[Federal Register Volume 75, Number 207 (Wednesday, October 27, 2010)]
[Rules and Regulations]
[Pages 65942-65964]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-27129]
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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\
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\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).
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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\
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\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.
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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.
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\60\ The Northeast ISOs refer to joint comments filed by ISO-NE,
PJM, and NYISO.
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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.
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\61\ New Jersey Public Power Comments at 10.
\62\ Powerex March 29, 2010 Comments at 7-8.
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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\
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\63\ CPUC March 29, 2010 Comments at 3.
\64\ Id. at 3-4.
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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\
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\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.
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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\
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\69\ Northeast ISOs March 29, 2010 Comments at 6-7.
\70\ Basin Electric March 29, 2010 Comments at 3.
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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\
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\71\ NRECA March 29, 2010 Comments at 11.
\72\ Shell Energy March 29, 2010 Comments at 7.
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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\
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\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.
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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.
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\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).
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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.
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\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)).
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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.
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\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.
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\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).
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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.
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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.
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\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.
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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.
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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\
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\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.
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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.
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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.
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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.
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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\
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\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.
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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\
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\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.
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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.
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\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.
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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\
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\105\ PJM Interconnection, L.L.C., 131 FERC ] 61,017 at P 31-34,
order on reh'g, 132 FERC ] 61,180 (2010).
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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\
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\106\ PJM March 29, 2010 Comments at 18-19.
\107\ Id. at 10-11.
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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\
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\108\ CFTC March 29, 2010 Comments at 2 n.7.
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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.
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\109\ Midwest ISO has adopted an approach similar to this,
discussed below.
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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.
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\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.
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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\
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\111\ Shell Energy March 29, 2010 Comments at 8.
\112\ MidAmerican Energy March 29, 2010 Comments at 7-8.
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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.
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\113\ Dominion March 29, 2010 Comments at 7-10.
\114\ NYISO March 29, 2010 Comments at 15.
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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\
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\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.
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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\
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\117\ Six Cities March 29, 2010 Comments at 6.
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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\
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\118\ Citigroup March 29, 2010 Comments at 5.
\119\ OMS March 16, 2010 Comments at 4-5.
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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\
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\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).
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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.
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\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).
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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\
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\126\ Id. at Tr: 21:22-26:14 (Mr. Daniel J. Shonkwiler, Senior
Counsel, CAISO).
\127\ Id. at Tr: 89: 1-25-90: 1-19 (Mr. Harold Novikoff,
Wachtell, Lipton, Rosen & Katz).
---------------------------------------------------------------------------
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.
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\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\
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\129\ Id. at Tr: 101:1-12 (Mr. Harold Novikoff, Wachtell,
Lipton, Rosen & Katz).
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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.
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\130\ Constellation June 8, 2010 Comments at 4.
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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\
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\131\ CAISO July 23, 2010 Comments at 6.
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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\
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\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.
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\133\ Policy Statement, 109 FERC ] 61,186 at P 29.
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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.
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\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.
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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.
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\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).
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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.
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\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.'')
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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\
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\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.
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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\
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\140\ Midwest TDUs, NYTOs, Consumers Energy, Wisconsin Parties
and Financial Marketers.
\141\ Financial Marketers March 29, 2010 Comments at 2-3.
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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.
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\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.
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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\
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\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.
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\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.
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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.
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\146\ We will leave to the discretion of the individual ISOs and
RTOs how much notice may be reasonable in particular circumstances.
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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\
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\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).
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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\
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\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.
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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\
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\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.
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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\
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\159\ CAISO, NCPA, CPUC, the Six Cities, and PG&E.
\160\ Six Cities March 29, 2010 Comments at 6-7.
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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: [email protected].
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 [email protected]), or the Public Reference Room at
202-502-8371, TTY 202-502-8659 (e-mail at
[email protected]).
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