RM10-13-000 Final Rule OMB Just

FERC-(516), RM10-13-000 Final Rule October 21, 2010 RIN No. 1902-AD89

SUPPORTING STATEMENT FOR

FERC-516 Electric Rate Schedules and Tariff Filings,

Credit Reforms in Organized Wholesale Electric Markets

In Docket No. RM10-13-000 (Final Rule)

The Federal Energy Regulatory Commission (FERC or Commission)

requests Office of Management and Budget review and approval of a revision to the information collection requirements contained in FERC-516, Electric Rate Schedule and Tariff Filings, (1902-0096) as proposed in the following Final Rule, RM10-13-000 “Credit Reforms in Organized Wholesale Markets”. FERC-516 is currently approved through October 31, 2013.

Overview

The Commission has long been interested in credit policies in wholesale electric markets. The Commission considered issues related to credit practices in 1996 in crafting the pro forma Open Access Transmission Tariff (OATT) in Order No. 888,¹ where it directed that each transmission provider’s tariff include reasonable creditworthiness provisions, and again in 2004 in a subsequent policy statement that provided additional guidance regarding creditworthiness.² Since then, the individual organized wholesale electric markets have developed credit practices on a case-by-case basis, in response to individual concerns and issues and with varying levels of stakeholder support. More recently, some in the industry have expressed concern that these credit practices may no longer be adequate to protect the integrity of these markets and, in turn, to protect consumers from the high costs that would flow from excessive defaults and associated risks in the markets.

Credit practices and related risk management tools within organized wholesale electric markets have developed incrementally. Until the 1980s, electricity was generally produced and consumed within a single utility system, or bought from neighboring traditional utility suppliers. Because the risk of non-performance was deemed minimal, collateral requirements and other credit practices were not rigidly managed. Credit practices began to evolve with the development of independent generators and then with increased bulk trading between traditional utilities and independent generators and marketers in the 1990s. Credit practices further progressed in this decade, as power trading with multiple counterparties became a recognized multi-billion dollar industry.

Today, parties operating outside the organized wholesale electricity markets typically use bilateral contracts such as the Western Systems Power Pool (WSPP) standard contract and the Edison Electric Institute (EEI) standard contract to sell power, managing credit risk within the terms of those agreements. However, the majority of transactions based on quantity and volume is in the organized wholesale electric markets.³ Individual RTOs and ISOs developed their own individual processes for assessing risk, extending unsecured credit, and settling accounts.

To a large degree, early credit policies in the organized wholesale electric markets were based on the practices of their transmission owning members. In Order No. 888, the Commission required each transmission provider to have “reasonable credit review procedures … in accordance with standard commercial practices,”⁴ but otherwise allowed the transmission provider to develop its own individual credit practices.⁵ As the organized markets were being formed, they tended to use practices based on those of their transmission-owning members.

Over time, the credit policies in each RTO and ISO have evolved and, in November 2004, the Commission issued its Policy Statement on Electric Creditworthiness to encourage consideration of specific reforms.⁶ In particular, the Commission recommended that transmission providers establish qualitative and quantitative measures to assess credit risk and post those measures on their Open Access Same-Time Information System (OASIS) websites or in their tariffs. Further, the Commission recommended that organized wholesale electric markets seek to minimize the risk of default by shortening the settlement period, netting obligations owed by and to market participants wherever possible, and adopting other measures.

Subsequent to the Policy Statement, various proposals to amend credit policies have been filed by RTOs and ISOs and accepted by the Commission. PJM Interconnection, LLC (PJM), for example, has made several filings revising its tariff to modify its credit practices. The Commission recently accepted PJM’s proposal to revise its tariff to reduce its settlement cycle from 30 days to seven days, reduce the amount of unsecured credit allowed to $50 million for a member company and $150 million for an affiliated group, and eliminate unsecured credit in the financial transmission rights market.⁷ Earlier, the Commission accepted a shortened period to cure defaults and other tariff revisions intended to improve credit practices.⁸

Likewise, the Commission has accepted recent tariff revisions filed by California Independent System Operator Corporation (CAISO), reducing the level of unsecured credit that may be obtained by a market participant from $250 million to $150 million,⁹ and eventually to $50 million.¹⁰ The Commission has also accepted CAISO’s proposal to shorten its “settlement and payment period” from more than 80 days to approximately 25 days.¹¹

Concerns of default, especially large defaults that have not been minimized by market safeguards, are troubling in the organized wholesale electric markets, in which losses due to default are borne among all market participants.¹²

RM10-13-000 NOPR

On January 21, 2010, in Docket No. RM10-13-000, the Commission issued a Notice of Proposed Rulemaking (NOPR) to amend its regulations under the Federal Power Act Section 206, to reform credit practices in organized wholesale electric markets to ensure that credit practices result in jurisdictional rates that are just and reasonable. Credit practices are particularly important in the organized energy markets, in which regional transmission organizations (RTOs) and independent system operators (ISOs) must balance the need for market liquidity against corresponding risk.¹³ In order to ensure that credit policies result in jurisdictional rates that are just and reasonable, FERC proposed to require RTOs and ISOs to adopt tariff revisions to reflect proposed credit reforms. These reforms included shortening settlement periods and reducing the amount of unsecured credit.

In the NOPR, the Commission estimated that the annual burden associated with the information requirements contained in the proposed rulemaking to be a total of 360 hours (60 hours per organization). This estimate was based on the number of RTO’s and ISO’s who file transmission tariffs with the Commission and the modifications to their tariffs that each RTO/ISO will have to perform. As a result of the revisions of the requirements and the corresponding reporting burden of 360 hours, the hours will be added to the total hours associated with FERC-516 at the final rule stage.

RM10-13-000 Final Rule

On October 21, 2010, in Docket No. RM10-13-000, the Commission issued a Final Rule to amend its regulations under the Federal Power Act Section 205, to improve the management of risk and the subsequent use of credit in organized wholesale electric markets. Each RTO and ISO will be required to submit a compliance filing including tariff revisions to demonstrate that its existing tariff already satisfies the regulations. The Commission is issuing this Final Rule, to require shortened settlement timeframes, to place restrictions on the use of unsecured credit, the elimination of unsecured credit in all financial transmission rights (FTR) or equivalent markets,¹⁴ 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. The Commission has also revised its initial burden estimate to 100 hours per entity or an increase in its initial estimate from 360 hours to 600 hours of burden to the inventory.

1. JUSTIFICATION

1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY

The Commission has a statutory obligation under Section 205 and 206 of

the Federal Power Act (FPA) to prevent unduly discriminatory practices in transmission access. FPA section 205 specifies that all rates and charges, and related contracts and

service conditions, for wholesale sales and transmission of energy in interstate commerce be filed with the Commission and must be “just and reasonable”. In addition, FPA section 206 requires the Commission, upon complaint or its own motion, to modify existing rates or services that are found to be unjust, unreasonable, unduly discriminatory or preferential. FPA section 207 further requires the Commission, upon complaint by a state commission and a finding of insufficient interstate service, to order the rendering of adequate interstate service by public utilities, the rates for which would be filed in accordance with FPA sections 205 and 206.

Because “just and reasonable” is not defined by the FPA, the Commission and the courts historically have interpreted this standard in the context of public utilities possessing market power. The courts generally have held that electric rates should be limited to rate levels sufficient to compensate the utility for the cost of rendering service to its customers, including a fair return on the utility’s investment devoted to the service at issue.

In Order No. 888, the Commission encouraged the development of independent systems operators (ISOs) as a way to implement the Commission's functional unbundling

policy for existing power pools. Properly functioning ISO's serve the public interest by making the electric power market to be more competitive place. Trade in bulk power markets increased significantly and the Nation's transmission grid was used more heavily and in new ways as customers took advantage of the pro forma OATT and purchased power from competitive sellers.

In the wake of these changes, in December 1999, the Commission adopted Order No. 2000. That rulemaking recognized that Order No. 888 set the foundation upon which competitive electric markets could develop, but did not eliminate the potential to engage in undue discrimination and preference in the provision of transmission service.¹⁵ The Final Rule also recognized that Order No. 888 did not address the regional nature of the grid, including the treatment of parallel flows, pancaked rates, and congestion management. Thus, the Commission encouraged the creation of RTOs to address important operational and reliability issues and eliminate any residual discrimination in transmission services that can occur when the operation of the transmission system remains in the control of a vertically integrated utility. The Commission found that RTOs would increase the efficiency of wholesale markets by eliminating pancaked rates, internalizing parallel flow, managing congestion efficiently and operating markets for energy, capacity and ancillary services. The Commission established an open, collaborative process that relied on voluntary regional participation to design RTOs tailored to the specific needs of each region. The Commission noted, however, that “[i]f the industry fails to form RTOs under this approach, the Commission will reconsider what further regulatory steps are in the public interest.”¹⁶

On February 17, 2007, the Commission issued a final rule Order No. 890, to revise the pro forma Open Access Transmission Tariff (OATT).¹⁷ The final rule addressed and remedied opportunities for undue discrimination under the OATT adopted in 1996 by Order No. 888. Order No. 888 fostered greater competition in wholesale power markets by reducing barriers to entry in the provision of transmission service. In the ten years since Order No. 888, however, the Commission has found that the OATT contained flaws that undermine realizing its core objective of remedying undue discrimination.

Additionally, since the issuance of Order No. 888, the Commission also has experience on the evolution by the markets with credit practices and it believes that it is appropriate to now consider adoption of specific requirements regarding credit practices for organized wholesale electric markets, to be set forth in the Commission’s regulations. To promote confidence in the markets, the Commission in the NOPR, proposed reforming credit practices of the organized wholesale electric markets to limit potential future market disruptions and to dampen the possible ripple effect of such disruptions. These reforms include shortening settlement periods and reducing the amount of unsecured credit, as described below. The Commission believes that these reforms, as adopted, 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.

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.¹⁸ 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.¹⁹

For these reasons, and in light of recent experiences in both the broader economy and the organized wholesale electric markets, the Commission has revisited the risk and credit procedures pertaining to the organized wholesale markets under its jurisdiction.

In making these proposals, the Commission seeks to balance the needs of the organized wholesale electric markets to modify their practices to comply with the proposed reforms against the benefits to the markets and consumers of having the reforms in place before the winter peak season in 2011-2012.

2. HOW, BY WHOM, AND FOR WHAT PURPOSE THE INFORMATION IS TO BE USED AND THE CONSEQUENCES OF NOT COLLECTING 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.

The major portion of data requested in the Part 35 regulations specifies the rates, terms and conditions of service to support the wholesale customers in a service the utility is proposing to provide. Submission of the information is necessary because of the complexity of the utility conditions and terms to provide service. Sufficient detail must be obtained for the Commission to make informed and equitable decisions concerning the appropriate levels of rates and service, and to aid customers and other parties who may wish to challenge the rate proposed by the utility. Through this data collection process, the Commission is able to regulate public utilities and licensees by exercising oversight and review of the reported rate schedules and tariffs.

With regard to administering tariffs, the RTO is the sole provider of transmission services and sole administrator of its own open access tariff. It has sole authority over facilities under its control to evaluate and approve or deny all requests for transmission service, and also authority to approve requests for new interconnections.

In addition, the Commission has a statutory obligation under section 205 and 206 of the FPA to prevent unduly discriminatory practices in transmission access. To accomplish this, the Commission added section 35.27 to its regulations concerning the standards a public utility must satisfy regarding nondiscriminatory open access transmission services on the utility's facilities that transmit electric energy in interstate commerce. The regulations require all public utilities owning or controlling facilities for the transmission of electric energy in interstate commerce to file tariffs of general applicability that offer transmission services, including ancillary services, on a network and point-to-point basis. The regulations require the public utility take transmission service for itself under the rates, terms and conditions of these tariffs. In essence these tariffs as approved by the Commission list the terms and conditions, including a schedule or prices, under which utility services will be provided.

This final rule amends the Commission’s regulations to ensure that credit practices currently in place in organized markets reasonably protect consumers against the adverse effects of default. To promote confidence in the markets, the Commission believes it is appropriate to consider adoption of specific requirements regarding credit practices for organized wholesale electric markets. These requirements include as noted above, shortening of settlement periods and reducing the amount of unsecured credit. The Commission believes these actions, as they are adopted, 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. Filings by RTOs and ISOs would be made under Part 35 of the Commission’s regulations.

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.

The Commission has reasoned that the proposed reforms are necessary to address the lack of standardized credit practices and the potential for mutualized default risk. Credit practices are basic acceptable practices that 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 that there will be 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 all market participants.

Without this information, the Commission would be unable to discharge its responsibility to approve or modify electric utility tariff filings and 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;²⁰ 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.

For these reasons, the Commission is revising its regulations to require that each RTO and ISO include in the credit provisions of its tariff language to limit the time period allowed to post additional collateral when additional collateral is requested by the organized wholesale electric market. The Commission seeks to ensure that the tariffs contain reasonable creditworthiness provisions,

3. DESCRIBE ANY CONSIDERATION FOR THE USE OF IMPROVED INFORMATION TECHNOLOGY TO REDUCE BURDEN AND TECHNICAL OR LEGAL OBSTACLES TO REDUCING BURDEN

There is an ongoing effort to determine the potential and value of improved information technology to reduce the burden. The Commission adopted user friendly electronic formats and software in order to facilitate the required electronic formats for rate filings and will develop formats for any subsequent filings.

In Order No. 2001, (67 FR 31043, May 8, 2002) the Commission revised the format through which traditional public utilities and power marketers must satisfy their obligation, in accordance with section 205 of the FPA and Part 35 of the Commission’s regulations, to file agreements with the Commission. Public utilities that have standard forms of agreement in their transmission tariffs, cost-based power sales tariffs, or tariffs for other generally applicable services no longer have to file conforming service agreements with the Commission. The filing requirement for conforming agreements is now satisfied by filing the standard form of agreement and an electronic Electric Quarterly Report. Order No. 2001 also lifted the requirement that parties to an expiring conforming agreement file a notice of cancellation or a cancellation tariff sheet with the Commission. The public utility can simply remove the agreement from its Electric Quarterly Report.

On November 15, 2007, the Commission issued a Final Rule, RM07-16-000, Order No. 703, “Filing via the Internet” 73 Fed. Reg. 65659 (November 23, 2007) revising its regulations for implementing the next version of its system for filing documents via the Internet, eFiling 7.0. The Final Rule allows the option of filing all documents in Commission proceedings through the eFiling interface except for specified exceptions, and of utilizing online forms to allow “documentless” interventions in all filings and quick comments in P (Hydropower Project), PF (Pre-Filing NEPA activities for proposed gas pipelines), and CP (Certificates for Interstate Natural Gas Pipelines) proceedings.

In RM01-5-000²¹, Order No. 714 issued September 19, 2008, FERC revised its regulations to require that all tariffs, tariff revisions and rate change applications for the public utility, natural gas pipeline and oil pipeline industries be filed according to a set of standards developed in conjunction with the North American Standards Board. The standards assist in FERC’s goal of establishing a robust electronic filing environment for tariffs and tariff related material and make it possible for FERC staff and the public to retrieve this material from a data base. Adoption of these standards and protocols provides each company with enhanced flexibility to develop software to better integrate tariff filings with their individual tariff maintenance and business needs. These standards and protocols also provide an open platform permitting third-party software developers to create more efficient tariff filing and maintenance applications, which spreads the development costs over larger numbers of companies.

Electronically filed tariffs and rate change applications improves the efficiency and administrative convenience and improve the overall management of the tariff and tariff change filing process, facilitate public access to tariff information, and reduce the burden and expense associated with paper tariffs and tariff changes. In addition electronically filed tariffs improve access and research capabilities with and among applicant’s tariffs. These features help facilitate the Commission’s monitoring of the energy markets, to the benefit of the customers and all involved. It also enhances competition within industries by providing the customers with an electronic means of comparing the rates, terms and conditions, and other provisions applicable to the regulated entities. The electronic filing requirements began April 1, 2010 with final implementation as of September 30, 2010.

The Commission intends, as far as practicable, to continue decreasing its reliance on paper documents and to continue to upgrade eFiling capabilities in furtherance of the Commission’s responsibilities under the Government Paperwork Elimination Act.²²

4. DESCRIBE EFFORTS TO IDENTIFY DUPLICATION AND SHOW SPECIFICALLY WHY ANY SIMILAR INFORMATION ALREADY AVAILABLE CANNOT BE USED OR MODIFIED FOR USE FOR THE PURPOSE(S) DESCRIBED IN INSTRUCTION NO. 2.

Electric Rate schedules and tariff filings contain transmission information that

are not available from other sources and therefore, no use or other modification of the

information can be made to perform oversight and review responsibilities under

applicable legislation (e.g. Federal Power Act, Energy Policy Act of 1992, Energy Policy

Act of 2005). All of the Commission’s public information collections are subject to

analysis and review by Commission staff and are examined for redundancy. Further,

Commission staff conducted an internal review of this collection of information to

determine the necessity of the Commission’s strategic objectives.

5. METHODS USED TO MINIMIZE BURDEN IN COLLECTION OF INFORMATION INVOLVING SMALL ENTITIES

The Commission has reviewed those public utilities that constitute “small business concerns” under the Regulatory Flexibility Act for compliance with the proposed Final Rule. FERC does not believe that the Final Rule will have a direct impact on small entities. In making this determination, the Commission is required to examine only the direct compliance costs that rulemaking imposes on small businesses.²³ Most, if not all, of the transmission organizations to which the requirements of this rule would apply do not fall within the definition of small entities.²⁴ Those entities to be impacted directly by this rule include the following:

• California Independent Service Operator Corp. (CAISO) 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.

• New York Independent System Operator, Inc. (NYISO) 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.

• PJM Interconnection, L.L.C. (PJM) 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.

• Southwest Power Pool, Inc. (SPP) is comprised of 50 members serving 4.5 million customers in 8 states and has 52,301 miles of transmission lines.

• 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.

• ISO New England Inc. (ISO-NE) is a regional transmission organization serving 6 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.

This rulemaking does not impose significant compliance costs on small entities. Instead, it leaves them with the choice of whether to join an RTO or not. The only costs mandated are the minimal costs associated with a filing a statement, in the event a public utility does not make an RTO filing, explaining its efforts to join an RTO, any barriers it encountered and any future plans to join an RTO.

6. CONSEQUENCE TO FEDERAL PROGRAM IF COLLECTION WERE CONDUCTED LESS FREQUENTLY

It is not possible to collect this data less frequently. Only public utilities owning,

operating, and/or controlling facilities used for the transmission of electricity in interstate

commerce are required to comply with the Final Rule. They will only be required to file

once to amend their OATTs to include these reforms or indicate why they already have

provisions in place in their tariffs. Specifically, the Commission is requiring that each

RTO and ISO make certain filings to amend their tariffs, in order to comply with the

credit reform requirements specified in the Final Rule.

The required information should impose the least possible burden for companies to comply with the Commission’s open access policies.

7. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION COLLECTION

This program meets all of OMB's section 1320.5 requirements.

8. DESCRIBE EFFORTS TO CONSULT OUTSIDE THE AGENCY: SUMMARIZE PUBLIC COMMENTS AND AGENCY'S RESPONSE TO THESE COMMENTS

As noted above, the Commission has concerns about the adverse effects of defaults and also ensuring that the credit policies in place in organized markets can adequately protect consumers. These concerns prompted the issuance of the NOPR and to seek comments on proposed reforms.

The Commission held a technical conference in January of 2009 to investigate the role of credit in light of the recent financial crisis.²⁵ 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.”²⁶ Others testified about “recent near-misses” in the organized wholesale markets and suggested that the Commission should consider improvements in credit practices.²⁷ (See item number 2 above) The 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.

Comments

Shortening the Settlement Cycle

The Commission and participants in the electric industry have recognized a correlation between a reduction in the “settlement cycle”²⁸ 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.” ²⁹

Currently, each ISO and RTO has its own time period for settlement. ISO-NE has weekly settlement (soon to be twice-weekly, as accepted by the Commission),³⁰ with payment due no later than the second business day after the invoice is issued. Midwest ISO has weekly billing, with payment due seven days after the weekly invoice is issued.³¹ PJM has weekly billing and settlement.³² SPP has weekly billing, with payment due the following Wednesday.³³ CAISO has semimonthly billing, with five additional days for payment.³⁴ NYISO has monthly billing, with payment due by the first banking day common to all parties after the 15^th day of the month that the invoice is rendered by the ISO.³⁵

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).³⁶ 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.³⁷ 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 periods.

Parties in favor of the proposal include a number of the ISOs and RTOs, as well as financial entities such as “Financial Marketers,”³⁸ Citigroup Energy (Citigroup), J.P. Morgan Ventures Energy Corporation (J.P. Morgan), and Morgan Stanley Capital Group (Morgan Stanley). The staff of the Division of Clearing & Intermediary Oversight at the Commodity Futures Trading Commission (CFTC) also supported moving the billing cycle to, at most, to seven days.³⁹

Many industry participants who are normally “net sellers” of supply such as Constellation, NRG, Calpine, Dominion, Mirant, and Powerex also supported the proposed shortened billing time-period.⁴⁰ The Committee of Chief Risk Officers (CCRO) supported a standard seven-day billing period as “consistent” with its review of best practices in the electric industry.⁴¹ The New York Suppliers noted that NYISO is the lone organized market in the nation remaining with a monthly billing period.⁴² 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.⁴³ The Independent Power Producers of New York (IPPNY) commented 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,⁴⁴ suggesting that not only was liquidity enhanced by shorter billing but the change did not pose a barrier to entry.

Powerex stated 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 agreed 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.⁴⁵

CAISO, alone among the organized markets, doubted that moving to a weekly billing standard would result in incremental benefits significantly beyond those already achieved as it would reduce aggregated outstanding liabilities by only an additional 10 percent. CAISO expressed 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 explained that its future plans are to move to weekly billing.⁴⁶

Parties that opposed the proposal include the City of New York, the New York State Public Service Commission (NYPSC) and “Six Cities.”⁴⁷ The City of New York and the NYPSC argued 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.⁴⁸ 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 another.⁴⁹

Other parties opposed movement to weekly billing based on data concerns, including net sellers such as Midwest Transmission Dependent Utilities (Midwest TDUs)⁵⁰ and Consolidated Edison Solutions.⁵¹ Their position was similar to the concerns of Bonneville Power Administration (BPA) who, while supportive of weekly billing, had concerns about the ability of CAISO to effectively manage the increased demands of weekly billing. PG&E argued against reducing settlement 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.⁵²

Commission Response

In the Final Rule, the Commission is adopting 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,⁵³ the Commission finds that 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. The Commission is not persuaded by comments that shortened billing and settlement cycles will compromise the liquidity of the organized wholesale electric markets.

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.⁵⁴

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.

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.

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.

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, the Commission will not require daily billing at this time. Instead the Commission will require, weekly billing.

Ability to Offset Market Obligations

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.

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.

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.

PJM supported the Commission’s approach. Besides providing certainty, PJM argued 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.⁵⁵ In addition, PJM argued that the Commission’s approach is not without precedent. In support, it noted 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 stated 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.⁵⁶

Similarly, CFTC staff believes that the proposal would materially reduce credit risk for ISOs and RTOs. CFTC staff also stated 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.⁵⁷

J.P. Morgan supported 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 agreed 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 noted 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.⁵⁸ 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.

CCRO explained 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 encouraged the Commission to formulate policy and regulations which enable cost-effective implementation of this best practice. In addition, it encouraged the Commission to support innovations in netting consistent with emerging best practice.

Many commenters voiced strong views in opposition to this proposal. CAISO and Midwest ISO noted 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.⁵⁹ They encouraged consideration of less burdensome alternatives.

Other commenters questioned whether, absent steps taken in the Final Rule, there will really be a problem in upholding netting in the bankruptcy context. For instance, Shell Energy urged 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.⁶⁰ NRECA also asserted that the bankruptcy set-off risk to RTOs is largely hypothetical. MidAmerican Energy concurred with the joint comments of CAISO and Midwest ISO and asserted 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.⁶¹

Dominion argued that the set-off risk has not yet been demonstrated and asserts that the proposal is unreasonable.⁶² In addition, NYISO stated 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.⁶³ EPSA does not take a position on the proposal and instead asked the Commission to more clearly define the problem that it is trying to solve.

In contrast, NYISO argued that, because ISO and RTO tariffs specifically establish a contractual obligation of payment to the ISO or RTO, a bankruptcy court would likely allow an ISO or RTO to set-off the obligations of a market participant. Moreover, NYISO believes that a bankruptcy court may, for policy reasons, defer to the Commission-approved tariff provisions of the ISO or RTO, or uphold ISO or RTO netting under the doctrine of recoupment,⁶⁴ thereby circumventing a challenge for mutuality.⁶⁵

Many commenters argued 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.

Six Cities urged 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.⁶⁶

Numerous commenters opposed 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 argued that implementing central counterparty status will require a radical restructuring of ISOs/RTOs.

CCRO generally supported the Commission’s proposal and believes that any approved procedure should be standardized across the ISOs/RTOs to the extent practical. CCRO also encouraged 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.

Commission Response

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,⁶⁷ 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.

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 is directing 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.

• 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.

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.”⁶⁸ 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.’”⁶⁹ The Commission’s 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.

While the Commission continues to believe that the NOPR proposal provides a sound approach to this issue, the Commission is 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. 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.⁷⁰ 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.⁷¹ 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.

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 is going to 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.

Many parties also stated 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.⁷² As to possible tax implications, no specific evidence has been presented showing that the central counterparty model will lead to increased tax obligations. However, the Commission need not decide these points here, and RTOs and ISO, ands may consider these points in deciding how to comply with the Final Rule.

Use of “Material Adverse Change”

Events in credit markets can change the fortunes of a participant very quickly.⁷³ 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.

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.

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.

The Commission therefore proposed in the NOPR to require ISOs and RTOs to include in their tariffs language to more clearly specify circumstances when the market administrator may invoke a “material adverse change” clause.

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 stated 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.

CFTC staff noted 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 recommended 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.

CPUC, Dynegy, and SCE stated that they support clear guidelines on the definition of “material adverse change.” CPUC and SCE argued 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.⁷⁴ Therefore, CPUC requested that the Commission adopt guidelines that would allow the CAISO to maintain the status quo. Shell Energy also stated that the Commission should propose a generic material adverse change provision, and 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.

EEI stated 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 stated 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 stated 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.

MidAmerican stated 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 stated 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.

APPA proposed 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.⁷⁵

Commission Response

The Commission is adopting 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, the Commission is 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. The Commission is also persuaded that a market participant should receive a written explanation explaining the invocation of the material adverse change clause.

While market participants are generally familiar with “material adverse change” clauses, a market administrator’s right to invoke such a clause must be clarified in order to avoid any confusion, particularly during times of market duress, as to when such a clause may be invoked. Specifically, the Commission is concerned that a market participant in financial straits could exploit ambiguity as to when a market administrator may invoke a “material adverse change,” or a market administrator may be uncertain as to when it may invoke a “material adverse change,” and so delay, or even prevent entirely, actions that would insulate the market from unnecessary damage.

The Commission is directing 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. The Commission believes that the language proposed by the ISO/RTO Council is a good start, but notes 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.

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. The Commission is not adopting a pro forma list for the Commission, 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.

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 notice⁷⁶ 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.

9. EXPLAIN ANY PAYMENT OR GIFTS TO RESPONDENTS

Not applicable. The Commission does not provide compensation or remuneration to entities subject to its jurisdiction.

10. DESCRIBE ANY ASSURANCE OF CONFIDENTIALITY PROVIDED TO RESPONDENTS

An entity seeking confidential treatment of the information must ask the Commission to treat this information as confidential and non-public, consistent with Section 388.112 of the Commission’s regulations. (18 CFR 388.112) Generally, the Commission does not consider this information to be confidential.

11. PROVIDE ADDITIONAL JUSTIFICATION FOR ANY QUESTIONS OF A SENSITIVE NATURE THAT ARE CONSIDERED PRIVATE.

There are no questions of a sensitive nature that are considered private.

11. ESTIMATED BURDEN ON COLLECTION OF INFORMATION

Data Collection	Number of Respondents	No. of Responses	Hours Per Response	Total Annual Hours
FERC-516
Transmission Organizations with Organized Electricity Markets	6	1	100	600

Total Annual hours for Collection: (Reporting + recordkeeping, (if appropriate) =

Total hours for performing tasks 1 through as identified above = 600 hours. This is a modification from the Commission’s initial estimates and incorporates the additional documentation that an RTO/ISO will be tasked with. For instance, RTO/ISOs will need to provide market participants with advanced notice when they must inform market participants as to what events could trigger a collateral call or a change in activity in the market.

It should be noted that the above table applies only with the number of respondents who

have to comply with the requirements of this Final Rule. These requirements are a

component of all filing requirements contained under 18 CFR Part 35.

Current OMB Inventory

Data Collection	No. of Respondents	No. of Responses	Hours Per Response	Total Hours
FERC-516	1,230	4462	103.2740	460,809

As Proposed by FINAL RULE

Data Collection	No. of Respondents	No. of Responses	Hours Per Response	Total Hours
FERC-516	1,230	4,468	103.2696	461,409

13. ESTIMATED OF THE TOTAL COST BURDEN TO RESPONDENTS

The Commission reviewed both the hourly rate figures of the Bureau of Labor Statistics and salary.com. plus applying where possible market rates per occupational series. The hourly rates represent a composite of the respondents who will be responsible for implementing and responding to the Final Rule (Legal and financial staff). It has projected the average annualized cost to be:

In the NOPR, the Commission projected the average annualized cost of all respondents to be the following: 360 hours @ $300 per hour = $108,000 for respondents. No capital costs are estimated to be incurred by respondents. However, in light of the comments received, the Commission is revising its initial estimates to 100 hours per respondent.

The total annualized costs for the information collection is $180,000. This number is reached by multiplying the total hours to prepare responses (600 hours, 6 RTOs/ISOs @ 60 hours per entity) by an hourly wage estimate of $300 (a composite estimate that includes legal, technical and support staff rates, $215+$60+$25).

13. ESTIMATED ANNUALIZED COST TO THE FEDERAL GOVERNMENT

The costs to the Commission are estimated to be $68,917. (.50 FTEs (full time equivalent employees) x $137,834).

13. REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE

The Commission is issuing this Final Rule to reform credit practices in organized wholesale electric markets.⁷⁷ The recent turmoil in financial markets has emphasized the importance of sound credit practices that provide competitive markets with adequate access to capital without excessive risk and without excessive cost. Credit policies are particularly important in the organized energy markets, in which regional transmission organizations (RTOs) and independent system operators (ISOs) must balance the need for market liquidity against corresponding risk. In order to ensure that credit policies result in jurisdictional rates that are just and reasonable, the Commission proposes to require RTOs and ISOs to adopt tariff revisions reflecting these proposed credit reforms.

See Background section above for further discussion.

13. TIME SCHEDULE FOR THE PUBLICATION OF DATA

Schedule for Data Collection and Analysis

Tariff Amendment Filed See Below

Initial Commission Order 60 days

This compliance filing must be submitted by June 30, 2011, with the tariff revisions to take effect October 1, 2011.

13. DISPLAY OF EXPIRATION DATE

The information collected on Open Access Transmission Tariffs is not collected on standardized filing formats or a preprinted form that would avail itself of displaying the OMB control number. With the implementation of Order No. 714 (RM01-5-000), the electronic filing electric, gas and oil tariffs (see item no. 3 above), the control numbers for these information collections is displayed on the instructional manual disseminated to regulated entities and also posted on the Commission’s web site.

13. EXCEPTION TO THE CERTIFICATION STATEMENT

There are exceptions to the Paperwork Reduction Act Submission certification. Because the data collected for these reporting and recordkeeping requirements are not used for statistical purposes, the Commission does not uses as stated in item 19(I) “effective and efficient statistical survey methodology.” In addition, as noted in no. 17, this information collection does not fully meet the standard set in 19 (g) (vi.).

2. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS.

This is not a collection of information employing statistical methods.

1 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 12,274 (Mar. 14, 1997), FERC Stats. & Regs. ¶ 31,048, order on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002).

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

3 FERC Staff, 2008 State of the Markets Report, 51 (Sept. 2009).

4 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,937.

5 While the OATT applies to transmission providers, since 1996 a number of transmission providers have developed RTOs and ISOs.

6 See footnote 3.

7 PJM Interconnection, L.L.C., 127 FERC ¶ 61,017, at P 4 (2009).

8 PJM Interconnection, L.L.C., 126 FERC ¶ 61,084 (2009).

9 California Independent System Operator Corp., 126 FERC ¶ 61,285 (2009).

10 California Independent System Operator Corp., 129 FERC ¶ 61,142 (2009).

11 California Independent System Operator Corp., 128 FERC ¶ 61,265, at P 4 (2009).

12 Policy Statement, 109 FERC ¶ 61,186 at P 17 (“If collateral posted by a defaulting party is not sufficient to cover the amount of its default, the remaining credit risk exposure and costs are socialized across an ISO’s/RTO’s members.”).

13 Regional Transmission Organization -   An organization approved by the Commission to coordinate transmission planning (and expansion), operation, and use on a regional basis. Independent System Operator -   An entity charged with reliable operation of the grid and provision of open transmission access to all market participants on a non-discriminatory basis.

14 References to FTR markets in the Final Rule also include the Transmission Congestion Contracts (TCC) markets in NYISO and the Congestion Revenue Rights (CRR) markets in CAISO.

15 Order No. 2000 at 31,015.

16 Id. at 30,993.

17 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 Fed. Reg. 12,266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, 112 FERC ¶ 61,297 (2007)).

18 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.”).

19 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.

20 16 U.S.C. 824d, 824e (2006).

21 Electronic Tariff Filings, Order No. 714, 73 FR 57515 (Oct. 3, 2008), FERC Stats. & Regs ¶ 31,276 (2008).

22 Pub. L. No. 105-277, § 1704, 112 Stat. 2681, 2681-750 (1998).

23 Mid-Tex Elec. Coop, Inc. v. FERC, 773 F.2d 327 (D.C. Cir. 1985).

24 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. See 5 U.S.C. § 601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. § 632 (2000). The Small Business Size Standards component of the North American Industry Classification system defines a small utility as one that, including its affiliates is primarily engaged in the generation, transmission, or distribution of electric energy for sale, and whose total electric output for the preceding fiscal years did not exceed 4MWh. 13 C.F.R. § 121.202 (Sector 22, Utilities, North American Industry Classification System, NAICS) (2004).

25 Technical Conference on Credit and Capital Issues Affecting the Electric Power Industry, Docket No. AD09-2-000, held January 13, 2009.

26 Id. at Tr. 100:22-101:13 (Mr. Philip Leiber, Chief Financial Officer and Treasurer, California Independent System Operator).

27 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).

28 Some parties sought clarification of what the Commission meant by “settlement cycle” in its 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.”

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

30 ISO New England, Inc. and New England Power Pool, 132 FERC ¶ 61,046 (2010).

31 Midwest ISO March 29, 2010 comments at 4.

32 PJM March 29, 2010 comments at 21.

33 SPP March 29, 2010 comments at 3.

34 CAISO March 29, 2010 comments at 8.

35 Northeast ISOs March 29, 2010 comments at n.17; NYISO OATT at section 2.7.3.2.

36 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)).

37 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).

38 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.

39 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.

40 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.

41 CCRO March 29, 2010 comments at 3.

42 New York Suppliers March 29, 2010 comments at 9.

43 Id. at 9-10.

44 IPPNY March 29, 2010 comments at 12-13.

45 Powerex March 29, 2010 comments at 6-7.

46 CAISO March 29, 2010 comments at 7-8.

47 The “Six Cities” include the cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, all located in California.

48 City of New York March 29, 2010 comments at 6-7; NYPSC March 29, 2010 comments at 3-4.

49 NYPSC March 29, 2010 comments at 7-8; NYSCPB March 29, 2010 comments at 3.

50 Indiana Municipal Power Agency, Madison Gas & Electric Company, Missouri River Energy Services, Southern Minnesota Municipal Power Agency and WPPI Energy.

51 Midwest TDU March 29, 2010 comments at 7-9; Consolidated Edison Solutions March 29, 2010 comments at 3-4.

52 PG&E March 29, 2010 comments at 2.

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

54 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).

55 PJM March 29, 2010 Comments at 18-19.

56 Id. at 10-11.

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

58 Midwest ISO has adopted an approach similar to this, discussed below.

59 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.

60 Shell Energy March 29, 2010 Comments at 8.

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

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

63 NYISO March 29, 2010 Comments at 15.

64 “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 (9^th Cir. 1996) (quoting In re B & L Oil Co., 782 F.2d 155, 157 (10^th Cir. 1986)).

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

66 Six Cities March 29, 2010 Comments at 6.

67 Policy Statement, 109 FERC ¶ 61,186 at P 29.

68 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).

69 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.

70 Id. at Tr. 84:5-25, 85:1-22 (Iskender H. Catto; Kirkland & Ellis on behalf of the Committee of Chief Risk Officers).

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

72 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.”)

73 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.

74 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.

75 APPA March 29, 2010 Comments at 35.

76 The Commission will leave to the discretion of the individual ISOs and RTOs how much notice may be reasonable in particular circumstances.

77 For purposes of this Final Rule, organized wholesale electric markets include energy, transmission and ancillary service markets operated by independent system operators and regional transmission organizations. 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.

36