\ Notice Establishing Date for Comments, 75 FR 27552 (May 17, 
2010).
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III. Discussion

A. Shortening the Settlement Cycle

    16. As noted above, in developing this Final Rule, the Commission 
has considered the practices of other commodity markets, as well as 
electricity markets around the world. While we note that many other 
commodity markets employ risk management practices that are useful in 
minimizing the risk of a socialized default among other participants in 
those markets, we are also mindful of the importance of the continued 
reliable delivery of electricity and that some market participants have 
``provider of last resort'' obligations that require them to continue 
transacting in a market, even under challenging financial conditions.
    17. The Commission and participants in the electric industry have 
recognized a correlation between a reduction in the ``settlement 
cycle'' \18\ and a reduction in costs attributed to a default. As the 
Commission noted in its Policy Statement, ``the size of credit risk 
exposure is, in large part, a function of the length of time between 
completion of various parts of electricity transactions, i.e., the 
provision of service, the billing for service, and the payment of 
service.'' \19\
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    \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.
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    18. Currently, each ISO and RTO has its own time period for billing 
and settlement. ISO-NE has weekly billing (soon to be twice-weekly), 
with payment due no later than the second business day after the 
invoice is issued.\20\ Midwest ISO has weekly billing, with payment due 
seven days after the weekly invoice is issued.\21\ PJM has weekly 
billing and settlement.\22\ SPP has weekly billing, with payment due 
the Wednesday after the invoice is issued.\23\ CAISO has semi-monthly 
billing, with five additional days for settlement.\24\ NYISO has 
monthly billing, with payment due by the first banking day common to 
all parties after the 15th day of the month that the invoice is 
rendered by the ISO.\25\
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    \20\ ISO New England, Inc. and New England Power Pool, 132 FERC 
] 61,046 (2010).
    \21\ Midwest ISO March 29, 2010 Comments at 4.
    \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.
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    19. To minimize the risk associated with the duration of the 
settlement period, the Commission proposed in the NOPR to require no 
more than seven days for each ISO/RTO market billing period plus no 
more than seven calendar days for settlement. The Commission cited a 
PJM study that found that movement from monthly to weekly billing would 
reduce credit risk exposure by $2.1 billion (68 percent), and that 
necessary financial security provided by members would be reduced by 
$700 million (73 percent).\26\ Further, the Commission's earlier Policy 
Statement cited an ISO-NE report that its movement to a weekly billing 
period resulted in a 67 percent reduction in financial assurances that 
had to be produced by its market participants.\27\ The Commission also 
sought comment on the practicality of moving organized wholesale 
electric markets to daily billing within one year of implementation of 
weekly billing.
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    \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/
committees-groups/committees/mc/20080626/20080626-item-03d-crmsc-
market-reform-credit-recommendations.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 Assurance Policies to Implement Weekly 
Billing, Paul Belval and Scott Myers, NEPOOL Counsel, Feb. 21, 
2004).
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    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

[[Page 65945]]

Morgan Stanley Capital Group (Morgan Stanley). The staff of the 
Division of Clearing & Intermediary Oversight at the Commodity Futures 
Trading Commission (CFTC staff) also supports moving the billing cycle 
to, at most, seven days.\29\
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    \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.
    \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.
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    23. Many industry participants who are normally ``net sellers'' of 
supply such as Constellation, NRG, Calpine, Dominion, Mirant, and 
Powerex also support the proposed shortened billing time-period.\30\ 
CCRO supports a standard seven-day billing period as ``consistent'' 
with its review of best practices in the electric industry.\31\ The New 
York Suppliers note that NYISO is the lone organized market in the 
nation with a monthly billing period.\32\ The New York Suppliers 
contend that allowing NYISO--or CAISO which currently has a two-week 
billing cycle--to remain out of step with a weekly standard elsewhere 
increases the risks to participants in New York and California.\33\ The 
Independent Power Producers of New York (IPPNY) comments that, since 
the beginning of weekly billing in ISO-NE, the number of market 
participants has increased in every sector and the total number of 
market participants increased by over 60 percent,\34\ suggesting that 
not only was liquidity enhanced by shorter billing but the change did 
not pose a barrier to entry.
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    \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.
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    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\
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    \35\ Powerex March 29, 2010 Comments at 6-7.
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    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\
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    \36\ CAISO March 29, 2010 Comments at 7-8.
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    26. Parties opposing the proposal include the City of New York, the 
New York State Public Service Commission (NYPSC) and ``Six Cities.'' 
\37\ Indeed, the City of New York and the NYPSC argue that the 
Commission should not impose a shorter settlement period just for the 
sake of uniformity and that the Commission should give deference to the 
policies adopted through ISO and RTO governance processes.\38\ The 
NYPSC and the New York State Consumer Protection Board (NYSCPB) further 
contend that weekly billing could result in a wealth transfer from some 
market participants to others.\39\
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    \37\ The ``Six Cities'' include the cities of Anaheim, Azusa, 
Banning, Colton, Pasadena, and Riverside, all located in California.
    \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.
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    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\
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    \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.
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    28. Regarding the Commission's request for comment on the 
practicality of organized wholesale electric markets implementing daily 
settlement periods within one year of implementation of weekly 
settlement periods, there was very little commenter support for this 
proposal. Most of the support for this proposal came from financial 
entities. CFTC staff, J.P. Morgan and Morgan Stanley support this 
proposal.\43\ CFTC staff argues that routine and frequent settlement 
imposes discipline on participants, in that it discourages participants 
from entering into new positions without first ensuring that they have 
adequate liquidity to support such positions. CFTC staff also states 
that the collection of payments from FTR market participants should 
happen promptly, within hours or overnight.\44\
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    \43\ J.P. Morgan Comments at 6; MSCG Comments at 2-3.
    \44\ CFTC staff Comments on 5.
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    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\
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    \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.
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    30. However, many stakeholder group members opposed daily 
settlement. CAISO, the IRC, Midwest ISO, and PJM do not support daily 
invoicing. CAISO, Midwest ISO and PJM all cite financial and logistical 
concerns as reasons to oppose daily billing. The IRC does not believe 
the Commission should mandate a move to daily settlement periods, but 
should allow ISOs/RTOs to work with stakeholders to research the 
proposal further to evaluate the daily costs and benefits. PJM states 
that stakeholder discussions should occur prior to determining whether 
such a change would be cost beneficial to the market participants in 
the PJM region. PJM also states that its current settlement system does 
not have the flexibility to issue daily invoices.\48\
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    \48\ CAISO Comments at 9; IRC Comments at 4-5; MISO Comments at 
5; PJM Comments at 21-23.
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    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\

[[Page 65946]]

Midwest TDUs state that daily settlements are unworkable now and in the 
foreseeable future, and should be addressed by the individual ISOs/
RTOs.\51\ NRECA also points out that the movement to shortened 
settlement cycles would occur at the same time utilities implement 
``smart grid'' applications and NRECA questions whether all metering 
and computer hardware and software systems can be done at the same 
time.\52\ Western Area Power Administration (WAPA) believes daily 
settlements are impractical and it would not allow the opportunity to 
correct errors which could use up all available funds unnecessarily in 
a matter of a few days. WAPA is concerned about daily settlements and 
the timing of the CAISO invoices, which are issued at midnight, because 
it would unfairly shorten the daily settlement processing period to 
less than 24 hours.\53\
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    \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.
    \53\ WAPA Comments at 5-6.
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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.
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    \54\ Policy Statement, 109 FERC ] 61,186, at P 24.
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    33. The basic premise for shorter billing periods is that the 
reduced amount of unpaid debt left outstanding reduces the size of any 
default and therefore reduces the likelihood of the default leading to 
a disruption in the market such as cascading defaults and dramatically 
reduced market liquidity. In addition, the reduction in outstanding 
obligation also decreases the amount of collateral that market 
participants must post, which mitigates the affect on market 
participants of reducing the amount of unsecured credit the ISOs and 
RTOs can extend. The Commission's decision is supported by the studies 
performed by ISO-NE and PJM.\55\
---------------------------------------------------------------------------

    \55\ See, e.g., Market Reform, ``PJM Credit and Clearing 
Analysis Project Findings and Recommendations'' (June 2008) see 
http://www.pjm.com/~/media/committees-groups/committees/mc/20080626/
20080626-item-03d-crmsc-market-reform-credit-recommendations.ashx; 
NEPOOL Participants Committee, Weekly Billing Presentation, (January 
9, 2004).
---------------------------------------------------------------------------

    34. The Commission does not agree with the statement of the NYPSC 
or the City of New York that the movement to a weekly billing period 
will be a ``wealth transfer'' from buyers to sellers. The Commission is 
focused on the benefits of reduced risk afforded to all market 
participants by a minimum standard of weekly billing. While short-run 
working capital costs may be shifted, the result is that the overall 
cost of default will be lower for every market participant. Thus, all 
participants will benefit in this circumstance.
    35. The Commission also disagrees that there may be problems 
verifying data. ISO-NE, SPP, and Midwest ISO have shown that they can 
administer weekly billing without significant incident. The experience 
of these markets suggests that data handling and verification should 
not pose insurmountable challenges. Regarding PG&E's discussion of 
reduction of billing time in the bilateral markets, the Commission 
believes that individual counterparties to bilateral contracts may 
negotiate their own billing terms.
    36. As for parties that urged the Commission to not mandate a ``one 
size fits all'' approach in establishing minimum billing periods or 
that the Commission should defer to stakeholders in this matter, the 
Commission disagrees. Nothing in this record suggests that any of the 
organized wholesale electric markets is differently situated in a 
manner that warrants deviating from this minimum standard for billing 
periods.
    37. Recognizing the benefits that will flow from requiring billing 
to be at least weekly, and balancing the incremental benefits and 
incremental burdens of daily billing, we will not require daily billing 
at this time. Instead we will require, as discussed above, weekly 
billing.

B. Use of Unsecured Credit

    38. The use of unsecured credit varies among the organized markets. 
SPP currently limits extensions of unsecured credit to any single 
entity or affiliated group of entities to $25 million.\56\ CAISO and 
PJM extend no more than $50 million per market participant.\57\ Midwest 
ISO and ISO-NE allow up to $75 million per market participant,\58\ and 
NYISO extends up to $150 million per market participant.\59\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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

[[Page 65947]]

(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.
---------------------------------------------------------------------------

    \61\ New Jersey Public Power Comments at 10.
    \62\ Powerex March 29, 2010 Comments at 7-8.
---------------------------------------------------------------------------

    42. The CPUC asserted that the Commission should not arbitrarily 
limit unsecured credit. To the extent the Commission decides to limit 
unsecured credit, CPUC suggests limiting unsecured credit to a level 
that corresponds to the settlement cycle.\63\ When determining the 
amount of unsecured credit for a given entity, the CPUC recommends 
using a process which is based on a consistent, systematic, and non-
discriminatory approach. The CPUC states that market participants with 
higher credit ratings should be allowed to have higher unsecured 
credit.\64\
---------------------------------------------------------------------------

    \63\ CPUC March 29, 2010 Comments at 3.
    \64\ Id. at 3-4.
---------------------------------------------------------------------------

    43. A number of commenters support the continued use of unsecured 
credit, and state that the Commission should allow each ISO/RTO, 
through the stakeholder process, to determine a formula or method to 
limit the amount of unsecured credit.\65\ EEI states that the 
Commission should require the ISO/RTO to justify the maximum amount of 
unsecured credit that the ISO/RTO permits to any participants using a 
formula. Morgan Stanley states that credit should be extended based 
upon an application of objective financial criteria to evaluate 
carrying capacity and default probabilities.\66\ Consolidated Edison 
Solutions states that a national cap would not recognize the 
creditworthiness of financially strong companies and may set the level 
too low for regions with high energy costs.\67\ APPA believes that each 
RTO should tailor their credit policies to take into account the 
respective financial strengths and business models of the various 
market participants.\68\
---------------------------------------------------------------------------

    \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.
    \68\ APPA March 29, 2010 Comments at 4.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \69\ Northeast ISOs March 29, 2010 Comments at 6-7.
    \70\ Basin Electric March 29, 2010 Comments at 3.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \71\ NRECA March 29, 2010 Comments at 11.
    \72\ Shell Energy March 29, 2010 Comments at 7.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

c. Different Cap for Markets of Different Size
    48. In the NOPR, the Commission asked whether the caps on unsecured 
credit should differ as a result of differing market size. BP Energy 
specifically notes that the size of the market should make a difference 
in terms of the amount of unsecured credit allowed and that the 
Commission should not mandate a particular amount. MidAmerican agrees 
and states that any limit should be formulaic. Mirant favors avoiding a 
``one size fits all'' approach to setting unsecured credit limits. PSEG 
suggests that the cap should be based upon the risk of each individual 
market participant and factors unique to each ISO/RTO. Consequently, 
PSEG argues, this issue is best left to each ISO/RTO and its 
stakeholders.
2. Commission Determination
    49. The Commission adopts the NOPR proposal to require each ISO and 
RTO to revise its tariff provisions to reduce the extension of 
unsecured credit to no more than $50 million per market participant.
    50. The Commission is concerned that RTOs and ISOs, even after 
analyzing the creditworthiness of market participants, have allowed 
large amounts of unsecured credit in their markets (during the 
financial crisis in fall 2008, ranging from 50 to 80 percent). The 
Commission recognizes that unsecured credit may provide increased 
liquidity in the organized wholesale electric markets and is only 
extended after the ISO/RTO has performed a credit analysis of the 
market participant receiving the unsecured credit. However, the 
Commission is concerned that the assumptions upon which any credit 
analysis is made can change rapidly. For instance, Lehman Brothers was 
rated as ``investment grade'' by all ratings agencies on Friday, 
September 12, 2008, only to file for bankruptcy on Monday, September 
15, 2008.\76\ The Commission considered several factors, as well as the 
comments, in establishing the $50 million cap on unsecured credit per 
market participant. We note that CAISO and PJM have adopted a $50

[[Page 65948]]

million cap on unsecured credit for a single market participant, 
indicating that this level has already been accepted and incorporated 
into the business practices of market participants throughout the 
country. Most importantly, based on experience with past defaults, we 
are persuaded that the organized wholesale electric markets could 
withstand a default of this magnitude by a single market 
participant.\77\ The Commission further believes that this cap on 
unsecured credit per market participant balances the interests of 
market participants by not raising costs by an unreasonable amount 
while still protecting the markets and their participants from 
unacceptable disruption.
---------------------------------------------------------------------------

    \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/lbcs-default-update.ashx.
    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    52. As discussed earlier, the Commission must balance the needs of 
market liquidity with overall risk. To achieve this balance, the 
Commission directs each ISO and RTO to submit a compliance filing that 
includes tariff revisions to establish a limit on unsecured credit of 
no more than $50 million per market participant. This compliance filing 
must be submitted by June 30, 2011, and the tariff revisions will take 
effect October 1, 2011. In response to commenters who argue that 
markets that are a different size should have different caps on 
unsecured credit, we note that the $50 million limit on unsecured 
credit is a ceiling, not a mandated amount. Any organized wholesale 
electric market may establish a lower limit, either for individual 
market participants or based on the market administrator's credit 
analysis of a particular market participant.
    53. The Commission further establishes, for each organized 
wholesale electric market, a maximum level of $100 million of unsecured 
credit for all entities within a corporate family. This level would 
allow multiple market participants within one corporate family to each 
have access to a significant level of unsecured credit, up to $50 
million in each organized wholesale electric market as indicated above, 
to conduct business. Adoption of an overall corporate family cap of 
$100 million of unsecured credit in each organized wholesale electric 
market reflects our experience in the RTO and ISO markets where many 
entities have multiple subsidiary companies operating in the same 
market. By implementing a cap on a corporate family, the Commission 
avoids a scenario in which multiple market participants within one 
corporate family have $50 million in unsecured credit per participant, 
and a bankruptcy of the entire corporate family results in a 
significant default in an organized wholesale electric market.\79\ As 
indicated by Mr. Duane's testimony at the technical conference, a 
default of $100 million in an organized wholesale electric market would 
be significant, even in a market the size of PJM. Moreover, we believe 
that this level of unsecured credit strikes a balance by not raising 
costs for market participants by an unreasonable amount while still 
protecting the markets and their participants from unacceptable 
disruption.
---------------------------------------------------------------------------

    \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 participant could result in a significant disruption in an 
organized wholesale electric market.
---------------------------------------------------------------------------

    54. The Commission thus directs each ISO and RTO to submit a 
compliance filing that includes tariff revisions to establish an 
aggregate cap on unsecured credit per corporate family of no more than 
$100 million. This compliance filing likewise must be submitted by June 
30, 2011, and the tariff revisions will take effect October 1, 2011. 
Similar to the cap on individual market participants, each ISO or RTO 
may establish a lower level for the aggregate cap.
    55. The Commission views the limits as an upper ceiling or limit 
which will allow for varied amounts below the $50 million and $100 
million thresholds. The Commission agrees that limits below the 
Commission-prescribed levels can be set depending on relative market 
size, the price of energy, the number of megawatt hours, and the size 
and number of the members, for example.
    56. The Commission also believes that the contention of Morgan 
Stanley, that ISOs and RTOs should explicitly consider parent 
guarantees in their evaluation of credit, is contrary to the point of 
this rulemaking. Parent guarantees are simply another form of unsecured 
credit that will not necessarily protect a market from default by 
market participants if the parent company experiences financial 
distress, and the Commission directs ISOs and RTOs to not take them 
into account in establishing the appropriate level of unsecured credit 
for a market participant or aggregate cap.
    57. The Commission further disagrees that an aggregate cap is not 
needed in a corporate family structure that has both unregulated 
entities and regulated utilities. Regulated entities, even those with 
cost-of-service rates, do not necessarily have a revenue stream 
guaranteed to cover wholesale market costs, and thus should not be 
assumed to be without risk of default.

C. Elimination of Unsecured Credit for Financial Transmission Rights 
Markets

    58. The proposal to eliminate the allocation of unsecured credit in 
FTR markets or their equivalent is based on the unique nature of 
FTRs.\80\ The value of the FTR can vary widely over very short periods 
of time. Further, owing to the relationship to the physical state of 
the electric grid, the state of which is known to all market 
participants, there are few if any participants who would be willing to 
``step into'' the shoes of a party that is nearing default as a FTR 
position deteriorates financially. FTR markets entail obligations that 
are normally active over a long period of time, often a year or more, 
and their potential change in value over this time frame is quite 
large.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    59. The value of so-called ``prevailing flow'' FTRs \81\ are 
generally predictable when there are no substantial changes in fuel 
prices or the physical state of the electric grid. However, outages on 
the transmission system and substantial changes in fuel prices can 
cause

[[Page 65949]]

unforeseen flow patterns and result in a rapid and dramatic drop in the 
value of an FTR position.\82\ For example, a large transformer or major 
transmission line can fail, thus changing flows of electricity and 
causing increased congestion in other areas. This will happen nearly 
instantaneously and the effect on the flows of electricity will remain 
in effect for whatever period of time it takes to repair or replace the 
equipment. In some cases, this could be months or longer. Thus the use 
of unsecured credit in a market with risk that is difficult to quantify 
can lead to unforeseen and substantial costs in the event of a default.
---------------------------------------------------------------------------

    \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/market-oversight/st-mkt-ovr/som-
rpt-2009.pdf.
---------------------------------------------------------------------------

    60. In the NOPR, the Commission proposed to revise its regulations 
to require that each RTO and ISO include in the credit provisions of 
its tariff provisions that eliminate unsecured credit in financial 
transmission rights markets.
1. Comments
    61. The response to the Commission's proposal to eliminate the use 
of unsecured credit in FTR markets is mixed. Parties that support the 
proposal include SPP, Basin Electric, the Organization of Midwest ISO 
States (OMS), Calpine, Citigroup, DC Energy, Dominion, Shell Energy, 
the Northeast ISOs, the New York Transmission Owners (NYTO), National 
Energy Marketers Association (NEMA), and J.P. Morgan.\83\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    62. NYISO states general support for the elimination of unsecured 
credit for its TCC \84\ 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \87\ CPUC March 29, 2010 Comments at 4.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \88\ Joint Commenters include Constellation Energy Commodities 
Group, Inc., Constellation NewEnergy, Inc., and Integrys Energy 
Services, Inc.
    \89\ Joint Commenters March 29, 2010 Comments at 12.
    \90\ EEI March 29, 2010 Comments at 11.
    \91\ Wisconsin Parties March 29, 2010 Comments at 6-7.
---------------------------------------------------------------------------

    65. Similarly, MidAmerican and PSEG state that the NOPR proposal to 
eliminate unsecured credit in FTR markets is misguided because it does 
not address valuation of FTRs. MidAmerican states that, if the 
Commission is intent on eliminating unsecured credit for FTRs, it 
should require each ISO/RTO to allow a market participant to offer the 
ISO/RTO a security interest in receivables from non-FTR market 
activities as an acceptable form of collateral for FTR market 
activity.\92\
---------------------------------------------------------------------------

    \92\ MidAmerican March 29, 2010 Comments at 7.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

    \94\ APPA March 29, 2010 Comments at 6.
---------------------------------------------------------------------------

    68. First Energy, EMCOS, IMEA, Midwest TDUs, NRECA, NYAPP, NCPA, 
Western, CPUC, MSCG, MidAmerican, PSEG, and SCE oppose the Commission's 
proposal to eliminate unsecured credit in the FTR markets. First Energy 
Service Company (First Energy) argues that defaults that occurred in 
the PJM market in December 2007 were not due to the use of unsecured 
credit, but rather the abuse of FTR markets.\95\ First Energy 
recommends that the Commission not eliminate unsecured credit, but 
instead use independent market monitors that are in place in each ISO/
RTO, in addition to the enforcement capabilities granted to the 
Commission in the Energy Policy Act of 2005, to ensure that no market 
manipulation is taking place.\96\ MidAmerican and the PSEG state that 
the Commission's proposal is misguided and should be abandoned because 
it fails to address the most important underlying issue with respect to 
FTRs, which is one of valuation.\97\ In addition, Midwest TDUs, NRECA, 
NYAPP, and NCPA state that the elimination of unsecured credit for FTRs 
could create unnecessary collateral obligations on LSEs.\98\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    69. Some parties such as Northern Indiana Public Service Company

[[Page 65950]]

(NIPSCO), and Xcel Energy Services (Xcel) did not oppose elimination of 
unsecured credit for FTR markets per se. NIPSCO and Xcel suggested that 
a stakeholder process develop an unsecured credit policy appropriate to 
each ISO/RTO.\99\
---------------------------------------------------------------------------

    \99\ NIPSCO March 29, 2010 Comments at 6; Xcel March 29, 2010 
Comments at 12.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    71. For example, PJM suffered a significant default in December 
2007 in its FTR market \102\ and moved to eliminate the use of 
unsecured credit in that market due to its risk.\103\ That default 
illustrates the unique risk of FTRs. Given a change in market 
conditions, a set of FTR positions became highly unprofitable. Because 
FTR obligations cannot be terminated prior to the expiration of the 
contract, from one month to several years, losses can mount to the 
point that the FTR holder goes bankrupt.
---------------------------------------------------------------------------

    \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).
    \103\ PJM Interconnection, L.L.C., 127 FERC ] 61,017 at P 8, 36.
---------------------------------------------------------------------------

    72. It is difficult to quantify, and therefore limit, the risks 
inherent in FTR markets, as evidence by the substantial difference 
between FTR auction values and realized day ahead congestion value 
experienced over the past few years.\104\ For instance, the outage of a 
transformer at a key node in a network system during a peak season can 
have enormous financial consequences. Such an outage may be prolonged 
because replacement parts are expensive and not standardized, and thus 
not likely to be readily available. Under such circumstances, FTRs that 
had been ``prevailing flow'' or ``in the money'' may suddenly be 
counter-flow during an entire peak season or longer with costs that 
continue to widen depending on usage, flows, temperature and other 
factors. Because FTR market participants are all aware of large 
transmission events affecting FTR values, an FTR that is suddenly ``out 
of the money'' will be difficult to sell or liquidate. Thus the owner 
can be stuck with a financial position that continues to be a burden 
and that could force a large default. While elimination of unsecured 
credit may not necessarily have prevented previous defaults, requiring 
collateral to support all FTR transactions, rather than continued 
reliance on unsecured credit, will reduce the risk, and resulting 
costs, of defaults that are mutualized across all market participants.
---------------------------------------------------------------------------

    \104\ In 2008, dramatic changes in fuel prices at mid-year led 
to FTR values that differed dramatically from realized day-ahead 
congestion values. Division of Market Oversight, Federal Energy 
Regulatory Comm'n, 2008 State of the Markets Report at 18 (2009), 
available at http://www.ferc.gov/market-oversight/st-mkt-ovr/2008-
som-final.pdf. In 2009, changes in demand similarly led to 
divergence of FTR values and day-ahead congestion values. Division 
of Market Oversight, Federal Energy Regulatory Comm'n, 2009 State of 
the Markets Report at 20 (April 15, 2010), available at http://
www.ferc.gov/market-oversight/st-mkt-ovr/som-rpt-2009.pdf.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \105\ PJM Interconnection, L.L.C., 131 FERC ] 61,017 at P 31-34, 
order on reh'g, 132 FERC ] 61,180 (2010).
---------------------------------------------------------------------------

    74. As for those that argue against a uniform, nationwide 
prohibition on the use of unsecured credit in FTR markets, the 
Commission notes that there has been no evidence to suggest that the 
generation mix or transmission system of any particular ISO or RTO is 
inherently unique in its physical performance or equipment that would 
allow it to avoid the risks discussed above. In response to those that 
argue that the nature of the participants and their business model 
should exempt those participants from this aspect of the Final Rule, 
the Commission addresses this issue below.
    75. Thus, the Commission directs each ISO and RTO to submit a 
compliance filing that includes tariff revisions to eliminate the use 
of unsecured credit in its FTR, or FTR-equivalent, markets. This 
compliance filing must be submitted by June 30, 2011, and the tariff 
revisions will take effect October 1, 2011.
    76. The Commission acknowledges the parties that suggest that 
valuation of FTRs is important to protecting against the risk to 
participants associated with possible defaults. While the Commission 
agrees that ISOs and RTOs may face challenges in valuing FTRs, those 
comments are beyond the scope of this rulemaking proceeding.
    77. The Commission disagrees with commenters that assert that LSEs 
using FTRs to hedge for congestion should be exempt from the 
prohibition on the use of unsecured credit in the FTR market. Even an 
LSE with generation backing the FTR may encounter changes in the system 
that outstrip (perhaps substantially outstrip) the hedge, as in the 
transmission outage example used above. Similarly, municipal utilities 
that hold an FTR position can find that their position is ``out of the 
money'' due to an unforeseen, but large, transmission outage. The 
Commission also notes that low risk activities may be subject to lower 
security and collateral requirements for FTR positions. Thus, if LSEs, 
municipal utilities and other entities are engaged in ``low-risk'' 
transactions in the FTR markets, then this lower risk will be reflected 
in the credit analysis done by the market administrator in setting 
security and collateral requirements for their transactions in the FTR 
market, in contrast to higher requirements that may be established for 
those engaged in 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

[[Page 65951]]

FTR markets. This would serve to have the effect of ``loosening'' 
credit in an area where the Commission desires to see less risk.
    79. Additionally, the Final Rule does not provide exemptions for 
holders of ``fixed price TCCs,'' or other products, from the 
prohibition on the use of unsecured credit in this market as they may 
vary in value despite being called ``fixed price.''

D. Ability To Offset Market Obligations

    80. In order to help market participants manage their capital as 
efficiently as possible, market participants who are buying and selling 
energy and other products to and from the organized wholesale electric 
markets seek to net those transactions against each other for the 
purpose of determining the collateral requirement, thereby reducing the 
amount of collateral that a market participant must hold with the ISO/
RTO. In this way, the ISO/RTO can administer the market, while imposing 
fewer demands on the limited capital of its participants.
    81. However, if a market participant files for bankruptcy 
protection, it may assert that the ability of the ISO/RTO to offset 
accounts receivable against accounts payable is not valid and seek a 
claim to amounts owed to the market participant by the ISO/RTO. To 
ensure that ISOs/RTOs are not left owing the market participant without 
the ability to net amounts owed by the market participant, there must 
be an adequate legal basis to protect the ISOs/RTOs in the bankruptcy 
context.
    82. This concern provided the basis for the Commission's proposal 
in the NOPR to clarify the ISO's/RTO's legal status to take title to 
transactions, thereby becoming the central counterparty for 
transactions in an effort to establish mutuality in the transactions as 
legal support for set-off in bankruptcy.
1. Comments
    83. PJM supports the Commission's approach. Besides providing 
certainty, PJM argues that credit clearing solutions could provide 
attractive opportunities to RTO market participants to optimize the 
credit value of off-setting the positions that these companies hold in 
different market or trading environments, including across several 
RTOs.\106\ In addition, PJM argues that the Commission's approach is 
not without precedent. In support, it notes that Elexon, the company 
that serves the balancing and settlement function in the United 
Kingdom, created a 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 a forward contract 
merchant and/or swap participant within the meaning of the Bankruptcy 
Code.\107\
---------------------------------------------------------------------------

    \106\ PJM March 29, 2010 Comments at 18-19.
    \107\ Id. at 10-11.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

    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.
---------------------------------------------------------------------------

    \109\ Midwest ISO has adopted an approach similar to this, 
discussed below.
---------------------------------------------------------------------------

    86. CCRO explains that it reviewed this issue through a designated 
subcommittee of member companies that conducted a comprehensive study 
on netting. It asserts that it is emerging ``best practice'' in intra-
ISO netting for an ISO to create or designate a central counterparty 
entity through which market participants may execute transactions. CCRO 
encourages the Commission to formulate policy and regulations which 
enable cost-effective implementation of this best practice. In 
addition, it encourages the Commission to support innovations in 
netting consistent with emerging best practice.
    87. Many commenters voice strong views in opposition to this 
proposal. CAISO and Midwest ISO note that the argument that 
transactions between a market participant and ISO/RTO are not mutual, 
and therefore cannot be set-off in bankruptcy, has only been raised 
once and that there may be reasons why the argument has not been raised 
again.\110\ They encourage consideration of less burdensome 
alternatives.
---------------------------------------------------------------------------

    \110\ In the NOPR, the Commission cited the Mirant bankruptcy 
and resulting default in the CAISO market as support for its 
proposal that ISOs/RTOs clarify their ability to offset market 
obligations. NOPR, FERC Stats. & Regs. ] 32,651 at P 24 (2010). 
Mirant argued in bankruptcy that CAISO would not be able to show the 
mutuality required to establish a right of setoff under section 553 
of the bankruptcy code. Memorandum by Wachtell, Lipton, Rosen & Katz 
to PJM regarding Setoffs and Credit Risk of PJM in Member 
Bankruptcies at 10-11 (Mar. 17, 2008) (found on Sept. 7, 2010 at 
http://www.pjm.com/~/media/committees-groups/committees/crmsc/
20080423/20080423-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.
---------------------------------------------------------------------------

    88. Other commenters question whether, absent steps taken in this 
rulemaking, there will really be a problem in upholding netting in the 
bankruptcy context. For instance, Shell Energy urges the Commission to 
more clearly define the problem and that a speculative problem is not 
an adequate basis to change the fundamental nature and role of an 
RTO.\111\ NRECA also asserts that the bankruptcy set-off risk to RTOs 
is largely hypothetical. MidAmerican Energy concurs with the joint 
comments of CAISO and Midwest ISO and asserts that the Mirant 
bankruptcy proceeding only marginally supports the proposition that an 
ISO or RTO may not be able to offset market participant obligations due 
to lack of mutuality.\112\
---------------------------------------------------------------------------

    \111\ Shell Energy March 29, 2010 Comments at 8.
    \112\ MidAmerican Energy March 29, 2010 Comments at 7-8.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \113\ Dominion March 29, 2010 Comments at 7-10.
    \114\ NYISO March 29, 2010 Comments at 15.
---------------------------------------------------------------------------

    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

[[Page 65952]]

believes that a bankruptcy court may, for policy reasons, defer to the 
Commission-approved tariff provisions of the ISO or RTO, or uphold ISO 
or RTO netting under the doctrine of recoupment,\115\ thereby 
circumventing a challenge for mutuality.\116\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \117\ Six Cities March 29, 2010 Comments at 6.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \118\ Citigroup March 29, 2010 Comments at 5.
    \119\ OMS March 16, 2010 Comments at 4-5.
---------------------------------------------------------------------------

2. Technical Conference
    94. The Commission held a technical conference to delve further 
into the issues raised by its proposal. The technical conference 
provided additional evidence on the ISOs and RTOs ability to net 
obligations and conduct setoff in the bankruptcy context. Mutuality was 
identified by several participants as important in allowing the ISOs 
and RTOs to perform this vital function, who asserted that mutuality 
was most easily achieved by the market administrator ``taking title'' 
or being the buyer to all sellers and seller to all buyers in all 
transactions in the market. Mr. Duane from PJM supported the 
Commission's proposal by stating: ``* * * the obvious and direct way to 
establish mutuality is simply to be a contract party to the 
transactions that you're setting up.'' \120\ Mr. Duane further stated: 
``I would regard the Commission's initiatives here as overdue'' and 
``the proposal here would remove a real disability that is a cloud over 
the enforcement of a broad set of rights that the RTOs have in outside 
forums, particularly beyond this Commission.'' \121\ According to Mr. 
Novikoff a ``best practice'' is ``to create mutuality by using a 
central counterparty and have that counterparty deal with all of the 
participants.'' \122\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    95. However, the Midwest ISO participant and the CAISO participant 
represented two different ways in which their organizations sought to 
deal with the issue, as opposed to the PJM proposal to change its 
tariff to allow an entity to explicitly take title and act as the 
central counterparty to achieve mutuality.
    96. At the technical conference, Mr. Holstein of Midwest ISO 
discussed the ``first short-pay, then uplift'' system used by Midwest 
ISO, stating that it works well and is revenue neutral in all 
transactions. Mr. Holstein stated that, if a market participant doesn't 
pay a charge that it owes, which is the net charge of the invoice, 
Midwest ISO short-pays the other market participants who are net-owed 
funds in that billing cycle, thus remaining revenue neutral for that 
billing cycle. Midwest ISO later makes up the difference by 
``uplifting'' the default to all market participants, that is, charging 
extra in the next billing cycle and redistributing the proceeds to 
those who were initially short-paid.\123\ Further, any party in Midwest 
ISO who wishes to net their obligations across its various markets 
(e.g., real time, day ahead, reserves, etc.) must provide Midwest ISO a 
security interest in these transactions. By doing this, Midwest ISO 
asserts that it is able to safely set credit exposure to a net, rather 
than a gross, obligation. Midwest ISO stated that ten percent of its 
market participants grant Midwest ISO a security interest, but certain 
public power entities are not able to use that approach.\124\ During 
the technical conference, participants noted the difficulties raised by 
using the security interest approach given that many lending agreements 
prohibit granting liens and some entities, such as municipalities, 
cannot engage in such practices.\125\ For these reasons stakeholders in 
Midwest ISO decided against mandatory requirements of security interest 
and opted for voluntary use of security interest.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    97. Mr. Daniel Shonkwiler of CAISO did not perceive a potential 
inability to offset market participants' claims and obligations as a 
risk, because CAISO's ordinary monthly settlements involve net 
invoices. Under CAISO's tariff, CAISO asserts that market participants 
only have the right to receive the net payment from CAISO for market 
sales, with no competing claims and obligations. CAISO indicates that a 
legal issue arises where a market participant fails to pay an invoice, 
but in a subsequent month, has a payment due back to it. In such a 
situation, CAISO states that its tariff allows it to recoup that later 
payment to pay the previous month's default. CAISO does not see a 
material risk because it does not assume a right to set-off when it is 
calculating the amount of financial security required. CAISO further 
states that its market is not at risk because it ensures that its 
market participants are adequately secured; many market participants 
are exclusively buyers or sellers, and thus netting their invoices 
would not reduce their exposure; litigating the issue would be so 
expensive as not to be worthwhile for a market participant in 
bankruptcy; and bankruptcy is rare in the CAISO

[[Page 65953]]

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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    98. The Commission also invited parties to submit further comment 
in response to the issues discussed in the technical conference.
3. Comments Submitted After the Technical Conference
    99. Several commenters assert that it is unlikely that a bankruptcy 
court would refuse an ISO/RTO's netting a market participant's 
obligations and therefore the Commission's concern does not justify the 
Commission's central counterparty proposal.\128\ Dominion states that 
CAISO has identified a number of practical reasons why the risk is 
minimal, such as that many market participants are unlikely to be in a 
position to use setoff because they are not both a buyer and seller in 
a given market. Dominion and SPP state that most market participants 
that want to continue to operate post-bankruptcy require transmission 
service and therefore will work with the ISO/RTO during bankruptcy 
proceedings. According to Midwest ISO, only an estimated 20 percent of 
its market participants are not dependent on transmission service, and 
thus do not net any transactions, and potentially would challenge the 
ISO's/RTO's ability to off-set. NYISO believes that its credit exposure 
is limited because most market participants in New York are not both 
buyers and sellers of energy in NYISO-administered markets.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    100. CCRO acknowledges that a market participant going into 
bankruptcy and challenging the ISO's/RTO's ability to net transactions 
is a low probability event, but it argues that the Commission cannot 
ignore such potentially high risk events. However, CAISO believes that 
the Commission needs additional evidence regarding the scope of the 
risk. CAISO suggests that the Commission first determine the number of 
market participants that likely would challenge set-off and then gather 
historical data about the difference between their net position and 
gross credits. NYISO also questions the scope of the risk, and asserts 
that it would have sufficient collateral available to recover the 
market participant's payment obligations to the NYISO because it 
calculates distinct credit requirements for each of its markets without 
assuming that it will be able to net across markets in a bankruptcy 
proceeding. NYISO also asserts that its tariff allows it to draw from 
its pre-funded working capital fund to facilitate timely payment to 
market participants and maintain the liquidity of the NYISO-
administered markets.
    101. Many commenters argue that the central counterparty approach 
does not definitively eliminate the risk that a bankruptcy court would 
refuse an ISO/RTO's netting obligations between the ISO/RTO and the 
debtor market participant. For instance, Eastern Massachusetts, 
Dominion and NYISO believe that a bankruptcy court that is hostile to 
set-off would question whether the ISO/RTO is the central counterparty 
in form only and not substance. NYISO explains that taking title is 
just one factor that a bankruptcy court may consider in determining 
whether there is mutuality between the ISO/RTO and the market 
participant. NYISO points out that under PJM's proposal, PJM is only 
obligated to pay market sellers to the extent of its collections from 
market buyers. Thus, NYISO argues that PJM may not truly be taking on 
the debt obligation for market purchases, but rather be acting as an 
agent for many different buyers. Although NYISO acknowledges that this 
argument is unlikely to succeed, it demonstrates that the risk is not 
eliminated. In addition, Dominion points to Midwest ISO's argument that 
the central counterparty model does not defend against a challenge 
based on the absence of mutuality in netting across commodities and 
services. However, bankruptcy counsel noted that there would have to be 
a major change in case law for a challenge to an identified central 
counterparty to be successfully upheld regarding its ability to set-off 
in a bankruptcy.\129\
---------------------------------------------------------------------------

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

    102. Numerous commenters oppose the central counterparty proposal 
because they believe that it will require the ISOs/RTOs to expend 
significant resources to implement it and may have negative 
consequences for the ISOs/RTOs and their market participants. According 
to Dominion, EPSA, Shell Energy, and SPP, the proposal is not a 
clarification in status, but instead is a radical departure from the 
current business model used for ISO/RTO transactions. Shell Energy 
believes that, as a result of the clarification, existing ISOs/RTOs 
will be administrators only and the new central counterparty will be a 
new public utility that should be treated similar to other public 
utilities. Thus, Shell Energy argues that implementing central 
counterparty status will require a radical restructuring of ISOs/RTOs.
    103. As for potential consequences and impacts on the ISOs/RTOs, 
Constellation cites Midwest ISO's Chief Financial Officer's comment 
that if an ISO/RTO is the central counterparty to energy market 
transactions, then its revenue neutrality may be jeopardized and 
liquidity and insolvency risk is introduced to the market.\130\ 
Similarly, EPSA states that Midwest ISO believes that it would be 
obligated to pay for defaults in the event other parties to the 
transaction could not pay, and that an event like this potentially 
could bankrupt the ISO/RTO. Eastern Massachusetts highlights CAISO's 
comments regarding the potential for increased cost of credit used to 
fund market operations.
---------------------------------------------------------------------------

    \130\ Constellation June 8, 2010 Comments at 4.
---------------------------------------------------------------------------

    104. CAISO also states that, by becoming a central counterparty to 
transactions within its market, it could become a ``point of 
regulation'' under greenhouse gas regulatory schemes. CAISO states that 
the Air Resources Board of California is regulating greenhouse gas 
emissions which extend to electricity produced and/or consumed within 
California. CAISO is concerned that if it is required to take title to 
the transactions, it will be subject to greenhouse gas regulations with 
no ability to procure alternative, non-carbon intensive fuels in the 
power pool. In fact, CAISO states that such a construct could provide 
an incentive for electricity exporters into California to dump the 
energy onto CAISO's system prior to entering California, so the 
exporters would not be subject to the greenhouse gas regulations. CAISO 
further states that national clearing could take place without ISOs and 
RTOs becoming the counterparty to transactions within their 
markets.\131\
---------------------------------------------------------------------------

    \131\ CAISO July 23, 2010 Comments at 6.
---------------------------------------------------------------------------

    105. Dominion, NYISO, Shell Energy and SPP argue that the central 
counterparty model potentially exposes ISOs/RTOs to new requirements, 
risks

[[Page 65954]]

and costs associated with complying with generally acceptable 
accounting principles requirements, loss of legal status, 
indemnification, and tax liability. They also believe that there may be 
unintended consequences that could cause significant harm, such as the 
imposition of state and local sales taxes on ISOs/RTOs, implications 
regarding the independence of an ISO/RTO, regulatory uncertainty 
resulting from potential multi-agency jurisdictional oversight of ISOs/
RTOs, negative impacts on financing options, and increases in financing 
costs. In light of these uncertainties, Constellation argues that the 
Commission should develop a full record, particularly regarding the 
consequences for ISOs/RTOs.
    106. PG&E also believes that CAISO already is considering and 
implementing numerous changes and improvements to its tariffs and 
markets and therefore does not have sufficient time to undertake 
additional effort.
    107. Eastern Massachusetts argues that the central counterparty 
proposal could result in interference with the ability of eligible 
municipal market participants to continue existing tax exempt financing 
or to use such financing to expand productive assets. Although NEPOOL 
does not take a formal position in its comments, it also believes that 
the central counterparty proposal could have profound and unintended 
consequences on market participants. SPP is concerned that, if the 
ISOs/RTOs operate as clearinghouses, then market participants such as 
cooperatives or municipalities will be unable to meet credit 
requirements.
    108. CCRO generally supports the Commission's proposal and believes 
that any approved procedure should be standardized across the ISOs/RTOs 
to the extent practical. CCRO also encourages the Commission to adopt 
rules that do not deter the development of innovations that can further 
limit credit exposure, such as the advent of netting of transactions 
across all the ISOs/RTOs and the over-the-counter markets.
    109. Some commenters argue that there are less costly approaches 
that ISOs/RTOs can employ to address the Commission's concerns without 
adopting the central counterparty proposal.\132\
---------------------------------------------------------------------------

    \132\ CAISO June 8, 2010 Comments at 6-7.
---------------------------------------------------------------------------

    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 believes that Midwest ISO's 
approach is less costly and simpler to implement, it also believes it 
would require a long lead time to facilitate discussions between market 
participants and their lenders. SPP notes concerns with the security 
interest approach, because it may be difficult for most market 
participants to supply such a security interest due to existing 
financing arrangements and the burden of perfecting a security 
interest.
    113. Dominion argues that it may not be necessary to amend ISO/RTO 
tariffs because there are existing defenses of netting under the 
current ISO/RTO structure that moot the need for the NOPR proposal. For 
instance, SPP notes that a bankruptcy court may be hesitant to set 
aside a Commission-approved tariff that requires payment netting or 
set-off. Dominion points to Midwest ISO's and NYISO's comments that the 
tariff, which market participants agree to be bound by, satisfies the 
mutuality of party requirement.
    114. NYISO also argues that its existing tariff may provide 
sufficient protection in the event a market participant raises the 
mutuality argument. According to NYISO and SPP, the commercial 
relationship between ISOs/RTOs and their market participants is 
distinguishable from the typical scenarios in which parties have 
successfully challenged setoff rights in a bankruptcy proceeding. 
According to NYISO, the important distinction is that the net 
obligations are between NYISO and a specific debtor market participant 
directly and NYISO is acting in the same capacity on both sides of 
market transactions.
    115. As an alternative to seeking setoff in bankruptcy, CAISO, 
NYISO and SPP believe that a bankruptcy court likely would allow it to 
net obligations under the equitable defense of recoupment. According to 
NYISO, a bankruptcy court would likely uphold the NYISO's right to 
recoupment within each market because it would be inequitable for a 
market participant to benefit from its participation in a single market 
without also having to meet its obligations related to its transactions 
in that market.
4. Commission Determination
    116. Organized wholesale electric markets typically arrange for 
settlement and netting of transactions entered into between market 
participants and the market administrator, but do not take title to the 
underlying contract position of a participant at the time of 
settlement. The Commission is concerned that, if a market participant 
files for bankruptcy protection, it may argue against 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.
---------------------------------------------------------------------------

    \133\ Policy Statement, 109 FERC ] 61,186 at P 29.
---------------------------------------------------------------------------

    117. While the Commission, in response to what it still considers 
to be a legitimate concern, originally proposed requiring ISOs and RTOs 
to establish themselves as the central counterparty to transactions 
with market participants, the Commission is open to considering other 
solutions to this concern. The Commission directs each ISO and RTO to 
submit a compliance filing that includes tariff revisions to include 
one of the following options:
     Establish a central counterparty as discussed above.
     Require market participants to provide a security interest 
in their transactions in order to establish collateral requirements 
based on net exposure.

[[Page 65955]]

     Propose another alternative, which provides the same 
degree of protection as the two above-mentioned methods.
     Choose none of the three above alternatives, and instead 
establish credit requirements for market participants based on their 
gross obligations.
    118. This compliance filing must be submitted by June 30, 2011, 
with the tariff revisions to take effect October 1, 2011.
    119. Evidence put before the Commission has demonstrated the need 
for establishing better protection against loss due to bankruptcy of a 
market participant. Allowing netting without adequate protection could 
pose a risk to the ISO and RTO markets and particularly their 
participants who would be assessed any shortfall. The ability for an 
ISO or RTO to net amounts owed to and owed by a market participant that 
has filed for bankruptcy protection is not clear. At the technical 
conference, Mr. Novikoff testified that ``bankruptcy courts are quite 
hostile to setoff.'' \134\ The Commission also notes that a recent 
court decision affirmed a bankruptcy court's finding that, ``the 
mutuality required by Section 553, `cannot be supplied by a multi-party 
agreement contemplating a triangular setoff.' '' \135\ Our effort to 
limit the amount of unsecured credit extended in ISO and RTO is less 
meaningful if an ISO or RTO establishes a collateral requirement based 
on net exposure that can not withstand a challenge in bankruptcy court. 
As to the view that there is a low probability that a market 
participant will file for bankruptcy and then challenge an ISO's/RTO's 
ability to net, the Commission agrees with CFTC staff and the CCRO that 
that this low probability is balanced by a high cost to market 
participants and the stability of the market if it does occur.
---------------------------------------------------------------------------

    \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 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.
---------------------------------------------------------------------------

    120. While we continue to believe that the NOPR proposal provides a 
sound approach to this issue, we are open to considering other 
solutions. Two alternatives to the central counterparty solution were 
presented; one proposed by the CAISO and one proposed by Midwest ISO, 
described in more detail in the comment section above. The Commission 
is convinced that Midwest ISO's approach, in which market participants 
grant a security interest in their transactions to Midwest ISO, 
provides a basis for the ISO or RTO to net market obligations. A 
security interest is a form of collateral which provides certain 
protection in the bankruptcy context, but it may be unworkable under 
some lender agreements.\136\ The Commission notes that not all parties 
may be able to grant a security interest in their transactions, 
however, this method provides an alternative for ISOs and RTOs that 
wish to allow market participants to continue to net their 
transactions. However, the Commission is concerned that CAISO's method 
of ``net invoicing,'' which treats all events on a market participant's 
monthly invoice as one transaction, may not be adequate in the context 
of a bankruptcy.\137\ Because of the uncertainties about the viability 
of CAISO's theory under bankruptcy law, the Commission does not believe 
that market participants should be allowed to net their financial 
obligations based on CAISO's ``net invoicing'' solution.
---------------------------------------------------------------------------

    \136\ Id. at Tr. 84:5-25, 85:1-22 (Iskender H. Catto; Kirkland & 
Ellis on behalf of the Committee of Chief Risk Officers).
    \137\ Id. at Tr: 73:16-21 (May 11, 2010) (Mr. Harold Novikoff, 
Wachtell, Lipton, Rosen & Katz).
---------------------------------------------------------------------------

    121. Some participants have suggested that the Commission direct 
that all ISO/RTO tariffs have explicit language allowing these markets 
to perform netting and set-off to provide legal cover in bankruptcy. 
While RTOs and ISOs may propose such tariff language as an additional 
measure, the Commission believes that it is not sufficient protection 
to simply direct the ISOs and RTOs to include the ability to net in 
their tariff. Based on testimony cited above, the Commission is 
concerned that, if the issue were raised in bankruptcy court, the 
existence of a Commission-approved tariff, even with such language, may 
not persuade a bankruptcy court to allow the set-off of financial 
obligations between an ISO/RTO and a market participant who is in 
bankruptcy. For this reason, the Commission will require more than mere 
tariff language to ensure the right of an ISO/RTO to net in the 
bankruptcy context. In the absence of a central counterparty, security 
interest, or another method that provides the same degree of protection 
to support netting, the remaining solution is to establish credit 
requirements to gross market obligations rather than net obligations.
    122. Many parties also state that the Commission should not pursue 
the counterparty model due to tax and administrative costs. Given that 
ISOs and RTOs already function in ways similar to a central 
counterparty, it is not clear how it will lead to increased 
administrative costs.\138\ As to possible tax implications, no specific 
evidence has been presented showing that the central counterparty model 
will lead to increased tax obligations. However, we need not decide 
these points here, and RTOs and ISOs may consider these points in 
deciding how to comply with this Final Rule.
---------------------------------------------------------------------------

    \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.'')
---------------------------------------------------------------------------

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 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

[[Page 65956]]

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\
---------------------------------------------------------------------------

    \139\ J.P. Morgan Comments at 14 (referring to the Commodity 
Exchange Act definition of Eligible Contract Participant. 7 U.S.C. 
1a(12)). Examples of criteria-determined Eligible Contract 
Participants include financial institutions, insurance companies, 
mutual funds, and corporations with assets in excess of $10 million.
---------------------------------------------------------------------------

    127. APPA supports development of ISO/RTO rules that limit the 
activities of ``financial-only'' market participants, including maximum 
position and credit limits for financial-only ISO/RTO market 
participants and suggests a follow-on NOPR dealing specifically with 
these issues. NRECA suggests that ISOs/RTOs should be encouraged to 
develop minimum participation criteria for cooperative utilities that 
would be different than investor-owned utilities.
    128. Morgan Stanley agrees that certain risk management 
capabilities and minimum capital requirements be established but 
cautioned against making these criteria too onerous. Moreover, Morgan 
Stanley stated that criteria applied only to financial-only 
participants should be avoided. A similar argument was made by the 
Western Power Trading Forum (WPTF), which states that objective 
criteria should apply to all market participants. WPTF further states 
that, if the Commission seeks to ``enhance certainty and stability in 
the markets,'' then it should require each ISO/RTO to apply their 
credit policies to all market participants.
    129. Many parties, such as Detroit Edison, Direct Energy, PSEG and 
SCE, recommend that the stakeholder process should determine 
appropriate criteria in each ISO and RTO. On the other hand, Dominion 
asserts that the proper forum for establishing such criteria is the 
current rulemaking proceeding, and not the ``popular vote'' of market 
participants with competing interests in the stakeholder process.
    130. Other parties did not agree on the need for minimum 
criteria.\140\ Midwest TDUs suggest the Commission is not well 
positioned to design such criteria. The NYTOs argue the need for such 
criteria has not been established. Consumers Energy states that, as 
long as each RTO accurately determines creditworthiness, there is no 
need to further specify minimum criteria for participation. Financial 
Marketers argue that erecting barriers to market entry through the 
establishment of market participation criteria, such as minimum net 
worth or minimum size requirements, would be anticompetitive, unjust, 
and unreasonable.\141\
---------------------------------------------------------------------------

    \140\ Midwest TDUs, NYTOs, Consumers Energy, Wisconsin Parties 
and Financial Marketers.
    \141\ Financial Marketers March 29, 2010 Comments at 2-3.
---------------------------------------------------------------------------

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 ISO and RTO will need to consider the minimum 
criteria that are most applicable to its markets, this compliance 
filing must be submitted by June 30, 2011 and to take effect by October 
1, 2011.
    133. In taking this approach, the Commission is aware that 
stakeholder groups with competing interests may disagree on these 
criteria, and so the Commission will review proposed tariff language to 
ensure that it is just and reasonable and not unduly discriminatory. 
The Commission believes that such standards might address adequate 
capitalization, the ability to respond to ISO/RTO direction and 
expertise in risk management. The Commission directs that these 
criteria apply to all market participants rather than only certain 
participants.
    134. The Commission does not agree with the argument that minimum 
criteria are not necessary if ISOs and RTOs apply vigorous standards in 
determining the creditworthiness of each market participant. While an 
analysis of creditworthiness may capture whether the market participant 
has adequate capital, it may not capture other risks, such as whether 
the market participant has adequate expertise to transact in an ISO/RTO 
market. Moreover, the ISOs' and RTOs' ability to accurately assess a 
market participant's creditworthiness is not infallible, and this 
additional safeguard should not be unduly burdensome compared to the 
need to protect the stability of the organized markets.

F. Use of ``Material Adverse Change''

    135. Events in credit markets can change the fortunes of a 
participant very quickly.\142\ Consequently, risk management is not a 
static endeavor. Every market administrator needs to perform frequent 
risk analysis on its participants to ensure that existing collateral 
and creditworthiness standards are sufficient. Nevertheless, even with 
such scrutiny, events may transpire that require the market 
administrator to invoke a ``material adverse change'' clause to justify 
changing the risk assessment of a participant and requiring additional 
collateral.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    136. The Commission is concerned that ambiguity as to when an ISO 
or RTO may invoke a ``material adverse change'' clause could itself 
have damaging effects on a market administrator's ability to manage 
risk on behalf of all the participants. If a market administrator is 
concerned about when it may invoke a ``material adverse change'' 
clause, it could delay requests for collateral or orders for the 
cessation of a participant's right to transact, which could further 
endanger the other participants and, in extreme cases, the market 
function itself.
    137. In addition, material adverse change clauses need to be 
sufficiently forward-looking to allow market administrators to request 
additional collateral before a crisis starts. The Commission is 
concerned that any attempt to acquire additional collateral during or 
after a crisis has begun would either fail or destabilize the party 
asked to provide additional credit. Specifically, news that a market 
participant was unable to secure additional collateral could negatively 
affect the perception of the market participant's viability and 
potentially undermine confidence in an organized market's viability.
    138. The Commission therefore proposed in the NOPR to require ISOs

[[Page 65957]]

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.

    140. Hess states that the material adverse change clauses in the 
ISO/RTO tariffs must include non-exclusive illustrative lists of 
potential material change events, and require ISO/RTO credit officers 
to exercise caution prior to invoking the ``material adverse change'' 
clause.
    141. CFTC staff notes that it is critical for a market 
administrator to have the ability to call for additional collateral in 
unusual or unforeseen circumstances. Therefore, CFTC staff recommends 
either: (1) Removing any requirement for a market administrator to wait 
until a participant experiences a ``material adverse change'' in credit 
status before calling for additional collateral to support FTR 
positions; or (2) permit a market administrator to define ``material 
adverse change'' in a manner that would allow a market administrator to 
have broad discretion in calling for additional collateral to support 
FTR positions.
    142. CPUC, Dynegy, and SCE state that they support clear guidelines 
on the definition of ``material adverse change.'' CPUC and SCE argue 
that CAISO's current tariff provision specifying under what 
circumstances a market administrator may invoke a ``material adverse 
change'' clause to require additional collateral is adequate.\144\ 
Therefore, CPUC requests that the Commission adopt guidelines that 
would allow the CAISO to maintain the status quo. Shell Energy also 
states that the Commission should propose a generic material adverse 
change provision, then allow the ISOs and RTOs to work with 
stakeholders to produce an illustrative list of instances where 
material adverse change provisions would or should be triggered and to 
file that language with the Commission. However, even then, the tariff 
language should still allow a market administrator to act in the event 
that special circumstances arise.
---------------------------------------------------------------------------

    \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 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.
---------------------------------------------------------------------------

    143. EEI states that the ISO/RTO should be able to explain its 
procedures and provide the types of circumstances under which it would 
invoke the ``material adverse change'' clause that requires a market 
participant to post collateral within two days. EEI also states that 
the procedures that the ISO/RTO employs should, at a minimum, provide 
written notice of the reasons for its action within thirty days and an 
opportunity to appeal to the Chief Executive Officer of the ISO/RTO. 
Additionally, EEI states that the Commission should require the ISOs/
RTOs to incorporate in their tariffs examples of the conditions under 
which they will invoke a ``material adverse change'' clause with the 
explicit requirement that the ISO/RTO put the rationale for its 
determination in writing and allow the market participant an 
opportunity for an appeal.
    144. MidAmerican states that it is not practical nor prudent to 
require a comprehensive and all-inclusive list of circumstances in 
which an ISO/RTO may invoke a material adverse change, but the required 
justification provided by an ISO/RTO for invoking a material adverse 
change provision should include reasonable, objective evidence of the 
occurrence of an identifiable event or condition with respect to the 
affected market participant. MidAmerican also states that the 
Commission should require each ISO/RTO to specify a reasonable process 
for resolving any disagreement between the ISO/RTO and market 
participants with respect to the impact of any identified event or 
condition on the ability of the market participant to continue as a 
going concern or otherwise honor its obligations to the ISO/RTO.
    145. APPA proposes a committee on ``material adverse changes,'' 
that is, a balanced advisory group of RTO employees dealing with credit 
issues and their counterparts from representatives of various types of 
RTO market participants. This group would be responsible for developing 
``model'' protocols, to be the subject of a subsequent NOPR, which 
would guide an RTO in invoking the material adverse change provisions 
of the credit provisions of its tariff and business practices.\145\
---------------------------------------------------------------------------

    \145\ APPA March 29, 2010 Comments at 35.
---------------------------------------------------------------------------

    146. Because ``material adverse change'' is ambiguous and could be 
inconsistently and inappropriately applied, PG&E recommends that it not 
be incorporated into ISO/RTO tariff language. However, if the 
Commission does incorporate such language, PG&E recommends an 
initiative to develop clearer definitions. In addition, PG&E states 
that invocation of a ``material adverse change'' clause should be 
selective and limited to only adverse conditions due to a participant's 
financial strength or ability to meet its contractual obligations, but 
not the requirements of the customers and/or the regulators.
2. Commission Determination
    147. We adopt the NOPR proposal to require ISOs and RTOs to specify 
in their tariffs the conditions under which they will request 
additional collateral due to a material adverse change. However, we are 
persuaded by commenters that this list should not be exhaustive and the 
tariff provisions should allow the ISOs and RTOs to use their 
discretion to request additional collateral in response to unusual or 
unforeseen circumstances. We are also persuaded that a market 
participant should receive a written explanation explaining the 
invocation of the material adverse change clause.
    148. While market participants are generally familiar with 
``material adverse change'' clauses, a market administrator's right to 
invoke such a

[[Page 65958]]

clause must be clarified in order to avoid any confusion, particularly 
during times of market duress, as to when such a clause may be invoked. 
Specifically, the Commission is concerned that a market participant in 
financial straits could exploit ambiguity as to when a market 
administrator may invoke a ``material adverse change,'' or a market 
administrator may be uncertain as to when it may invoke a ``material 
adverse change,'' and so delay, or even prevent entirely, actions that 
would insulate the market from unnecessary damage.
    149. The Commission therefore directs each ISO and RTO to submit a 
compliance filing that includes tariff revisions to establish and 
clarify when a market administrator may invoke a ``material adverse 
change'' clause to compel a market participant to post additional 
collateral, cease one or more transactions, or take other measures to 
restore confidence in the participant's ability to safely transact. The 
tariff revisions should state examples of which circumstances entitle a 
market administrator to invoke a ``material adverse change'' clause, 
but this list should be illustrative, rather than exhaustive. The tools 
used to determine ``material adverse change'' should be sufficiently 
forward looking to allow the market administrator to take action prior 
to any adverse effect on the market, but provide the market 
participants with notice as to what events could trigger a collateral 
call or a change in activity in the market. We believe that the 
language proposed by the IRC is a good start, but note that it 
generally includes items that potentially lag the events that 
constitute a material adverse change. For instance, credit ratings tend 
to change slowly. As discussed above, the several ISOs have noted that 
they were concerned about large, destabilizing defaults from 
investment-grade companies. Other criteria, like large changes in the 
price for a collateralized debt security, are potentially more forward 
looking and would allow the ISO or RTO to request collateral before a 
market participant is in financial distress.
    150. The Commission agrees with those parties that suggest that it 
would be short-sighted to limit the discretion of the market 
administrator to only those specified instances when it could invoke a 
``material adverse change'' clause to compel certain actions. 
Experience has demonstrated that unforeseen circumstances can arise, 
which will require action to protect the markets from ongoing 
disruption. We are not adopting a pro forma list ourselves, but 
allowing the ISOs and RTOs to develop their own ``material adverse 
change'' clauses. Nevertheless the compliance filing related to this 
directive must be submitted by June 30, 2011 to take effect no later 
that October 1, 2011.
    151. The Commission is also sensitive to the need for a record of 
the market administrator's actions when exercising this discretion. 
Therefore, the Commission directs the ISOs and RTOs to provide 
reasonable advance notice \146\ to a market participant, when feasible, 
when the ISOs and RTOs are compelled to invoke a ``material adverse 
change'' clause. The notification should be in writing, contain the 
reasoning behind invocation of the ``material adverse change'' clause, 
and be signed by a person with authority to represent the ISO/RTO in 
such actions. This will allow for a timely remedy for continued market 
participation, but also provide for a possible dispute to be resolved 
after the fact.
---------------------------------------------------------------------------

    \146\ We will leave to the discretion of the individual ISOs and 
RTOs how much notice may be reasonable in particular circumstances.
---------------------------------------------------------------------------

G. Grace Period to ``Cure'' Collateral Posting

    152. Under certain circumstances, a market administrator may 
require the market participant to post additional collateral in order 
to continue to transact. Currently the organized wholesale electric 
markets vary as to the amount of time they allow a market participant 
to post additional collateral to ``cure'' its position. NYISO and PJM 
allow two days to provide additional collateral.\147\ Midwest ISO 
allows two to three days (the market participant gets an additional 
business day if notice of invocation of the material adverse change 
clause occurs after noon Eastern Daylight Time).\148\ CAISO and SPP 
allow three days.\149\ In general, ISO-NE requires almost immediate 
remedy from market participants who exceed all of the credit tests. By 
10 a.m. the next morning, all typical market functions of the market 
participant are suspended (some functions are lost immediately). In the 
event that this credit test failure was caused by the market 
participant or a guarantor dropping a single rating grade or from a 
bank issuing a letter of credit being downgraded, however, it may have 
five to ten days to ``cure'' this situation.\150\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    153. Establishing a brief but standard time period to ``cure'' a 
collateral posting will bring certainty to the market which can 
stabilize the market and its prices, while controlling the risk and 
costs of a default. However, the Commission is aware of the importance 
of the continued reliable delivery of electricity and that some market 
participants have ``provider of last resort'' obligations. 
Consequently, the Commission attempted to strike a balance that allows 
an entity who is required to post additional collateral a reasonable 
chance to find a provider of capital--a bank or similar creditworthy 
institution--to assist in maintaining that participant's activity, 
while at the same time not posing a risk to the market. The Commission 
therefore proposed in the NOPR a two-day time limit for entities to 
post additional collateral and sought comment on the appropriate time 
limit.
1. Comments
    154. The IRC agrees that establishing an outer limit on the amount 
of time granted for the posting of additional collateral will promote 
confidence in the ISO/RTO markets by limiting default exposure and by 
shortening collateral posting periods.\151\ The Joint Commenters, EEI, 
PSEG, and Wisconsin Parties support standardization across the ISOs/
RTOs, while NRECA, NIPSCO, and SCE support allowing the ISOs/RTOs and 
their stakeholders discretion to decide whether to revise their 
tariffs' time periods for curing collateral calls. NIPSCO claims that 
the Commission and ISOs/RTOs should be mindful that shortening the time 
a market participant has to react to margin calls could result in a 
higher rate of defaults.\152\ APPA believes the time period to cure 
collateral calls should be referred to the working group APPA 
recommends for Material Adverse Changes.\153\ NEPOOL argues that the 
ISO-NE Financial Assurance Policy \154\ currently provides a suitable 
level of protection and urges that the Commission not issue any final

[[Page 65959]]

rule that would require changes to that policy.\155\
---------------------------------------------------------------------------

    \151\ IRC March 29, 2010 Comments at 9.
    \152\ NIPSCO March 29, 2010 Comments at 9.
    \153\ APPA March 29, 2010 Comments at 33-35.
    \154\ 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, and provides the conditions under which the ISO will conduct 
business in a non-discriminatory way so as to avoid the possibility 
of failure of payment and to deal with market participants who are 
delinquent. ISO-NE Tariff, Section I, Exhibit IA.
    \155\ NEPOOL March 29, 2010 Comments at 20.
---------------------------------------------------------------------------

    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\ 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.
---------------------------------------------------------------------------

    156. Regarding the appropriate time period to post additional 
collateral, several parties from California \159\ support keeping the 
current CAISO rule of a three-day cure period. These parties express 
concerns about the burdens of a shorter time period. For example, Six 
Cities argue that the internal review and authorization processes 
applicable to collateral commitments for Six Cities would make it 
difficult to post additional collateral within two business days, so 
the current three-day period should remain in effect, at least for 
governmental entities.\160\
---------------------------------------------------------------------------

    \159\ CAISO, NCPA, CPUC, the Six Cities, and PG&E.
    \160\ Six Cities March 29, 2010 Comments at 6-7.
---------------------------------------------------------------------------

    157. Other parties, however, believe a two-day period to post 
additional collateral is more appropriate. Calpine requests that the 
Commission require ISOs and RTOs to adopt a standardized two-day cure 
period.\161\ DC Energy, Direct Energy, Dominion, and Dynegy all support 
a standardized two-day cure period across all ISOs/RTOs. Midwest ISO 
and NRECA support a two-day cure period. Midwest ISO states that it 
views this proposal as generally being a standard practice in wholesale 
electric markets.\162\ NRECA acknowledges that the standard financial 
industry practice allows two business days to post additional 
collateral after receipt of the demand, but the ISO/RTO stakeholder 
process is the best vehicle for addressing this on a regional 
basis.\163\ Morgan Stanley and the NYTOs find that the current two-day 
period is sufficient in PJM and NYISO, respectively.\164\ OMS, 
Consumers Energy, EPSA, FirstEnergy, Shell Energy, and CEI and 
MidAmerican state that two days is a reasonable amount of time to post 
additional collateral.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \165\ Midwest TDUs March 29, 2010 Comments at 20-21.
    \166\ J.P. Morgan March 26, 2010 Comments at 13.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

2. Commission Determination
    160. The Commission adopts the NOPR proposal to require each ISO 
and RTO to include in the credit provisions of its tariff language to 
limit the time period allowed to post additional collateral. In 
addition, we require each ISO and RTO to allow no more than two days to 
``cure'' a collateral call. The Commission directs each ISO and RTO to 
submit a compliance filing that includes tariff revisions to establish 
a two-day limit to post additional collateral due to invocation of a 
``material adverse change'' clause or other provision of an ISO/RTO 
tariff. This compliance filing must be submitted by June 30, 2011, and 
the tariff revisions will take effect October 1, 2011.
    161. The Commission recognizes the difficult position parties can 
find themselves in when additional collateral is required on short 
notice. Nevertheless, the time allowed for a ``cure'' needs to be short 
to minimize uncertainty as to a participant's ability to participate in 
the market, and to minimize the risk and costs of a default by a 
participant (which, as noted elsewhere, affects other participants). 
The Commission also understands the rationale presented by CFTC staff 
when they suggest that any period longer than a day can be hazardous to 
the market. We thus seek to strike a balance: to minimize the potential 
for market disruptions and the risk and costs of a default, while 
allowing participants sufficient time to obtain additional capital so 
that they can continue to participate in the market. The Commission is 
persuaded that a limit of no more than two days to cure a collateral 
call achieves the desired balance.
    162. Two days should be sufficient for a market participant which 
is called upon to ``cure'' to arrange reasonable capital requirements. 
In reaching this determination, we note that some of the ISO/RTO 
markets already have a two-day cure period, so it should not prove 
overly burdensome to mandate this standard for all markets.\169\ 
Additionally, commenters point out that a two-day limit is a standard 
financial industry practice.\170\
---------------------------------------------------------------------------

    \169\ See Midwest ISO March 29, 2010 Comments at 21.
    \170\ NRECA March 29, 2010 Comments at 19.
---------------------------------------------------------------------------

    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

[[Page 65960]]

rulemaking process--in order to obtain additional information to 
consider the question asked in the NOPR.
---------------------------------------------------------------------------

    \171\ NOPR, FERC Stats. & Regs. ] 32,651 at P 8.
---------------------------------------------------------------------------

    165. Based on, among other things, a review of comments, Commission 
experience, and our review of the historic and recent developments in 
the debt markets, the Commission determines that the credit practices 
in this Final Rule will apply to all market participants. In making 
this determination, the Commission is aware that ISOs and RTOs may, 
through their stakeholder processes, ask for specific exemptions based 
on their experience and appropriate supporting evidence, particularly 
for individual entities whose participation is such that a default 
would not risk significant market disruptions. The Commission, however, 
will not, at this time in this generic rulemaking, adopt any 
exemptions.

IV. Information Collection Statement

    166. The Office of Management and Budget's (OMB) regulations 
require approval of certain information collection requirements imposed 
by agency rules. Upon approval of a collection(s) of information, OMB 
will assign an OMB control number and an expiration date. Respondents 
subject to the filing requirements of a rule will not be penalized for 
failing to respond to these collections of information unless the 
collections of information display a valid OMB control number.
    167. This Final Rule amends the Commission's regulations pursuant 
to section 206 of the Federal Power Act, to reform credit practices of 
organized wholesale electric markets to limit potential future market 
disruptions. To accomplish this, the Commission requires RTOs and ISOs 
to adopt tariff revisions reflecting these credit reforms. Such filings 
would be made under Part 35 of the Commission's regulations. The 
information provided for under Part 35 is identified as FERC-516.
    168. Under section 3507(d) of the Paperwork Reduction Act of 
1995,\172\ the reporting requirements in this rulemaking will be 
submitted to OMB for review. In their notice of March 18, 2010, OMB 
took no action on the NOPR, instead deferring their approval until 
review of the Final Rule.
---------------------------------------------------------------------------

    \172\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    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:

----------------------------------------------------------------------------------------------------------------
                                              Number of         Number of         Hours per       Total annual
             Data collection                 respondents        responses         response            hours
----------------------------------------------------------------------------------------------------------------
FERC-516:
    Transmission Organizations with                      6                 1               100               600
     Organized Electricity Markets......
----------------------------------------------------------------------------------------------------------------

    Information Collection Costs: The Commission has projected the 
average annualized cost of all respondents to be the following:

600 hours @ $300 per hour = $180,000 for respondents. No capital costs 
are estimated to be incurred by respondents.

    Title: FERC-516, Electric Rate Schedule Tariff Filings.
    Action: Information Collection.
    OMB Control No: 1902-0096.
    Respondents: Businesses or other for profit and/or not-for-profit 
institutions.
    Necessity of the Information: The information from FERC-516 enables 
the Commission to exercise its wholesale electric power and 
transmission oversight responsibilities in accordance with the Federal 
Power Act. The Commission needs sufficient detail to make an informed 
and reasonable decision concerning the appropriate level of rates, and 
the appropriateness of non-rate terms and conditions, and to aid 
customers and other parties who may wish to challenge the rates, terms, 
and conditions proposed by the utility.
    170. This Final Rule amends the Commission's regulations to ensure 
that credit practices currently in place in organized wholesale 
electric markets reasonably protect consumers against the adverse 
effects of default. To promote confidence in the markets, the 
Commission believes it is appropriate to adopt specific requirements 
regarding credit practices for organized wholesale electric markets. 
These requirements include shortening of billing and settlement periods 
and reducing the amount of unsecured credit. The Commission believes 
these actions will enhance certainty and stability in the markets, and 
in turn, ensure that costs associated with market participant defaults 
do not result in unjust or unreasonable rates.
    171. Internal Review: The Commission has reviewed the requirements 
pertaining to organized wholesale electric markets and determined the 
proposed requirements are necessary to its responsibilities under 
section 206 of the Federal Power Act.
    172. These requirements conform to the Commission's plan for 
efficient information collection, communication and management within 
the energy industry. The Commission has assured itself, by means of 
internal review, that there is specific, objective support for the 
burden estimates associated with the information requirements.
    173. Interested persons may obtain information on this information 
collection by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, Attention: 
Ellen Brown, Office of the Executive Director, phone: (202) 502-8663, 
fax: (202) 273-0873, e-mail: DataClearance@ferc.gov.
    174. Comments concerning this information collection can be sent to 
the Office of Management and Budget, Office of Information and 
Regulatory Affairs, Washington, DC 20503 [Attention: Desk Officer for 
the Federal Energy Regulatory Commission, phone: (202) 395-4650, fax: 
(202) 395-7285].

V. Environmental Analysis

    175. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\173\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is

[[Page 65961]]

required for this Final Rule under Section 380.4(a)(15) of the 
Commission's regulations, which provides a categorical exemption for 
approval of actions under sections 205 and 206 of the FPA relating to 
rates and charges and terms and conditions for transmission or sales 
subject to the Commission's jurisdiction.\174\
---------------------------------------------------------------------------

    \173\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. 
] 30,783 (1987).
    \174\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    177. The RTOs and ISOs regulated by the Commission do not fall 
within the RFA's definition of small entity. In addition, the vast 
majority of market participants in RTOs and ISOs are, either alone or 
as part of larger corporate families, not small entities. And the 
protections proposed here will protect all market participants, 
including small market participants, by reducing risk by reducing the 
likelihood of defaults and minimizing the impact of any defaults.
    178. California Independent Service Operator Corp. is a nonprofit 
organization comprised of more than 90 electric transmission companies 
and generators operating in its markets and serving more than 30 
million customers.
    179. New York Independent System Operator, Inc. is a nonprofit 
organization that oversees wholesale electricity markets serving 19.2 
million customers. NYISO manages a 10,775-mile network of high-voltage 
lines.
    180. PJM Interconnection, L.L.C. is comprised of more than 450 
members including power generators, transmission owners, electricity 
distributors, power marketers and large industrial customers and 
serving 13 states and the District of Columbia.
    181. Southwest Power Pool, Inc. is comprised of 50 members serving 
4.5 million customers in eight states and has 52,301 miles of 
transmission lines.
    182. Midwest Independent Transmission System Operator, Inc. 
(Midwest ISO) is a non-profit organization with over 131,000 megawatts 
of installed generation. Midwest ISO has 93,600 miles of transmission 
lines and serves 15 states and one Canadian province.
    183. ISO New England Inc. is a regional transmission organization 
serving six states in New England. The system is comprised of more than 
8,000 miles of high voltage transmission lines and several hundred 
generating facilities of which more than 350 are under ISO-NE's direct 
control.
    184. Therefore, the Commission certifies that this Final Rule will 
not have a significant economic impact on a substantial number of small 
entities. As a result, no regulatory flexibility analysis is required. 
As discussed in Order No. 2000,\177\ in making this determination, the 
Commission is required to examine only the direct compliance costs that 
a rulemaking imposes upon small businesses. It is not required to 
consider indirect economic consequences, nor is it required to consider 
costs that an entity incurs voluntarily. This rulemaking does not 
impose significant compliance costs upon small entities; the RTOs and 
ISOs directly affected--in that they have to adopt new or revised 
tariff language--are not small entities. Further, as to entities 
indirectly affected, i.e., market participants, most of them are not 
small entities. And, in any event, as to all market participants large 
and small, as we explained in Order No. 2000, supra, they have a choice 
of whether to join an RTO and whether to be a market participant or 
not. Moreover, the Commission believes that, to the extent that the 
credit reforms required by this Final Rule indirectly may impose 
potentially higher costs on some entities in the short-term, these 
reforms will also protect the markets and their participants from 
unacceptable disruptions and resulting costly defaults.\178\ Thus, this 
rulemaking will not have a significant economic impact upon any small 
entities.
---------------------------------------------------------------------------

    \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)).
    \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.
---------------------------------------------------------------------------

VII. Document Availability

    185. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, 
Washington, DC 20426.
    186. From the Commission's Home Page on the Internet, this 
information is available in the Commission's document management 
system, eLibrary. The full text of this document is available on 
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or 
downloading. To access this document in eLibrary, type ``RM10-13'' in 
the docket number field.
    187. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours. For assistance, please contact 
FERC Online Support at 1-866-208-3676 (toll free) or 202-502-6652 (e-
mail at FERCOnlineSupport@FERC.gov), or the Public Reference Room at 
202-502-8371, TTY 202-502-8659 (e-mail at 
public.referenceroom@ferc.gov).

VIII. Effective Date and Congressional Notification

    188. This Final Rule will take effect November 26, 2010. The 
Commission has determined, with the concurrence of the Administrator of 
the Office of Information and Regulatory Affairs of OMB, that this rule 
is not a major rule within the meaning of section 251 of the Small 
Business Regulatory Enforcement Fairness Act of 1996.\179\ The 
Commission will submit this Final Rule to both Houses of Congress and 
the General Accountability Office.\180\
---------------------------------------------------------------------------

    \179\ See 5 U.S.C. 804(2).
    \180\ See 5 U.S.C. 801(a)(1)(A).
---------------------------------------------------------------------------

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

[[Page 65962]]

    By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

0
In consideration of the foregoing, the Commission amends part 35, 
Subchapter B, Chapter I, Title 18, Code of Federal Regulations, as 
follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
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.

0
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.

Sec.  35.45  Applicability.

    This subpart establishes credit practices for organized wholesale 
electric markets for the purpose of minimizing risk to market 
participants.

Sec.  35.46  Definitions.

    As used in this subpart:
    (a) Market Participant means an entity that qualifies as a Market 
Participant under Sec.  35.34.
    (b) Organized Wholesale Electric Market includes an independent 
system operator and a regional transmission organization.
    (c) Regional Transmission Organization means an entity that 
qualifies as a Regional Transmission Organization under 18 CFR 35.34.
    (d) Independent System Operator means an entity operating a 
transmission system and found by the Commission to be an Independent 
System Operator.

Sec.  35.47  Tariff provisions regarding credit practices in organized 
wholesale electric markets.

    Each organized wholesale electric market must have tariff 
provisions that:
    (a) Limit the amount of unsecured credit extended by an organized 
wholesale electric market to no more than:
    (1) $50 million for each market participant; and
    (2) $100 million for all entities within a corporate family.
    (b) Adopt a billing period of no more than seven days and allow a 
settlement period of no more than seven days.
    (c) Eliminate unsecured credit in financial transmission rights 
markets and equivalent markets.
    (d) Establish a single counterparty to all market participant 
transactions, or require each market participant in an organized 
wholesale electric market to grant a security interest to the organized 
wholesale electric market in the receivables of its transactions, or 
provide another method of supporting netting that provides a similar 
level of protection to the market and is approved by the Commission. In 
the alternative, the organized wholesale electric market shall not net 
market participants' transactions and must establish credit based on 
market participants' gross obligations.
    (e) Limit to no more than two days the time period provided to post 
additional collateral when additional collateral is requested by the 
organized wholesale electric market.
    (f) Require minimum participation criteria for market participants 
to be eligible to participate in the organized wholesale electric 
market.
    (g) Provide a list of examples of circumstances when a market 
administrator may invoke a ``material adverse change'' as a 
justification for requiring additional collateral; this list does not 
limit a market administrator's right to invoke such a clause in other 
circumstances.

    Note:  The following Appendix will not be published in the Code 
of Federal Regulations.

               Appendix List of Intervenors and Commenters
------------------------------------------------------------------------
                               Commenters
-------------------------------------------------------------------------
                     Acronym                               Name
------------------------------------------------------------------------
AMP.............................................  American Municipal
                                                   Power.
APPA............................................  American Public Power
                                                   Association.
Basin Electric..................................  Basin Electric Power
                                                   Cooperative.
BP Energy.......................................  BP Energy Company.
BPA.............................................  Bonneville Power
                                                   Administration.
CAISO...........................................  California Independent
                                                   System Operator
                                                   Corporation.
Calpine.........................................  Calpine Corporation.
CCRO............................................  Committee of Chief
                                                   Risk Officers.
CFTC staff......................................  Commodity Futures
                                                   Trading Commission.
Citigroup.......................................  Citigroup Energy Inc.
City of New York................................  City of New York.
Constellation/NRG...............................  Constellation
                                                   Companies and NRG
                                                   Companies.
CPUC............................................  California Public
                                                   Utility Commission.
DC Energy.......................................  DC Energy, LLC.
Detroit Edison..................................  Detroit Edison
                                                   Company.
Direct Energy...................................  Direct Energy
                                                   Services, LLC.
DMEC............................................  Delaware Municipal
                                                   Electric Corporation,
                                                   Inc.
Dominion........................................  Dominion Resources
                                                   Services Inc.
Duke............................................  Duke Energy
                                                   Corporation.
Dynegy..........................................  Dynegy Power
                                                   Marketing, Inc.
East Texas Electric Cooperatives................  East Texas Electric
                                                   Cooperatives.
EEI.............................................  Edison Electric
                                                   Institute.
EMCOS...........................................  Eastern Massachusetts
                                                   Consumer-Owned
                                                   Systems, including
                                                   Braintree Electric
                                                   Light Department,
                                                   Concord Municipal
                                                   Light Plant, Hingham
                                                   Municipal Lighting
                                                   Plant, Reading
                                                   Municipal Light
                                                   Department, Taunton
                                                   Municipal Lighting
                                                   Plan, Wellesley
                                                   Municipal Light
                                                   Plant.
EPSA............................................  Electric Power Supply
                                                   Association.
Financial Marketers.............................  Jump Power, LLC;
                                                   Energy Endeavors LP;
                                                   Big Bog Energy, LP;
                                                   Silverado Energy LP;
                                                   Gotham Energy
                                                   Marketing LP;
                                                   Rockpile Energy LP;
                                                   Coaltrain Energy LP;
                                                   Longhorn Energy LP;
                                                   MET MA, LLC; Solios
                                                   Power, LLC; and JPTC,
                                                   LLC.

[[Page 65963]]

First Energy....................................  First Energy Service
                                                   Company, including
                                                   American Transmission
                                                   Systems, Inc., The
                                                   Cleveland Electric
                                                   Illuminating Company,
                                                   Jersey Central Power
                                                   & Light Company,
                                                   Pennsylvania Power
                                                   Company, The Toledo
                                                   Edison Company, and
                                                   FirstEnergy Solutions
                                                   Corp.
Hess............................................  Hess Corporation.
IMEA............................................  Illinois Municipal
                                                   Electric Agency.
IPPNY...........................................  Independent Power
                                                   Producers of New
                                                   York.
IRC.............................................  ISO/RTO Council.
ISO-NE..........................................  ISO New England Inc.
J.P. Morgan.....................................  J.P. Morgan Ventures
                                                   Energy Corporation.
Joint Commenters................................  Constellation Energy
                                                   Commodities Group,
                                                   Inc., Constellation
                                                   NewEnergy, Inc., and
                                                   Integrys Energy
                                                   Services, Inc.
MidAmerican.....................................  MidAmerican Energy
                                                   Holdings Company.
Midwest ISO.....................................  Midwest Independent
                                                   Transmission
                                                   Operator, Inc.
Midwest TDUs....................................  Indiana Municipal
                                                   Power Agency, Madison
                                                   Gas & Electric
                                                   Company, Missouri
                                                   River Energy
                                                   Services, Southern
                                                   Minnesota Municipal
                                                   Power Agency, and
                                                   WPPI Energy.
Mirant..........................................  Mirant Corporation.
Morgan Stanley..................................  Morgan Stanley Capital
                                                   Group Inc.
NEMA............................................  National Energy
                                                   Marketers
                                                   Association.
NEPOOL..........................................  New England Power Pool
                                                   Participants
                                                   Committee.
New Jersey Public Power.........................  Public Power
                                                   Association of New
                                                   Jersey and Madison,
                                                   New Jersey.
New York Consumers..............................  Multiple Intervenors,
                                                   including more than
                                                   50 large industrial,
                                                   commercial, and
                                                   institutional end-use
                                                   energy consumers
                                                   located in New York.
New York Suppliers..............................  Small Customer
                                                   Marketer Coalition
                                                   (The Constellation
                                                   Companies, The CENG
                                                   Companies, and The
                                                   NRG Companies).
NIPSCO..........................................  Northern Indiana
                                                   Public Service
                                                   Company.
Northeast ISOs..................................  ISO-NE, NYISO, and PJM
                                                   Joint Comments.
Northern California Power Agency................  Northern California
                                                   Power Agency.
NRECA...........................................  National Rural
                                                   Electric Cooperative
                                                   Association.
NYISO...........................................  New York Independent
                                                   System Operator, Inc.
NYPSC...........................................  New York Public
                                                   Service Commission.
NYSCB...........................................  New York State
                                                   Consumer Protection
                                                   Board.
NYTOs...........................................  New York Transmission
                                                   Owners, including
                                                   Central Hudson Gas &
                                                   Electric Corporation,
                                                   Consolidated Edison
                                                   Company of New York,
                                                   Inc., Long Island
                                                   Power Authority, New
                                                   York Power Authority,
                                                   New York State
                                                   Electric & Gas
                                                   Corporation, Orange
                                                   and Rockland
                                                   Utilities, Inc., and
                                                   Rochester Gas and
                                                   Electric Corporation.
OMS.............................................  Organization of
                                                   Midwest ISO States.
PG&E............................................  Pacific Gas & Electric
                                                   Company.
PJM.............................................  PJM Interconnection,
                                                   L.L.C.
Powerex.........................................  Powerex.
PSEG............................................  Public Service
                                                   Electric and Gas
                                                   Company, PSEG Power
                                                   LLC, and PSEG Energy
                                                   Resources & Trade
                                                   LLC.
SCE.............................................  Southern California
                                                   Edison Company.
SDG&E...........................................  San Diego Gas &
                                                   Electric Company.
Shell Energy....................................  Shell Energy.
Six Cities......................................  Cities of Anaheim,
                                                   Azusa, Banning,
                                                   Colton, Pasadena, and
                                                   Riverside,
                                                   California.
SPP.............................................  Southwest Power Pool,
                                                   Inc.
SWP.............................................  California Department
                                                   of Water Resources
                                                   State Water Project.
WAPA............................................  Western Area Power
                                                   Administration.
Wisconsin parties...............................  Wisconsin Public
                                                   Service Commission
                                                   and Upper Peninsula
                                                   Power Company.
WPTF............................................  Western Power Trading
                                                   Forum.
Xcel............................................  Xcel Energy Services.
------------------------------------------------------------------------

[[Page 65964]]

[FR Doc. 2010-27129 Filed 10-26-10; 8:45 am]
BILLING CODE 6717-01-P