RM07-19-000 NOPR OMB Just

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FERC-516, RM07-19-000 NOPR

SUPPORTING STATEMENT FOR

FERC-516 Electric Rate Schedule Filings, Proposed Rule for

Wholesale Competition in Regions with Organized Electric Markets

In Docket No. RM07-19-000 (Noticed of Proposed Rulemaking)

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 Notice of Proposed Rulemaking.

RM07-19-000 NOPR

On February 21, 2008, in Docket No. RM07-19-000, the Commission issued a Notice of Proposed Rulemaking to amend its regulations under the Federal Power Act to improve the operation of organized wholesale electric markets in the areas of: (1) demand response and market pricing during a period of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of regional transmission organizations (RTOs) and independent system operators (ISOs) to stakeholders and customers. The Commission proposes to require that each RTO and ISO make certain filings that propose amendments to its tariff, in order to comply with the proposed requirements in each area, or that demonstrate that its existing tariff and market design already satisfy the requirements.

Overview

National policy for many years has been, and continues to be, to foster competition in wholesale power markets. As the third major federal law enacted in the last 30 years to embrace wholesale competition, the Energy Policy Act of 2005 (EPAct 2005)¹ strengthened the legal framework for continuing wholesale competition as federal policy for this country.

The Commission’s core responsibility is to “guard the consumer from exploitation by non-competitive electric power companies.”² The Commission has always used two general approaches to meet this responsibility—regulation and competition. The first was the primary approach for most of the last century and remains the primary approach for wholesale transmission service, and the second has been the primary approach in recent years for wholesale generation service.

The Commission has never relied exclusively on competition to assure just and reasonable rates and has never withdrawn from regulation of wholesale electric markets. Rather, the Commission has shifted the balance of the two approaches over time as circumstances changed. Advances in technology, exhaustion of economies of scale in most electric generation, and new federal and state laws have changed the Commission’s views of the right mix of these two approaches. The Commission’s goal has always been to find the best possible mix of regulation and competition to protect consumers from the exercise of monopoly power.

In each major energy bill over the last few decades, Congress has acted to open up the wholesale electric power market by facilitating entry of new generators to compete with traditional utilities. The Commission has acted quickly and strongly over the years to implement this national policy.

Congress has not deregulated the wholesale electric power business, however, and the Commission has not done so by regulation. To the contrary, the Commission has issued many new regulations and orders designed to foster competition nationally and to support competitive markets in specific regions. Because the United States does not have a national electric power market, its approach to implementing competition has been to recognize and foster the development of regional markets.

There are significant differences among the regional wholesale power markets. There are differences in industry structure, differences in the mix of ownership (such as investor-owned, cooperatively-owned, and publicly-owned utilities), differences in the mix of fuels and energy sources for electric generation, and differences in population densities and weather patterns, to name a few. Some regions pursue wholesale competition exclusively by relying on direct bilateral contracting between sellers and buyers, and others employ a mix of bilateral contracting with organized spot markets and other markets to increase opportunities for the sale or purchase of electric power. In regions with organized spot markets, the markets are administered by an RTO or ISO (ISO)³, which themselves have differences regarding such matters as market design, transmission

responsibilities, and decision-making procedures. The Commission’s approach to

supporting wholesale competition is to recognize and respect these differences in market structure and other differences across the various regions.

Wholesale competition can serve customers well in all regions, including RTO and ISO regions with organized markets and regions without such organizations and markets. There are strengths and weaknesses to the approach taken by each, and wholesale competition faces challenges in both areas.

The Commission believes however, that the best way to address these challenges may differ among the regions. For example, in all regions the cost of the fuels used for electric generation has increased in recent years, as it has throughout the world. Those regions of the United States that depend on natural gas for electric generation have felt this the most. Competitive spot markets reflect these cost changes quickly in market prices, while longer-term fixed price bilateral contracts or cost-of-service regulation may reflect cost increases or decreases more gradually in the wholesale price. Wholesale customers in all regions want better long-term contracting opportunities. All regions face the problem that retail customers are often unaware of supply shortages and continue their normal consumption even on days when supplies are tight and wholesale prices are high. Allocating the costs of a major new regional transmission facility fairly is a challenge faced by every region.

Regions with an RTO or ISO may be better able than other regions to address some of these issues, but they may also face more difficult challenges. For example, much of the recent dissatisfaction with organized competitive markets appears to be directly linked to rising natural gas prices.

As noted above, national policy is to promote wholesale competition in all regions, and customers now are calling especially for actions to improve the operation of wholesale competitive markets in the organized market regions. Hence, the focus of this NOPR is not whether wholesale competition is the correct federal policy; the focus is on further improving the operation of wholesale competitive markets in organized market regions.6 The Commission is seeking comment on proposed reforms to improve the operation of wholesale markets in these regions.

Background

Numerous federal and state legislative and regulatory activities have supported competition in the U.S. electric industry over the last three decades. Congress enacted the Public Utility Regulatory Policies Act of 1978 (PURPA)7 as a response to the energy crises of the 1970s. PURPA required electric utilities to interconnect with, and offer to purchase power from, qualifying cogeneration and small power production facilities at avoided cost rates set by state regulatory authorities. It gave the Commission limited authority to order wholesale transmission on a case-by-case basis, upon application by an eligible entity. A consequence of PURPA was the emergence of a new class of power

generators those were independent of traditional utilities.

Beginning in the 1980s, the Commission allowed independent power producers to sell electric energy at wholesale at negotiated rates instead of the traditional cost-based rates.⁴ Development of a competitive generation sector was impeded, however, because independent power producers were discouraged from entering the generation business by certain provisions of the Public Utility Holding Company Act of 1935 (PUHCA)⁵ and because the new power suppliers could not readily gain access to the transmission grid to reach wholesale buyers.

Congress addressed these problems in the Energy Policy Act of 1992 (EPAct1992)⁶ EPAct 1992 eased PUHCA restrictions so that independent and affiliate generators could more easily enter the market to compete at wholesale and it expanded the Commission’s authority to order a transmitting utility to provide wholesale power transmission service, upon application on a case-by-case basis, to anyone selling power at wholesale. By the mid-1990s, the Commission found that ordering wholesale transmission services case-by-case did not adequately address problems with undue discrimination in transmission access, which limited opportunities for wholesale power competition. In 1996, the Commission used its authority under section 206 of the Federal Power Act (FPA)⁷ to issue Order No. 888, remedying undue discrimination in access to transmission by requiring all public utilities with transmission to provide transmission service under an Open Access Transmission Tariff (OATT).⁸ The Commission recently issued Order No. 890 to remedy remaining opportunities for undue discrimination in the provision of open access transmission service.

Also during the 1990s, many states began to allow retail customers to choose their power supplier. Retail competition was expected to lower retail prices, protect customers from shouldering generation investment risk, and introduce innovative retail services including demand response services. By 2000, 24 states and the District of Columbia had enacted legislation or issued regulatory orders to restructure their electric power industries.⁹

In addition to requiring open transmission access in Order No. 888, FERC also encouraged the formation of ISOs. The Commission encouraged transmission-owning utilities to voluntarily transfer operating control of their transmission facilities to an ISO to ensure independent operation of the transmission grid. Several ISOs—some based on longstanding power pools such as PJM and ISO-NE—formed after that. Early experience with open transmission access led the Commission to issue Order No. 2000 in December 1999,¹⁰ which encouraged transmitting utilities, including those that were not public utilities, to join an RTO.¹¹ More than half the United States’ load is now served by RTOs or ISOs.¹² Most RTOs and ISOs have adopted some forms of organized markets, which have continued to evolve with operating experience.¹³ RTOs and ISOs have improved transmission reliability and enabled greater coordination and efficiency in the dispatch of resources and provision of transmission service over regions served previously by separate entities. Further, they have supported competitive power markets by eliminating pancaked rates in the region, as well as by providing a spot market to supplement traditional means of selling and buying power.

While RTOs and ISOs have produced benefits, they also have encountered many challenges. Security constrained least cost dispatch over a large region can reveal transmission constraints and higher locational prices in constrained areas. Previously, average prices for the large region masked these constraints. Higher prices in certain locations and the lack of investment to relieve chronic congestion are criticisms of RTOs and ISOs. Concerns about transmission investment are common to both the RTO and ISO regions and the other regions.

Competitive wholesale markets for electric energy, including RTO and ISO spot markets, have had successes and failures. Competitive markets have stimulated generation investment, with much of the new generation supplied by merchant generating companies.¹⁴ According to data from the Energy Information Administration (EIA), the percentage of generating capacity in the United States owned by independent power producers has grown from less than 2 percent in 1990 to more than 35 percent by 2005.¹⁵ As a result, there has been a shift in the risk of investment from customers to shareholders. In addition, under wholesale competition, the efficiency of existing nuclear, coal, and other types of generation has improved significantly, lowering costs to consumers and reducing

environmental effects, and the increased capacity factors and availability of these units have further lowered electric generating costs.¹⁶ The RTO and ISO-organized markets opened opportunities for renewable energy sources; an increasing fraction of new generation is from non-traditional sources such as wind generators. In fact, more wind generation has been added in RTO and ISO regions than in other regions, even though there are many areas with good wind availability.¹⁷ RTO and ISO regions with organized markets report that competitive markets promote significant investment in new transmission, improve transmission reliability, and open new opportunities for demand response.¹⁸

Despite all of the successes attributable to wholesale competition, there have been difficulties. The most prominent is that spot markets in California during 2000 and 2001 experienced sustained high wholesale prices resulting from supply shortages, market design flaws, and market abuses. In other RTOs and ISOs, prices in the day-ahead and real-time balancing markets have been volatile at times. This volatility can present issues for both buyers and sellers as buyers try to hedge the volatility and sellers try to project revenues from the organized markets. Even with the volatility, the RTO and ISO markets have provided wholesale customers and suppliers with a new and constantly available

opportunity to buy or sell power and transparent price information.

Much of the concern about competition in wholesale power markets can be traced to the effects of higher natural gas prices on wholesale electric power prices. As the Commission’s staff reported, “natural gas currently functions as the most significant price setting fuel in U.S. electric generation.”¹⁹ Natural gas prices have increased significantly over the last decade. According to the Energy Information Administration, the average U.S. wellhead price of natural gas increased from $2.17 in 1996 to $6.42 in 2006 (which was down from $7.33 in 2005).²⁰ The summer 2007 futures prices from the New York Mercantile Exchange (NYMEX) for natural gas at Henry Hub, Louisiana were up 21 percent over last summer’s actual average prices traded on the Intercontinental Exchange (ICE).²¹ As reported by Commission staff, wholesale prices for electricity were higher in the summer of 2007 in all regions of the United States, regardless of regional market structure.²² The principal reason was higher expected prices for natural gas. As the United States has increased its reliance on natural gas for electricity generation, particularly to meet peak loads, the forward price of natural gas has had an increasing effect on the forward price of wholesale electric power, especially during electric peak periods. The effect of wholesale prices is felt in parts of the United States that have no organized markets as well as regions with organized markets.

Some perceived challenges in the organized wholesale markets may be closely related to difficulties in state retail choice programs. Retail choice programs tend to be in areas served by organized wholesale markets, and the distinction between wholesale and retail competition challenges is often blurred. It appears that some areas with retail choice depend on their RTO or ISO to provide or arrange for the provision of some functions previously carried out by vertically integrated utilities. This has created challenges for wholesale market design, particularly with regard to whether it effectively provides for resource adequacy. Because wholesale and retail markets are intertwined, any examination of retail choice typically involves a critique of the combination of the particular retail choice program and the RTO’s or ISO’s wholesale market design.

The Commission continues to believe that wholesale competition benefits

customers by providing more choice, spurring innovative services and technologies, shifting risk away from customers, improving efficiency, and providing incentives for cost reductions and for the construction of new resources.

In the past several years, the Commission has received both formal and informal comments from market participants indicating areas where competition in wholesale markets could be improved. In response to these comments, the Commission held three public conferences in 2007 in order to gather more information on competition at the wholesale level and other related issues.

At the first conference on competition issues, held on February 27, 2007, most speakers addressed issues affecting the RTO and ISO regions, including the levels of wholesale prices, the need for long-term power contracts, the effectiveness of market monitoring, and the lack of adequate demand response.²³ On April 5, 2007, the Commission also held a technical conference on market monitoring policies and heard from interested commenters on issues such as the development of the concept and functions of market monitoring and the market monitoring units’ (MMU) role with respect to the Commission, ISOs and RTOs, and various stakeholders.²⁴ The Commission then held a second competition conference on May 8, 2007, to examine in more detail several specific concerns and challenges identified in the first conference. This second conference focused on regions with organized markets administered by RTOs and ISOs and dealt with: (1) demand response and market prices during a period of operating reserve shortage; (2) fostering long-term power contracting; and (3) the responsiveness of RTOs and ISOs to customers and other stakeholders.²⁵

Based on the record compiled at these three conferences, the Commission issued an Advance Notice of Proposed Rulemaking (ANOPR)²⁶ on June 22, 2007 to identify and implement improvements to specific aspects of organized wholesale markets. In the ANOPR, the Commission identified four issues in organized market regions that were not being adequately addressed or under consideration in other proceedings. These areas were: (1) the role of demand response in organized markets and greater use of market prices to elicit demand response during a period of operating reserve shortage; (2) increasing opportunities for long-term power contracting; (3) strengthening market monitoring; and (4) enhancing the responsiveness of RTOs and ISOs to customers and other stakeholders.

NOPR Proposals

The Commission received several thousand pages of comments from 101 commenters in response to the ANOPR (a list of commenters and their abbreviated names the Commission used for them in the NOPR appears in Appendix A).²⁷ After reviewing the comments, and pursuant to the Commission’s responsibility under sections 205 and 206 of the Federal Power Act (FPA)²⁸ to ensure that rates, charges, classifications, and service of public utilities (and any rule, regulation, practice, or contract affecting any of these) are just and reasonable and not unduly discriminatory, the Commission is making several proposals in this NOPR designed to ensure just and reasonable rates and to remedy undue discrimination and preference and to improve wholesale competition in regions with organized markets. These proposals reflect the record compiled by the Commission in its conferences and in comments to the ANOPR.

In proposing the reforms in the four areas described below, the Commission recognized that there are differences of opinion on the appropriate scope of this rulemaking, as well as on the four specific issues described in the ANOPR. From the commencement of the Commission’s first technical conference in this proceeding, its goal has been to identify any specific reforms that can be made to strengthen organized markets and to adopt them on a timely basis to benefit consumers. As the Commission explains in the NOPR, this proceeding does not represent the final effort to strengthen competitive markets. Rather, FERC will continue to evaluate other specific reforms that may be necessary.

In the area of demand response and the use of market prices to elicit demand response, the Commission proposes several requirements for ISOs and RTOs. These proposals include requirements to: (1) accept bids from demand response resources in their markets for certain ancillary services, comparable to any other resources; (2) eliminate, during a system emergency, a charge to a buyer in the energy market for taking less electric energy in the real-time market than purchased in the day-ahead market; (3) permit an aggregator of retail customers (ARC) to bid a demand response on behalf of retail customers directly into the organized energy market; and (4) for RTOS and ISOs to modify their market rules, as necessary, to allow the market-clearing price to accurately reflect the value of energy, during periods of operating reserve shortage.

In the section on long-term power contracting, the Commission proposes that ISOs and RTOs be required to dedicate a portion of their web sites for market participants to post offers to buy or sell power on a long-term basis. This proposal is designed to promote greater use of long-term contracts through improving transparency among market participants.

In the area of improving market monitoring, the Commission proposes that each RTO and ISO provide its MMU with access to market data, resources and personnel sufficient to carry out its duties, and that the MMU (or the external MMU in a hybrid structure) report directly to the RTO or ISO board. In addition, the Commission proposes to require that the MMU’s functions include: (1) identifying ineffective market rules and recommending proposed rules and tariff changes; (2) reviewing and reporting on the performance of the wholesale markets to the RTO or ISO, the Commission, and other interested entities; and (3) notifying appropriate Commission staff of instances in which a market participant’s behavior requires investigation. The Commission also proposes expanding the list of recipients to receive MMU recommendations regarding rule and tariff changes, and broadening the scope of behavior to be reported to the Commission. The Commission further proposes to remove the MMU from tariff administration, require each RTO and ISO to include ethics standards for MMU employees in its tariff, and consolidate all its MMU provisions in one section of its tariff. The Commission also proposes expanding the dissemination of MMU market information to a broader constituency, with reports made on a more frequent basis, and reducing the time period before energy market bid and offer data are released to the public.

Finally, the Commission proposes to establish new criteria intended to ensure that an RTO or ISO is responsive to its customers and stakeholders. These principles will include: (1) inclusiveness; (2) fairness in balancing diverse interests; (3) representation of minority positions; and (4) ongoing responsiveness.

In each of these four areas, the Commission will require RTOs and ISOs to consult with their stakeholders and make a compliance filing that details why the entity’s existing practices comply with the final rule in this rulemaking, or the entity’s plans to attain compliance.

In the Notice of Proposed Rulemaking (NOPR), the Commission estimated that the annual burden associated with the information requirements contained in the proposed rulemaking to be 14,481 hours. This estimate was based on the number of RTO’s and ISO’s who file transmission tariffs with the Commission and the number of tasks that each RTO/ISO and their stakeholders will have to perform. As a result of the revisions of the requirements and the corresponding reporting burden of 14,481 hours, the hours will be added to the total hours associated with FERC-516 at the final rule stage. FERC-516 is currently approved through March 31, 2010.

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. Trade in bulk power markets as noted above, has continued to increase significantly and the nation's transmission grid is being used more heavily and in many new ways.

This has resulted on strains on traditional grid management which could no longer

support efficient and reliable systems necessary for the continued development of competitive energy markets. Also, there were indications of continued discrimination in providing transmission services by vertically integrated utilities to hamper the development of fully competitive energy markets. The Commission believed that additional steps were necessary to address grid management if fully competitive energy markets are to be achieved. Therefore, the Commission encouraged all transmission owning entities in the nation, including non-public utility entities, to place their transmission facilities under the control of appropriate regional transmission institutions in a timely manner.

On December 20, 1999, the Commission issued Order No. 2000 “Regional Transmission Organizations”. By adopting the final rule the Commission amended its regulations under the Federal Power Act to advance the formation of Regional Transmission Organizations. The regulations required that each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce makes certain filings with respect to forming and participating in an RTO.

The Commission codified the minimum characteristics and functions that a transmission entity must satisfy in order to be considered an RTO. The four characteristics required of an RTO are: Independence; Scope and Regional Configuration; Operation Authority; and Short-term Reliability. These characteristics are more fully described below.

• Independence: RTOs must be independent of market participants. By market participant, the Commission means any entity that, either directly or through an affiliate, sells or brokers electric energy, or provides transmission or ancillary services to the RTO unless the Commission finds that the entity does not have economic or commercial interests in an RTO.

•Scope and Regional Configuration. RTOs must serve a region of sufficient scope and configuration to permit the RTO to maintain reliability, effectively perform its required functions and support efficient and non-discriminatory power markets.

•Operational Authority. The RTO is required to be the security coordinator for its region. The Commission allows flexibility in how the RTO performs its security coordinator functions, and the Commission does not require the RTO to operate what traditionally has been thought of as a single control area for its region. However, it must perform the control functions required to satisfy the minimum characteristic and functions in a nondiscriminatory manner.

•Short-term Reliability. The RTO must have exclusive authority for maintaining short-term reliability on the grid that it operates. It must have exclusive authority for receiving, confirming and implementing all interchange schedules. It must have the right to order redispatch of any generator connected to the transmission facilities it operates, if necessary for the reliable operation of those facilities. When the RTO operates transmission facilities owned by other entities, it must have authority to approve all requests for scheduled outages.

As identified above, the Commission determined that independence is a required characteristic necessary for an RTO to prevent any undue discrimination and to bring benefits to market participants. In that respect, the Commission stated that an RTO’s decision-making process must be independent in both reality and perception.²⁹ The Commission did not believe that detailed guidance regarding governance structure was necessary given the early stage of RTO formation and the varying structures of governance among regional entities. Instead, the Commission required RTOs to have an “open architecture” so that the organization and its members would have the necessary flexibility to improve the structure, geographic scope, market scope, and operations of the organization. Although the Commission required that proposed changes continue to satisfy RTO minimum characteristics and functions,³⁰ open architecture allowed the original RTO design to evolve to reflect changes in member needs.

Since Order No. 2000 was issued, RTOs and ISOs have evolved. Given the size and complexity of RTOs and ISOs today, it is not surprising that tension has arisen between the goals of independent decision-making and responsiveness to stakeholders, as an RTO or ISO cannot satisfy every group on every issue. The RTO and ISO management and boards of directors face increasing difficulty (as well as increasing responsibility) in understanding the impact of their decisions on the various stakeholder classes. Attempting to accommodate stakeholders’ needs on each issue has been a difficult task borne by the boards and other employees of the RTOs and ISOs.

Creating a mechanism and process to enable the board to be responsive to the needs of stakeholders is critical to an independent governance structure. Moreover, it is necessary for customers and other stakeholders to have confidence in the decisions that come out of RTO and ISO processes. Similarly, management responsiveness to customers and stakeholders plays an important role in implementing the RTO and ISO policies and achieving its objectives in a manner that customers and other stakeholders perceive to be fair, balanced, and effective. The Commission proposes in this NOPR a set of criteria, for assessing the mechanism or process by which an RTO or ISO achieves board responsiveness to its members and customers.

In summary, the Commission is proposing reforms to improve the operation of organized wholesale electric power markets.³¹ Working to ensure the competitiveness of organized wholesale markets is an important part of the Commission’s mandate to ensure adequate and reliable service at just and reasonable rates.

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

This NOPR amends the Commission’s regulations to improve the operation of organized wholesale electric power markets. The objective of this proposed rule is to improve market design and competition in organized markets. Through this rule the Commission hopes to provide remedies by ensuring:

(1) that new criteria are established so RTOs and ISOs are responsive to their customers and stakeholders;

(2) improve market monitoring within RTOs and ISOs by requiring them to provide their Market Monitoring Units with access to market data and sufficient resources to perform their duties;

(3) transparency in the marketplace by requiring RTOs and ISOs to dedicate portions of their web sites so market participants can avail themselves of information concerning offers to buy or sell power on a long-term basis and

(4) require RTOs and ISOs to institute certain reforms in the demand response programs to remove several disincentives and barriers to provide for more efficient operation of markets while at the same time encouraging new technologies.

Filings by RTOs and ISOs would be made under Part 35 of the Commission’s regulations.

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 implementing this requirement, the Commission wanted to eliminate "rate pancaking"-- paying additional transmission charges every time a trade crosses a corporate boundary.

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 to 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.

In Order No. 890, the Commission reformed the open access transmission tariff (OATT) to ensure that it continues to provide nondiscriminatory access to transmission service. The Commission is now focusing on the compliance phase of OATT reform to ensure that it is implemented properly.³²

Without this information, the Commission would be unable to discharge its responsibility to approve or modify electric utility tariff filings and would delay the effective implementation of nationwide open access to transmission by wholesale electric customers. Failure to issue these requirements would prevent timely Commission determination and approval of just and reasonable rates, which in turn, would prevent public utilities and licensees from being fairly compensated for services rendered.

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. 614 (65 FR 18221, April 7, 2000) the Commission amended its regulations to streamline rate schedules sheet designation procedures for electric industry schedules.

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.

Non-conforming agreements, which are agreements for transmission, cost-based power sales and other generally applicable services that do not conform to an applicable standard form of agreement in a public utility’s tariff, must continue to be filed with the Commission for approval before going into effect. This category excludes unexecuted agreements and agreements that do not precisely match the applicable standard form of service agreement.

In RM01-5-000, (69 FR 43929, July 23, 2004), the Commission proposed to require that all tariffs and tariff revisions and rate change applications for public utility, natural gas pipeline, and oil pipeline industries, be filed electronically via software provided by the Commission. Upon the effective date of a final rule, the Commission will no longer accept tariff filings submitted in paper format. This effort is intended to improve the administrative convenience of the regulated entities, facilitate public access to the tariffs, improve the overall tariff management processes, and facilitate the Commission’s and the public’s analysis of proposed tariff changes and tariff fillings.

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.

This Final Rule amended the Commission’s regulations³³ to provide that all documents filed with the Commission may be submitted through the eFiling interface except for documents specified by the Secretary. The changes implemented in the eFiling Final Rule means that categories such as oversized documents and most confidential documents will be accepted via eFiling. However, at this time, there are principal exceptions, and they are tariffs, tariff revisions and rate change applications; some forms;³⁴ and documents that are subject to protective orders.

The Final Rulemaking became effective 30 days after publication in the Federal Register or December 24, 20007. However, implementation of eFiling 7.0 is anticipated to occur by March 3, 2008. The Secretary of the Commission will announce the implementation of the upgrade in advance and will also post filing instructions.

The Commission has already issued instructions specifying acceptable file formats for filings submitted on CD-ROM, DVD and other electronic media. These can be found at http://www.ferc.gov/help/submission-guide/electronic-media.asp. In addition, in some cases Commission staff has issued instructions applying to specific types of filings. Where there are no specifications for a particular type of filing, users must follow the Secretary’s instructions. At this time, the eFiling system will accept documents in their native formats. This will include both text or word processing documents, and other more specialized documents such as spreadsheets and maps. It will also accept text documents in searchable formats, including scanned documents that have been saved in searchable form. This same list will serve as the list of acceptable formats for eFiling 7.0. Submitters will be able to choose a suitable format from that list unless they are instructed otherwise in specific instances by regulation or by direction from Commission staff. Audio and video files will be accepted only in waveform audio format (.wav) for audio content and either audio-video interleave (.avi) or quicktime (.mov) files for video content, except where submitters are specifically instructed otherwise.

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.³⁵ At this time, however, the Commission will not accept tariff filings through the eFiling system. The eTariff rulemaking (see RM01-5-000 above) will remain the forum for addressing the electronic submission of tariff filings with tariff material. However, eFiling may be used to file material in tariff proceedings provided the filing does not contain tariff material. Examples include testimony filed as part of the hearing, Schedules G-1 through G-6,³⁶ and updated statements such as required by section 154.311 of the Commission’s regulations.³⁷ Also, Natural Gas Act Section 7 certificate filings with pro forma tariff sheets may be filed under this version of eFiling 7.0.

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 containing 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 rule. FERC does not believe that the NOPR would have a direct impact on small entities. 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.³⁸ 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.

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 NOPR. They will only be required to file once to amend their OATT to include the schedule. The required standardized 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 proposed program meets all of OMB's section 1320.5 requirements with the exception of part "d" thereof. Section 1320.5(d) limits the collection of data to an original and two copies of any document. The data provided under FERC-516 includes tariff sheets and rate schedules that would be filed by the respondents to comply with the provisions as indicated in Item A (1.). Currently an original and five copies are required to be submitted to the Commission. This is the minimum necessary to permit processing within the statutory time frame for Commission action. The original is routed to eLibrary for public viewing over the Commission's web site. One copy is distributed to the Public Reference and Files Maintenance Branch for public inspection in the Commission's Public Reference Room. An additional copy is distributed to the Office of General Counsel for legal review. Three copies are distributed to the Office of Energy Markets and Regulation for technical review by analysts in rate filings, rate investigations and financial analysis.

However, if the eTariff NOPR is adopted and electronic filing is put into place, this will eliminate the need for paper copies entirely for service agreements and transactional reports. During this transitional period, however, the traditional number of hard copies will still be needed for efficient processing of the data.

The Commission proposes to require that each RTO and ISO make certain filings

to amend their tariffs, in order to comply with the requirements in each area specified

in the NOPR, or that demonstrates that its existing tariff and market design already

satisfy the requirements. Specifically, the Commission proposed that:

•each RTO and ISO set forth all its provisions involving market monitoring in one section of its tariff, noting that in order for Market Monitoring Units to achieve transparency of function, the detailed obligations imposed upon them must be made clear and accessible, and also be subject to approval and enforcement by the Commission.

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

As noted above, the Commission has received both formal and informal comments from market participants indicating areas where competition in wholesale markets could be improved. In response to these comments and as noted above, the Commission held three public conferences in 2007 in order to gather more information on competition at the wholesale level and other related issues.

Based on the record compiled at these three conferences, the Commission issued an Advance Notice of Proposed Rulemaking (ANOPR) on June 22, 2007 to identify and implement improvements to specific aspects of organized wholesale markets. In the ANOPR, the Commission identified as noted above, four issues in organized market regions that were not being adequately addressed or under consideration in other proceedings.

Comments received on the ANOPR and made during technical conferences highlighted several potential problems with wholesale competition both inside and outside the organized market regions that are within the scope of this proceeding. In the ANOPR, the Commission noted that it was not addressing potential reforms outside the organized market regions, explaining that many of the important concerns discussed during the first technical conference (e.g., nondiscriminatory access to transmission, nondiscriminatory rules for power procurement) were already being addressed in other proceedings. Similarly, the Commission has chosen to limit this proceeding to four discrete areas involving wholesale competition within organized markets.

Several parties proposed to expand the scope of this proceeding beyond the four areas covered in the ANOPR. The Commission received a request from American Public Power Association (APPA), in its comments on the ANOPR, and a request from Association for the Advancement of Retired Persons (AARP), et al., a group consisting of 41 entities, for a large-scale investigation of the workings of organized markets with respect to their ability to produce just and reasonable rates. APPA and AARP, et al. stated that the current market system allows incumbent sellers (those power suppliers with older power plants) to make excess profits while disadvantaging certain power suppliers with new generation. APPA and AARP, et al. argued that this has resulted in increased cost to consumers without the corresponding benefit of new generation being built. APPA and AARP, et al. claim that the Commission has a responsibility under sections 205 and 206 of the FPA to investigate the workings of organized markets based on their allegations of unjust and unreasonable rates.

Commission’s response

The Commission acknowledges the concerns of APPA and AARP, et al.; however, it has declined to initiate the broad investigation APPA and AARP, et al. have requested as part of this proceeding. As noted above, by listening to the concerns of market participants, and evaluating the record of this proceeding, the Commission has identified four specific areas in which reforms can improve wholesale electricity market operations. Through the competition conferences and the ANOPR process, the Commission has developed a solid record in favor of making those reforms, and a strong sense of what the Commission can do to be helpful in these four areas. It is important that the Commission move forward with regard to the specific reforms under consideration in this proposed rulemaking to foster improvements in the near term to the competitive operation of existing organized markets administered by RTOs and ISOs.

In contrast to the specific reforms proposed in the NOPR, APPA and AARP, et al. requests a broad, generic inquiry into alleged (but not specified) market design flaws. Their request not only fails to offer any specific solutions, but also fails to appreciate the differences in market design that exist in each region. Over the past five years, the Commission has undertaken significant market design reforms in most regions. The Commission has not adopted a standard market design, but rather has undertaken different reforms, at different times in each region to reflect the differing characteristics of each market.

Responsiveness of RTOs and ISOs to Stakeholders and Customers

In this section of the NOPR, the Commission proposes to establish new criteria intended to ensure that an RTO or ISO board is responsive to the RTO’s or ISO’s customers and other stakeholders. These criteria will include: (1) inclusiveness; (2) fairness in balancing diverse interests; (3) representation of minority positions; and (4) ongoing responsiveness. The Commission proposes to require each RTO or ISO to submit a compliance filing demonstrating that it has in place or will adopt practices and procedures to ensure that it is responsive to stakeholders and customers. In the compliance filing, the Commission encourages each RTO or ISO to evaluate what practices and procedures may best satisfy the responsiveness criteria.

In the ANOPR, the Commission made a preliminary proposal to improve responsiveness of RTO and ISO boards of directors to customers and other stakeholders. By responsiveness, the Commission means an RTO or ISO board’s willingness, as evidenced in its practices and procedures, to directly receive concerns and recommendations from customers and other stakeholders, and to fully consider and take actions in response to the issues that are raised. The Commission also sought comment on several issues focusing on whether and how RTO and ISO responsiveness to stakeholders can be improved, including management practices and stakeholder participation in the budgeting process.

In Order No. 888, the Commission encouraged but did not require the formation of ISOs, delineating eleven principles defining the operations and structure of a properly functioning ISO.³⁹ Similarly, in Order No. 2000, the Commission encouraged utilities to join RTOs voluntarily and set out the characteristics that an RTO must possess and the minimum functions that it must perform.⁴⁰ Embodied in Order Nos. 888 and 2000 is the requirement that the regional transmission entity be independent from market participants.

In Order No. 890, the Commission reformed the open access transmission tariff (OATT) to ensure that it continues to provide nondiscriminatory access to transmission service. Among other things, Order No. 890 requires an open and transparent regional transmission planning process.⁴¹ The Commission is now focusing on the compliance phase of OATT reform to ensure that it is implemented properly.⁴² The Commission also has been pursuing a cooperative dialogue with the National Association of Regulatory Utility Commissioners (NARUC) to identify and analyze models for competitive power procurement. This effort is designed to enhance the ability of load-serving entities (LSEs) to acquire reliable power supplies at competitive prices. As noted in the ANOPR, the Commission has also acted to investigate demand response in organized markets, through a Commission report and a recent technical conference. This conference was designed to examine demand response resources in markets, grid operations and expansion, and best practices for the measurement and evaluation of demand response resources.⁴³ The Commission also held a technical conference on December 11, 2007 to explore issues surrounding the management of interconnection queues.⁴⁴

Deviation Charge

Preliminary Proposals in the ANOPR

In the ANOPR, the Commission stated that it was considering a proposal to modify RTO and ISO tariffs to eliminate, during a system emergency, a charge to a buyer in the energy market for taking less electric energy in the real-time market than purchased in the day-ahead market.⁴⁵

The Commission requested comment on whether an RTO or ISO should assess a deviation charge for a day-ahead to real-time load reduction in the absence of a system emergency. The Commission noted that eliminating the deviation charge might have unintended consequences and asked whether it would result in an unfair reallocation of these costs to others; whether it was important to retain the deviation charge to discourage poor scheduling practices; or whether eliminating the deviation charge would introduce opportunities for gaming behavior.

The vast majority of commenters support the preliminary proposal in the ANOPR to modify RTO and ISO tariffs to eliminate a deviation charge during a system emergency.⁴⁶ For instance, APPA asserted that it does not make much sense to penalize entities that help the RTO alleviate a system emergency.⁴⁷ SMUD stated that eliminating penalties for load reductions during a system emergency is a sensible approach to promoting further development of demand response as a resource eligible to be bid into organized markets.⁴⁸

Several supporters prefer allowing RTOs and ISOs the flexibility to establish rules for settling deviations. For example, SoCal Edison-SDG&E believe each RTO or ISO is different, and that allowing each region to determine specific deviation charges based on individual circumstances may make more sense than adopting uniform standards. In their opinion, such an approach would help mitigate any unintended consequences, such as gaming.⁴⁹

Other commenters who disagreed with the Commission’s preliminary proposal are concerned about the uplift costs resulting from the elimination of deviation charges. DC Energy argues that eliminating the deviation charge penalty for demand response participants would negatively impact the market and result in unfair cost reallocation.⁵⁰ It maintains that such elimination would create two classes of market participants and have a deleterious affect on the market by inefficiently and unfairly reallocating costs to others.

Two commenters raised concerns about the applicability of the proposal to virtual bidding.⁵¹ APPA and the Connecticut and Massachusetts Municipals worried that virtual bidders may engage in market manipulation. Connecticut and Massachusetts Municipals argued that virtual bidders’ virtual load in the day-ahead market may create the appearance of a shortage even without corresponding real-time load. Therefore, the Commission should tailor any deviation exemption to apply to physical loads only.⁵² APPA agreed.⁵³

Suppliers predominantly support the Commission’s additional ANOPR proposal to eliminate deviation charges absent system emergencies. These commenters argued that any load reduction, during either a system emergency or non-emergency, would benefit all loads in RTOs and ISOs through greater market efficiency. Other commenters, including the RTOs and ISOs, however, opposed this proposal. Arguments against eliminating deviation charges for non-emergency periods include concerns about potential gaming and inaccurate scheduling. APPA stated that in order to ensure accurate schedules and cost accountability, deviation charges should remain in place absent a system emergency.⁵⁴ EEI argued that the elimination of this charge during non-emergencies “sends the wrong price signal to market participants, provides a disincentive to minimize deviations, and leads to increased costs to the market.”⁵⁵ PJM stated that little reliability value is associated with load reductions during non-emergencies, and therefore waiving the deviation charges is not justified, particularly when costs would have to be collected through a socialized uplift charge.⁵⁶

Commission Response

The Commission proposes to require that all RTO and ISO tariffs be modified to eliminate a charge, which we refer to as a deviation charge,⁵⁷ to a buyer⁵⁸ in the energy market for taking less electric energy in the real-time market during a real-time market period for which the RTO or ISO declares an operating reserve shortage or makes a generic request to reduce load to avoid an operating reserve shortage.

An RTO or ISO must either propose amendments to its tariff to comply with the proposed requirement or demonstrate that its existing tariff and market design already satisfy the requirement to eliminate the deviation charge during a system emergency. This filing would be submitted within six months of the date the final rule is published in the Federal Register. The Commission will assess whether each filing satisfies the proposed requirement and will issue additional orders as necessary.

Commenters supporting this proposal make sound arguments for it. The Commission agrees that removal of this deviation charge during a system emergency would remove a disincentive for greater demand response in the real-time market. A buyer may be deterred from reducing load during periods when supplies are tight and the real-time price is high if that buyer is subject to a charge for reducing its real-time consumption from its day-ahead purchases. If that buyer takes the appropriate action to reduce load and is accordingly penalized by a deviation charge, this unintended disincentive may lead the buyer to maintain a high load or discourage an LSE from calling on the demand response capabilities of its retail customers. Removal of this disincentive is important during a system emergency when load reduction is needed (and valued) most.

RTO and ISO tariffs already contain provisions associated with the dispatch of generators during real time, and specify payments and deviation charges for uninstructed deviations. During system emergencies, all available generation resources are instructed to increase output if possible. Because these units are instructed to increase output, RTO and ISO tariffs do not impose deviation charges on generators that generate more power during system emergencies than scheduled. Elimination of deviation charges for demand response by buyers ensures comparability between demand and supply resources.

As noted above, although a majority of commenters expressed support for this proposal, a significant number appear to misunderstand it. For example, some commenters appear to believe that the Commission proposed to remove any penalty for a day-ahead bidder of demand response who fails to reduce demand in real time, and oppose this idea as discriminating in favor of a demand response provider. Accordingly, the Commission provides two clarifications. First, this proposal applies to demand response that is in addition to the demand response of participants in RTO/ISO wholesale demand response programs. If demand response program participants reduce demand as directed, RTOs and ISOs already do not levy a deviation charge. The Commission is not proposing to remove any penalty for a day-ahead bidder of demand response who fails to follow directions to reduce demand in real time. This proposal focuses on demand response from Load Serving Entities (LSEs) and other buyers that consume less total energy in real time during system emergencies than they had scheduled in the day-ahead market.⁵⁹ Second, deviation charges would be eliminated only when the RTO or ISO announces an emergency situation after the close of the day-ahead market. The RTO or ISO could inform buyers either by instituting formal procedures that direct LSEs and electric utilities to activate retail demand response programs during a system emergency or by requesting voluntary load reductions, which may occur prior to or at the same time that a system emergency is declared. This is intended to ensure that buyers are not penalized when they voluntarily reduce load to improve system reliability at the request of a system operator.

In response to concerns that eliminating the deviation charge during a system emergency would result in an unfair allocation of the uplift costs or the creation of an unfair subsidy to demand response, we recognize that a deviation charge covers real costs to generators and others. These costs include those associated with the extra generation committed after the close of the day-ahead market that are not recovered from sales of energy in real time. Since demand response during system emergencies can be instrumental in maintaining system reliability and reducing overall energy prices, the Commission proposes that these costs be allocated to all loads of the RTO or ISO.

The Commission’s proposal to eliminate deviation charges during a system

emergency applies to physical load reductions. With regard to virtual purchases, we believe that, during an emergency, these day-ahead purchases may not cause unneeded generation to be committed to the market because an emergency by its nature is a time when the system is short of generation. As a result, the Commission believes that virtual purchasers may not cause significant additional costs during an emergency. Indeed, virtual purchases may enhance reliability by increasing the amount of generation resources available in real time during a system emergency. Assessing a deviation charge on virtual purchasers during an emergency may be unfair and may discourage helpful virtual bidding. Some commenters contend that virtual purchases add to system costs but do not address whether they add to costs during an emergency situation when the system is short of generation. The Commission seeks comment on whether to require RTO and ISO tariffs to be modified to eliminate deviation charges for virtual purchasers during system emergencies.

The Commission does not propose to modify RTO and ISO tariffs to eliminate deviation charges absent a system emergency, in light of the comments we received regarding this ANOPR proposal. The Commission is concerned about the resulting possibility of market manipulation and inefficiencies if deviation charges are removed, as raised by several commenters. Given the reliability value associated with demand response during system emergencies, socialization of related uplift costs is supportable.

Tariff Provisions

Preliminary Proposals in the ANOPR

The Commission proposed that each RTO and ISO set forth all its provisions involving market monitoring in one section of its tariff, noting that in order for Market Monitoring Units (MMUs) to achieve transparency of function, the detailed obligations imposed upon them must be made clear and accessible, and also be subject to approval and enforcement by the Commission.

There was widespread support for this proposal, although some commenters proposed that non-substantive MMU provisions be posted instead on the RTO or ISO web site.⁶⁰ Duke Energy proposed that the RTO or ISO be allowed to perform centralization of the tariff provisions the next time it makes an amendment to its market monitoring rules.⁶¹ The PJM MMU proposed that MMU provisions be included elsewhere in the tariff as well as in the MMU section, if the context so requires.⁶²

Commission Response

In accordance with the bulk of the comments on this subject, the Commission proposes that the RTOs and ISOs be required to include in their tariffs, and centralize in one section, all their MMU provisions. Including all MMU provisions in the tariff will ensure they are subject to the compliance requirements that attach to tariff provisions, and will give notice to interested parties, and thus an opportunity to intervene, when a tariff filing is made. As noted in the ANOPR, centralization of the MMU provisions has the obvious advantage of clarity and ease of reference. The Commission also proposes that the RTOs and ISOs include a mission statement for the MMU in the introductory portions of the section. This statement should set forth the goals to be achieved by the MMU, including the protection of both consumers and market participants by the identification and reporting of market design flaws and market power abuses.

The Commission disagrees with the comment requesting that the RTOs or ISOs be permitted to delay centralization until such time as they may choose, or otherwise be required, to make an amendment to their MMU rules. Such amendments will in all likelihood be required after issuance of a final rulemaking in this proceeding, and in any event the requirement should not be unduly onerous. Therefore, the Commission proposes that the RTOs and ISOs centralize their MMU tariff provisions when they make their compliance filings in connection with this proceeding. The Commission also sees no reason to forbid the RTOs and ISOs from posting MMU provisions elsewhere in their tariffs as well as in their MMU sections, should clarity and context so require, as long as appropriate cross-referencing is made.

Information Sharing

The Commission advanced proposals in the ANOPR that responded to requests of commenters at the technical conference for dissemination of expanded market information, and to a broader group of recipients. In particular, given the integral relationship between wholesale and retail rates, the Commission acknowledged the need for information by state commissions to assist them in performing their regulatory functions. However, the Commission noted that since public disclosure of certain information could harm market participants or could facilitate collusion under some circumstances, it was necessary to balance the need for information access with confidentiality concerns. The Commission solicited comments on the proposed changes.

Enhanced Information Dissemination

Preliminary Proposals in the ANOPR

The Commission proposed enhancing the dissemination of information in several areas. Specifically, the Commission proposed that MMUs be required to report comprehensively on aggregate market and RTO/ISO performance on a regular basis, but no less frequently than quarterly, to Commission staff, to staff of interested state commissions, and to the management and board of directors of the RTOs or ISOs. Further, the Commission proposed that MMUs should be required to deliver materials supporting their conclusions; make one or more of their staff members available for a conference call with representatives from the Commission, state commissions, and RTO or ISO; and work cooperatively to develop any further materials which might be useful to the Commission, to the state commissions and to the RTOs or ISOs.⁶³ Finally, the Commission proposed that offer and bid data, without identification of the market participants and with a lag of three months, be posted on the RTO or ISO web site.

The Commission requested comment on whether the proposal met the needs of the state commissions and whether there were other kinds of information needed by state commissions to fulfill their regulatory responsibilities. The Commission further solicited comment on whether there was a generic standard or test that could be used to determine what specific information should be provided to state commissions.

No comments were received proposing a generic standard or test to determine the specific information that should be provided to state commissions. There were relatively few comments identifying specific types of data needed;⁶⁴ rather, most commenters supporting greater access argued that state agencies should receive all available market information in order to assist them in their regulatory tasks.⁶⁵

There was substantial support for the proposal to require quarterly reports and conference calls.⁶⁶ Some commenters, however, thought comprehensive reports would be too costly and unduly time consuming.⁶⁷ Pepco suggested that these quarterly reports not be as extensive as the current annual reports, in order to avoid an excessive drain on the money and resources of the MMUs.⁶⁸ There was also concern that confidentiality protections be observed.⁶⁹ At least one commenter suggested that state attorneys general be included in the process as well as state commissions, since not all energy providers and consumers are associated with entities regulated by state commissions.⁷⁰ Some commenters, although recognizing that inclusion of market participants in conference calls would be unwieldy, proposed that they be included in the dissemination of the reports.⁷¹

There was substantial comment on the proposal to reduce the lag period for offer and bid data to three months, with a majority either favoring the Commission’s proposal or not actively opposing it.⁷² Some commenters stated that the lag period should be even shorter than three months, arguing that such information is released in Australia and the United Kingdom in close to real time, with no apparent adverse effects.⁷³ Others favored retention of the six-month period.⁷⁴ There was substantial support for something slightly longer than three months, in order to avoid the problem of data release within the same season; such release, it was argued, would provide opportunities for collusion and market power abuse.⁷⁵ EEI noted that different RTOs and ISOs have reached differing conclusions as to the appropriate lag time, and suggested that the Commission take into account regional differences, with a lag time no greater than six months and no less than three months.⁷⁶

Some commenters argued that masking the identity of the participants harmed the smaller players, contending that the larger players already have software programs which enable them to ascertain the identities of the participants.⁷⁷ OPSI supported maintaining confidentiality by the aggregation of cost data,⁷⁸ and Reliant argued that bidding data should be masked to avoid matching offers with the known output of the plant in question, thereby revealing the identity of the participant.⁷⁹

Commission Response

The Commission declines to propose a generic standard or test to determine the type of information that may be disseminated to state commissions. Inasmuch as there was no support for such a standard, the Commission believes the type of information to be released may most fruitfully continue to be developed on a case-by-case basis, so long as it generally consists of market analyses of the type regularly gathered by the MMUs in the course of business, and so long as it remains subject to appropriate confidentiality restrictions.

The Commission proposes that market participants be included in the dissemination of reports, which could be accomplished via posting them on the RTO or ISO web site. However, the Commission agrees that including market participants on conference calls would be unwieldy, and proposes limiting participation on such calls to Commission staff, RTO and ISO staff, staff of interested state commissions, and staff of state attorneys general should they express a desire to attend.

The Commission agrees that quarterly reports should not be as extensive as the annual state of the market reports. Preparing overly extensive reports would divert the attention of the MMUs from their tasks of daily monitoring and of providing recommendations to the RTO or ISO and the Commission regarding desirable rule and tariff changes. The Commission also believes that the annual state of the market reports have proven to be useful documents, and proposes that the RTOs and ISOs include in their tariffs a requirement for the MMUs to produce them, with the same dissemination (or broader, if desired) as the quarterly reports.

The Commission is persuaded by the comments that no harm generally would result from shortening the current six-month lag period.⁸⁰ However, the Commission acknowledges that in some instances release of such information in the same season could afford opportunities for collusion.⁸¹ Therefore, the Commission proposes that the time period for the release of offer and bid data be reduced to three months, but that the RTO or ISO may propose a shorter period, with accompanying justification. However, if the RTO or ISO demonstrates a potential collusion concern, it may propose a four-month lag period or, alternatively, some other mechanism to delay the release of a report if the release were otherwise to occur in the same season as reflected in the data.

The Commission proposes retaining the practice of masking the identity of participants when releasing offer and bid data. The possibility raised by a few commenters that some players may be able to surmise the identity of participants argues, if anything, for further protection, not for less. The Commission further proposes that the RTO or ISO include in its compliance filing a justification of its policy regarding the aggregation or lack thereof of offer data and of cost data, discussing the manner in which it believes its policy avoids participant harm and the possibility of collusion, while fostering market transparency.

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.

12. ESTIMATED BURDEN ON COLLECTION OF INFORMATION

Data Collection	Number of Respondents	Number of Responses.	Hours Per Response	Total Annual Hours
FERC-516
Task
Allow demand response to provide certain ancillary services	6	1	433	2,598
Remove certain deviation charges	5	1	288	1,440
Permit aggregation of Retail Customers	6	1	102.5	615
Allow pricing to ration demand during a shortage	6	1	649	3,894
Long-term contract postings	6	1	30	180
MMUs	6	1	129	774
Require RTO board responsiveness to customers	6	1	180	1080
Require RTO self-assessment	6	1	650	3,900
Totals				14,481 hours

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

Total hours for performing tasks 1 through as identified above = 14,481 hours.

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

must comply with the requirements of the NOPR. These requirements are a

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

13. ESTIMATED OF THE TOTAL COST BURDEN TO RESPONDENTS

The Commission is using 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 NOPR (Senior and support staff, information technology, engineering and legal staff). In addition, the Commission has factored in traveling and accommodation costs for the stakeholders in each RTO/ISO who will be participating in sessions to formulate the proposed rules and procedures for each RTO/ISO. It has projected the average annualized cost to be:

Legal expertise = $ 473,526 (2,368 hours @$200 an hour)

Technical Expertise = $ 712,038 (4,747 hours @$150 an hour)

(RTO/ISO Senior Staff, Stakeholder participants)

Administrative Support = $ 108,701 (2,718 hours @$40 an hour)

IT Support = $ 236,448 (2,489 hours @$95 an hour)

Participatory Expenditures = $2,160,000 (96 participants @$1,000 per day on average 4.5 days per activity for five of the eight activities identified above)

Total = $3,690,713

*differences in RTO/ISO staff hourly rates are to differentiate between administrative support staff and senior staff.

13. ESTIMATED ANNUALIZED COST TO THE FEDERAL GOVERNMENT

The costs to the Commission are estimated to be $379,152 (3 FTEs (full time equivalent employees x $126,384).

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

The Commission is issuing this NOPR to strengthen competition in the organized wholesale regional power markets, by issuing a proposed rule to improve demand response, encourage long term contracting, enhance the responsiveness of regional transmission organizations, and clarify the role of market monitors.

The Commission is acting because it recognizes that:

• competition is national policy in wholesale power markets, as reflected in three federal laws enacted has progressed over the past 25 years.

• it has a duty to improve the competitiveness of wholesale power markets, to use the regulatory tools Congress has given it to make competition more effective.

The reforms the Commission proposes are only the latest in a series of reforms FERC has taken to promote competition in wholesale power markets. In the past year alone it reformed its open access transmission tariff to improve grid access by competitors, and reformed its market based rate program to prevent the exercise of market power.

The Commission seeks steady reform to strengthen wholesale competition, encourage generation entry, improve market access and grid access, establish good market rules, prevent market power exercise and market manipulation, assure effective enforcement, improve market transparency, provide contract certainty, reinforce the power grid, and improve demand response.

See Background section above for further discussion.

13. TIME SCHEDULE FOR THE PUBLICATION OF DATA

Schedule for Data Collection and Analysis

Tariff Amendment Filed 60 days after publication in Federal Register

Initial Commission Order 60 days

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. If the proposed requirements of RM01-5-000, the electronic filing electric, gas and oil tariffs (see item no. 3 above) are adopted, the control numbers for these information collections will be displayed on the instructional manual to be 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.).

1. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS.

This is not a collection of information employing statistical methods.

1 Pub. L. No. 109-58, 119 Stat. 594 (2005).

2 National Association for the Advancement of Colored People v. FPC, 520 F.2d

432, 438 (D.C. Cir. 1975), aff’d, 425 U.S. 662 (1976).

3 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.

4 See The Electric Energy Market Competition Task Force, Report to Congress on Competition in Wholesale and Retail Markets for Electric Energy, Docket No. AD05-17-000, at 22 (April 2007).

5 15 U.S.C. §§ 79a et seq. (2000).

6 Pub. L. No. 102-486, 106 Stat. 2776 (1992).

7 16 U.S.C. § 824e (2000).

8 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, FERC Stats. & Regs., Regulations Preambles January 1991-June 1996 ¶ 31,036 (1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,048 (1997), 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, remanded in part on other grounds subnom. Transmission Access Policy Study Group, et al. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 US 1 (2002).

9 U.S. Department of Energy, Energy Information Administration, Status of State

Restructuring of the Electric Power Industry, at

http://www.eia.doe.gov/cneaf/electricity/epar1/state.html.

10 Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs.

¶ 31,089 (1999), order on reh'g, Order No. 2000-A, FERC Stats. & Regs ¶ 31,092 (2000), aff’d sub nom. Pub. Util. Dist. No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).

11 See Order No. 2000, FERC Stats. & Regs., Regulations Preambles July 1996-

December 2000 ¶ 31,089 at 31,028.

12 The Commission has approved RTOs or ISOs in several regions including the

Northeast (PJM, NYISO, and ISO-NE), California (CAISO), the Midwest (Midwest ISO) and the Southwest (SPP).

13 RTOs and ISOs currently operate various combinations of the following

organized markets: energy markets (day-ahead and real-time balancing markets),

transmission rights, installed capacity markets, and other ancillary services markets.

14 See Platts Research and Consulting/RDI, Review and Assessment of New

Competitive-Market Sources of Power Generation (February 5, 2003); Paul L. Joskow

February 27, 2007 Comments, Docket No. AD07-7-000; New England Power Generators

Association. Inc., Meeting New England’s Supply Needs: Regulated vs. Unregulated

Generation, at http://www.nepga.org/contents/factsheet9041006.pdf

15 U.S. Department of Energy, Energy Information Administration, Electric Power

Annual 2005, Table 2.1 (November 2006), at http://www.eia.doe.gov/cneaf/electricity/epa/epat2p1.html

16 North American Electric Reliability Corporation, Generating Availability

Report (November 2006).

17 Michael Skelly February 27, 2007 Comments, Docket No. AD07-7-000, at 1

(submitted on behalf of Horizon Wind Energy and the American Wind Energy

Association) (reporting that “[w]ell-structured regional wholesale electricity markets operated independently allow far greater amounts of renewable energy and demand response resources to be integrated into the nation’s electric grid. In fact, approximately 73 percent of installed wind capacity is now located in regions with such markets, while only 44 percent of wind energy potential is found in these areas. Large, regional energy markets provide for cost-effective balancing of generation and load with significant penetrations of variable, nondispatchable power sources, and they facilitate delivery of resources remote from load centers.”)

18 See, e.g., ISO/RTO Council, The Value of Independent Regional Grid Operators

(November 2005), http://www.caiso.com/14c6/14c6c4291aa40.pdf

19 Stephen Harvey, Office of Enforcement, Federal Energy Regulatory

Commission, Presentation at the May 17, 2007 Commission Meeting: 2007 Summer Energy Market Assessment (May 17, 2007) (Summer Market Assessment), at http://www.ferc.gov/EventCalendar/Files/20070517112506-A-3.pdf

20 See Id. See also U.S. Department of Energy, Energy Information

Administration, U.S. Natural Gas Wellhead Price, at http://tonto.eia.doe.gov/dnav/ng/hist/n9190us3a.htm.

21 See Summer Market Assessment. These NYMEX and ICE prices are not

estimates but prices actually produced on those two trading systems.

22 Id.

23 See Second Supplemental Notice of Conference, Conference on Competition in Wholesale Power Markets, Docket No. AD07-7-000 (Feb. 26, 2007).

24 See Notice of Agenda for the Conference, Review of Market Monitoring Policies, Docket No. AD07-8-000 (Mar. 30, 2007).

25 See Supplemental Notice of Conference, Conference on Competition in Wholesale Power Markets, Docket No. AD07-7-000 (Apr. 19, 2007).

26 Wholesale Competition in Regions with Organized Electric Markets, Advance Notice of Proposed Rulemaking, 72 Fed. Reg. 36,276 (July 2, 2007), FERC Stats. & Regs. ¶ 32,617 (2007).

27 The Commission did not summarize in the NOPR every comment received in response to the ANOPR. The Commission has reviewed and considered each comment submitted in to this proceeding.

28 16 U.S.C. § 824d - 824e (2000).

29 Order No. 2000, FERC Stats & Regs. ¶ 31,089 at 31,061.

30 Id. at 31,170.

31 Organized market regions are areas of the country in which a regional transmission organization (RTO) or independent system operator (ISO) operates day-ahead and/or real-time energy markets.

32 ANOPR, FERC Stats. & Regs. ¶ 32,617 at P 33 (citing 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)).

33 Rule 2003(c) of the Commission’s Rules of Practice and Procedure, 18 CFR 385.2003(c).

34 The following continue to be submitted through eForms: FERC Form No.1, FERC Form No. 2, FERC Form No. 2-A, FERC Form No. 3-Q, FERC Form No. 6, FERC Form No. 6-Q, Form 60, Form 714, and Electric Quarterly Reports. FERC Form 1-F is currently not included in eForms, so it may be efiled. Open Access Transmission Tariff (OATT) filings may also be efiled.

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

36 18 CFR 154.313(j)(2) (2007).

37 18 CFR 154.311 (2007).

38 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).

39 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, FERC Stats. & Regs. ¶ 31,036, at 31,730-32 (1996), order on reh’g, Order No. 888-A, 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).

40 Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 at 30,993.

41 This addresses, in part, concerns raised by some commenters regarding posting of future transmission constraints and congestion costs.

42 ANOPR, FERC Stats. & Regs. ¶ 32,617 at P 33 (citing 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, FERC Stats. & Regs. ¶ 31,261 (2007)).

43 Supplemental Notice, Demand Response in Wholesale Markets, Docket No. AD07-11-000 (April 6, 2007).

44 Notice of Technical Conference, Interconnection Queuing Practices, Docket No. AD08-2-000 (November 2, 2007).

45 The Commission noted that it would refer to the charge that it proposed to eliminate during an emergency as a “deviation charge.”

46 A number of commenters appear to misunderstand the proposal. Several did not distinguish a voluntary reduction in power purchase between day-ahead and real time (the intent here) from a demand response bidder that fails to deliver its accepted demand response.

47 APPA at 53.

48 SMUD at 4.

49 SoCal Edison-SDG&E at 2-3.

50 DC Energy at 4.

51 Virtual bidding, sometimes called “convergence bidding,” involves sales or purchases in the RTO or ISO day-ahead market that do not go to physical delivery. For example, an entity that does not serve load may make a purchase in the day-ahead market, which it must pay for, and then take no power in real time. This lack of consumption is treated as a sale of the power in the real-time spot market. By making virtual energy sales or purchases in the day-ahead market and settling these positions in the real-time market, any market participant can arbitrage price differences between the two markets.

52 Connecticut and Massachusetts Municipals at 40.

53 APPA at 53.

54 Id. at 54.

55 EEI at 17-19.

56 PJM at 7-8.

57 Deviation charges recover certain costs including importantly generators’ costs (such as start-up costs) that exceed their energy market revenues when real-time demand is less than forecast. These “uplift” costs may include the cost of the extra generators committed after the close of the day-ahead market that are not recovered from sales of energy at real-time LMPs.

58 Examples of buyers in RTO and ISO energy markets include a load serving entity that purchases electricity to meet the load requirements of its retail customers or a retail customer that purchases electricity directly from the wholesale market.

59 Note that under our proposal, if a demand response program participant reduces demand at greater levels than instructed during a system emergency, it will not be subjected to a deviation charge for the higher than instructed demand response.

60 EPSA at 46; Pepco at 19.

61 Duke Energy at 24.

62 PJM MMU at 17.

63 The Commission clarified that such reports and meetings were not intended to restrict the MMU from meeting individually with Commission staff, staff of state commissions, market participants, or other stakeholders, or sharing information with these various constituencies, subject to appropriate restrictions on confidentiality.

64 The California PUC set forth a lengthy list of desired market information, such as confidential and disaggregated data, bid data, generator dispatch data, generator performance data, unit commitment, scheduled and operational levels, and what units set clearing prices. It cautioned, however, that California’s needs are specific to its market design and structure as a single state ISO, and that data reporting protocols would vary from state to state. California PUC at 27-30.

65 See, e.g., FirstEnergy at 11; NARUC at 6; Massachusetts AG at 5; Joint Consumer Advocates at 22; New York PSC at 13.

66 See, e.g., BlueStar Energy at 6-7; Duke Energy at 26; Industrial Consumers at 37; NEPOOL Participants at 32; New England Conference at 19; North Carolina Electric Membership at 11; NRECA at 24; Old Dominion at 26.

67 EEI at 50; EPSA at 48; Mirant at 15; Duke Energy at 26.

68 Pepco at 19-20.

69 Constellation at 19; J. Aron, Barclays, Morgan Stanley at 6; Old Dominion at 26.

70 APPA at 84. See also LPPC at 15.

71 See, e.g., Old Dominion at 26.

72 See, e.g., Reliant at 22; PJM at 29; PSEG at 20; SMUD at 15; CAISO at 10; Connecticut and Massachusetts Municipals at 27; DC Energy at 9; Massachusetts AG at 5; Midwest ISO at 29; NEPOOL Participants at 33.

73 Industrial Consumers at 37-38; TAPS at 61.

74 See, e.g., Ameren at 42; Duke Energy at 26-27; Dynegy at 6; Industrial Coalitions at 24; NJBPU at 2; PJM MMU at 18.

75 See, e.g., Dynegy at 6; NJPBU at 2; OMS at 35; OPSI at 29; Old Dominion at 26.

76 EEI at 52-53.

77 Pennsylvania PUC at 18; TAPS at 62.

78 OPSI at 30. OPSI includes reference price or unit estimated cost data within the term.

79 Reliant at 22. Reliant used the term “bid data,” which the Commission assumes refers to offers, given the company’s concern over matching offers to unit output.

80 The Commission recently approved the request of ISO-NE and NEPOOL to shorten the lag time for release of ISO-NE offer and bid data from six months to roughly three months. ISO New England Inc. and New England Power Pool, 121 FERC ¶ 61,035 (2007) (ISO-NE Bid/Offer Order).

81 In the ISO-NE Bid/Offer Order, we found that the combination of ISO-NE’s ability to expeditiously file for a rule change if negative impacts on the market were experienced, and the existing tariff language that masks the bid/offer data, adequately protected against the risk of collusion.

10