# Regional Transmission Organizations; Notice of Proposed Rulemaking > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A99-12553 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** June 10, 1999 - **Citation:** 64 FR 31390 ## Text SUMMARY: The Federal Energy Regulatory Commission (Commission) is proposing to amend its regulations under the Federal Power Act (FPA) to facilitate the formation of Regional Transmission Organizations (RTOs). The Commission proposes to require that each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce make certain filings with respect to forming and participating in an RTO. The Commission also proposes minimum characteristics and functions that a transmission entity must satisfy in order to be considered to be an RTO. DATES: Initial comments are due August 16, 1999. Reply comments are due September 15, 1999. ADDRESSES: Send comments to: Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, D.C. 20426. FOR FURTHER INFORMATION CONTACT: Alan Haymes (Technical Information), Office of Electric Power Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, D.C. 20426, (202) 219-2919. Wilbur C. Earley (Technical Information), Office of Economic Policy, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, D.C. 20426, (202) 208-0100 Brian R. Gish (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, D.C. 20426, (202) 208-0996 SUPPLEMENTARY INFORMATION: In addition to publishing the full text of this document in the Federal Register, the Commission also provides all interested persons an opportunity to inspect or copy the contents of this document during normal business hours in the Public Reference Room at 888 First Street, N.E., Room 2A, Washington, D.C. 20426. The Commission Issuance Posting System (CIPS) provides access to the texts of formal documents issued by the Commission from November 14, 1994, to the present. CIPS can be accessed via Internet through FERC's Home page (http://www.ferc.fed.us) using the CIPS Link or the Energy Information Online icon. Documents will be available on CIPS in ASCII and WordPerfect 6.1. User assistance is available at 202-208-2474 or by E-mail to [email protected]. This document is also available through the Commission's Records and Information Management System (RIMS), an electronic storage and retrieval system of documents submitted to and issued by the Commission after November 16, 1981. Documents from November 1995 to the present can be viewed and printed. RIMS is available in the Public Reference Room or remotely via Internet through FERC's Home page using the RIMS link or the Energy Information Online icon. User assistance is available at 202-208-2222, or by E-mail to [email protected]. Finally, the complete text on diskette in WordPerfect format may be purchased from the Commission's copy contractor, RVJ International, Inc. RVJ International, Inc. is located in the Public Reference Room at 888 First Street, N.E., Washington, D.C. 20426. Table of Contents I. Introduction and Summary II. Background A. The Foundation for Competitive Markets: Order Nos. 888 and 889 B. Developments Since Order Nos. 888 and 889 1. Industry Restructuring and New Stresses on the Transmission Grid 2. Successes, Failures and Haphazard Development of Regional Transmission Entities 3. The Commission's ISO and RTO Inquiries; Conferences with Stakeholders and State Regulators C. Statutory Framework III. Discussion A. Barriers to Assuring an Abundant Supply of Electric Energy throughout the U.S. with the Greatest Possible Economy 1. Engineering and Economic Inefficiencies in the Operation, Planning, and Expansion of Regional Transmission Grids 2. Actual and Perceived Discriminatory Conduct by Transmission Owners to Favor Their Own or Affiliated Merchant Operations B. Benefits That RTOs Can Offer 1. An RTO Would Improve Efficiencies in the Management of the Transmission Grid 2. An RTO Would Improve Grid Reliability 3. An RTO Would Remove Opportunities for Discriminatory Transmission Practices 4. An RTO Would Result in Improved Market Performance 5. An RTO Would Facilitate Lighter-Handed Governmental Regulation 6. Conclusion C. Concerns Expressed by the State Commissions 1. Federal Mandate 2. Regional Flexibility 3. Retail Markets 4. Effect on States With Low Cost Generation 5. Need for Independent Transmission Operation 6. Transmission Cost Shifting 7. Boundary Drawing 8. Regional Approach to Reliability 9. Pricing Reform 10. Participation of Public Power 11. State Role in RTO Governance 12. Existing Regional Transmission Entities D. Minimum Characteristics and Functions for a Regional Transmission Organization Minimum Characteristics 1. Independence 2. Scope and Regional Configuration 3. Operational Authority 4. Short-term Reliability Minimum Functions 1. Tariff Administration and Design 2. Congestion Management 3. Parallel Path Flow 4. Ancillary Services 5. OASIS and TTC and ATC 6. Market Monitoring 7. Planning and Expansion E. Open Architecture F. Ratemaking for Transmission Facilities under RTO Control 1. Single Transmission Access Rate for Capital Cost Recovery 2. Congestion Pricing 3. Performance Based Rate Regulation 4. Consideration of Incentive Pricing Proposals G. Public Power Participation in RTOs H. Other Issues 1. Pre-existing Transmission Contracts 2. Treatment of Existing Regional Transmission Entities 3. Participation by Canadian and Mexican Entities 4. Providing Service to Transmission-owning Utilities That Do Not Participate in an RTO 5. RTO Filing Requirements 6. Power Exchanges (PXs) I. Implementation of the Rule 1. Collaborative Process 2. Filing Requirements IV. Environmental Statement V. Regulatory Flexibility Act VI. Public Reporting Burden and Information Collection Statement VII. Public Comment Procedures Text of the Regulations Appendix A: Staff Summary of the FERC-Industry ISO Conferences Appendix B: Staff Summary of FERC Consultations With the States Appendix C: Existing Configurations I. Introduction and Summary In 1996 the Commission put in place the foundation necessary for [[Page 31391]] competitive wholesale power markets in this country--open access transmission.1 Since that time, the industry has undergone sweeping restructuring activity, including a movement by many states to develop retail competition, the growing divestiture of generation plants by traditional electric utilities, a significant increase in the number of mergers among traditional electric utilities and among electric utilities and gas pipeline companies, large increases in the number of power marketers and independent generation facility developers entering the marketplace, and the establishment of independent system operators (ISOs) as managers of large parts of the transmission system. Trade in bulk power markets has continued to increase significantly and the Nation's transmission grid is being used more heavily and in new ways. --------------------------------------------------------------------------- \1\ See Promoting Wholesale Competition Through Open Access Non- discriminatory Transmission Services by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, 61 FR 21540 (1996), FERC Stats. & Regs. para. 31,036 (1996) (Order No. 888), order on reh'g, Order No. 888-A, 62 FR 12274 (1997), FERC Stats. & Regs. para. 31,048 (1997), order on reh'g, Order No. 888-B, 62 FR 64688, 81 FERC para. 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC para. 61,046 (1998), appeal docketed, Transmission Access Policy Study Group, et al. v. FERC, Nos. 97-1715 et al. (D.C. Cir.). --------------------------------------------------------------------------- As a result, the traditional means of grid management is showing signs of strain and may be inadequate to support the efficient and reliable operation that is needed for the continued development of competitive electricity markets. In addition, there are indications that continued discrimination in the provision of transmission services by vertically integrated utilities may also be impeding fully competitive electricity markets. These problems may be depriving the Nation of the benefits of lower prices, more reliance on market solutions, and lighter-handed regulation that competitive markets can bring. If electricity consumers are to realize the full benefits that competition can bring to wholesale markets, the Commission must address the extent of these problems and appropriate ways of mitigating them. Competition in wholesale electricity markets is the best way to protect the public interest and ensure that electricity consumers pay the lowest price possible for reliable service. We believe that further steps may need to be taken to address grid management if we are to achieve fully competitive power markets. We further believe that regional approaches to the numerous issues affecting the industry may be the best means to eliminate remaining impediments to properly functioning competitive markets. Our objective is for 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. We seek to accomplish our objective by encouraging voluntary participation. We are therefore proposing in this rulemaking minimum characteristics and functions for appropriate regional transmission institutions; a collaborative process by which public utilities and non-public utilities that own, operate or control interstate transmission facilities, in consultation with the state officials as appropriate, will consider and develop regional transmission institutions; a willingness to consider incentive pricing on a case-specific basis and an offer of non-monetary regulatory benefits, such as deference in dispute resolution, reduced or eliminated codes of conduct, and streamlined filing and approval procedures; and a time line for public utilities to make appropriate filings with the Commission and initiate operation of regional transmission institutions. As a result, we expect jurisdictional utilities to form Regional Transmission Organizations (RTOs). As discussed in detail herein, regional institutions can address the operational and reliability issues now confronting the industry, and any residual discrimination in transmission services that can occur when the operation of the transmission system remains in the control of a vertically integrated utility. Appropriate regional transmission institutions could: (1) improve efficiencies in transmission grid management 2; (2) improve grid reliability; (3) remove the remaining opportunities for discriminatory transmission practices; (4) improve market performance; and (5) facilitate lighter handed regulation. --------------------------------------------------------------------------- \2\ Appropriate regional institutions could improve efficiencies in grid management through improved pricing, congestion management, more accurate estimates of Available Transmission Capability, improved parallel path flow management, more efficient planning, and increased coordination between regulatory agencies. --------------------------------------------------------------------------- Thus, we believe that appropriate regional transmission institutions could successfully address the existing impediments to efficient grid operation and competition and could consequently benefit consumers through lower electricity rates resulting from a wider choice of services and service providers. There are likely to be substantial cost savings brought about by regional transmission institutions. In light of important questions regarding the complexity of grid regionalization raised by state regulators and applicants in individual cases, we are proposing a flexible approach. We are not proposing to mandate that utilities participate in a regional transmission institution by a date certain. Instead, we act now to ensure that they consider doing so in good faith. Moreover, the Commission is not proposing a ``cookie cutter'' organizational format for regional transmission institutions or the establishment of fixed or specific regional boundaries under section 202(a) of the FPA. Rather, the Commission is proposing to establish fundamental characteristics and functions for appropriate regional transmission institutions. We will designate institutions that satisfy all of the minimum characteristics and functions as Regional Transmission Organizations (RTOs). Hereinafter, the term Regional Transmission Organization, or RTO, will refer to an organization that satisfies all of the minimum characteristics and functions. Pursuant to our authority under section 205 of the FPA to ensure that rates, terms and conditions of transmission and sales for resale in interstate commerce by public utilities are just, reasonable and not unduly discriminatory or preferential, and our authority under section 202(a) of the FPA to promote and encourage regional districts for the voluntary interconnection and coordination of transmission facilities by public utilities and non-public utilities for the purpose of assuring an abundant supply of electric energy throughout the U.S. with the greatest possible economy, we propose the following.3 --------------------------------------------------------------------------- \3\ The Commission's legal authority is discussed in Section II. --------------------------------------------------------------------------- First, the Commission proposes minimum characteristics and functions that an RTO must satisfy. Industry participants, however, retain flexibility in structuring RTOs that satisfy these characteristics and functions. For example, we do not propose to require or prohibit any one form of organization for RTOs or require or prohibit RTO ownership of transmission facilities. The characteristics and functions could be satisfied by different organizational forms, such as ISOs, transcos, combinations of the two, or even new organizational forms not yet discussed in the industry or proposed to the Commission. Second, we propose to adopt an ``open architecture'' policy regarding RTOs, whereby all RTO proposals must [[Page 31392]] allow the RTO and its members the flexibility to improve their organizations in the future in terms of structure, operations, market support and geographic scope to meet market needs. In turn, the Commission will provide the regulatory flexibility to accommodate such improvement. Third, we propose guidance on flexible transmission ratemaking that may be proposed by RTOs, including ratemaking treatments that will address congestion pricing and performance based regulation. We also propose to consider on a case-by-case basis incentive pricing that may be appropriate for transmission facilities under RTO control. Finally, all public utilities (with the exception of those participating in an approved regional transmission entity that conforms to the Commission's ISO principles) that own, operate or control interstate transmission facilities must file with the Commission by October 15, 2000 a proposal for an RTO with the minimum characteristics and functions adopted in the Final Rule,4 or, alternatively, a description of efforts to participate in an RTO, any existing obstacles to RTO participation, and any plans to work toward RTO participation. Each proposed RTO must plan to be operational by December 15, 2001. We expect that such proposals would include the transmission facilities of public utilities as well as transmission facilities of public power and other non-public utility entities to the extent possible. --------------------------------------------------------------------------- \4\ An RTO proposal includes a basic agreement filed under section 205 of the FPA setting out the rules, practices and procedures under which an RTO will be governed and operated, and requests by the public utility members of the RTO under section 203 of the FPA to transfer control of their jurisdictional transmission facilities from individual public utilities to the RTO. Most RTO proposals by public utilities are likely to involve one or more filings under FPA sections 203, 205, or 206, but the number and types of filing may vary depending upon the type of RTO proposed, and the number of public utilities involved in the proposal. Under the proposed rule, a utility may file a petition for a declaratory order asking whether a proposed transmission entity would qualify as an RTO, to be followed by appropriate filings under sections 203, 205 and/or 206. --------------------------------------------------------------------------- A public utility that is a member of an existing transmission entity that has been approved by the Commission as in conformance with the eleven ISO principles set forth in Order No. 888 must make a filing no later than January 15, 2001 that explains the extent to which the transmission entity in which it participates meets the minimum characteristics and functions for an RTO, or proposes to modify the existing institution to become an RTO. Alternatively, the public utility must file an explanation of efforts, obstacles and plans with respect to conforming to these characteristics and functions. Through the required filings, utilities will make known to the public any plans for RTO participation so that other utilities and the competitive market can respond accordingly. This proposal relies primarily on the enlightened self-interest of stakeholders in each region. Such public disclosure of plans for transmission facilities will benefit the industry, the financial community, and public policy makers as the electric industry restructuring continues. To facilitate RTO formation in all regions of the Nation, the Commission proposes to sponsor and support a collaborative process under section 202(a) to take place in the spring of 2000. Under this process, we expect that public utilities and non-public utilities, in coordination with state officials, Commission staff, and all affected interest groups, will actively work toward the voluntary development of specific RTOs. Prior to undertaking this proposed rulemaking, we held eight technical conferences in 1998 with all industry stakeholders as well as three technical conferences this year with state regulatory commissions to obtain their views on the need for, and benefits of, regional organizations. We gained valuable insight from the participants, including many state commissions that have undertaken or are considering state retail choice programs for the consumers in their states. In light of the comments received, we wish to respond to several concerns that were raised. First, we are not proposing to mandate RTOs, nor are we proposing detailed specifications on a particular organizational form for RTOs. The goal of this rulemaking is to get RTOs in place through voluntary participation. While this Commission has specific authorities and responsibilities under the FPA to protect against undue discrimination and remove impediments to wholesale competition, we believe it is preferable to meet these responsibilities in the first instance through an open and collaborative process that allows for regional flexibility and induces voluntary behavior. Second, the development of RTOs is not intended to interfere with state prerogatives in setting retail competition policy. The Commission believes that RTOs can successfully accommodate the transmission systems of all states, whether or not a particular state has adopted retail competition. However, for those states that have chosen to adopt retail wheeling, RTOs can play a critical role in the realization of full competition at the retail level as well as at the wholesale level. In addition, the Commission believes that RTOs will not interfere with a state's prerogative to keep the benefits of low-cost power for the state's own retail consumers. Third, we propose to allow RTOs to prevent transmission cost shifting by continuing our policy of flexibility with respect to recovery of sunk transmission costs, such as the ``license plate'' approach. Fourth, the existence of RTOs has not, and will not in the future, interfere with traditional state and local regulatory responsibilities such as transmission siting, local reliability matters, and regulation of retail sales of generation and local distribution. In fact, RTOs offer the potential to assist the states in their regulation of retail markets and in resolving matters among states on a regional basis. They also provide a vehicle for amicably resolving state and Federal jurisdictional issues. Finally, we do not propose to establish regional boundaries in this rulemaking. Our foremost concern is that a proposed RTO's regional configuration is sufficient to ensure that the required RTO characteristics and functions are satisfied. To this end, the Commission proposes guidance regarding the scope and regional configuration of RTOs. We now turn to the state of the electric utility industry in the wake of Order No. 888 and how the development of RTOs achieves efficient, reliable and competitive power markets. II. Background In April 1996, in Order Nos. 888 and 889, the Commission established the foundation necessary to develop competitive bulk power markets in the United States: non-discriminatory open access transmission services by public utilities and stranded cost recovery rules that would provide a fair transition to competitive markets. Order Nos. 888 and 889 were very successful in accomplishing much of what they set out to do. However, they were not intended to address all problems that might arise in the development of competitive power markets. Indeed, the nature of the emerging markets and the remaining impediments to full competition have become apparent in the three years since the issuance of our orders. A. The Foundation for Competitive Markets: Order Nos. 888 and 889 In Order Nos. 888 and 889, the Commission found that unduly discriminatory and anticompetitive [[Page 31393]] practices existed in the electric industry, and that transmission- owning utilities had discriminated against others seeking transmission access.5 The Commission stated that its goal was to ensure that customers have the benefits of competitively priced generation, and determined that non-discriminatory open access transmission services (including access to transmission information) and stranded cost recovery were the most critical components of a successful transition to competitive wholesale electricity markets.6 --------------------------------------------------------------------------- \5\ Order No. 888, FERC Stats & Regs. at 31,682. \6\ Id. at 31,652. --------------------------------------------------------------------------- Accordingly, Order No. 888 required all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to (1) file open access non-discriminatory transmission tariffs containing, at a minimum, the non-price terms and conditions set forth in the Order, and (2) functionally unbundle wholesale power services. Under functional unbundling, the public utility must: (a) take transmission services under the same tariff of general applicability as do others; (b) state separate rates for wholesale generation, transmission, and ancillary services; and (c) rely on the same electronic information network that its transmission customers rely on to obtain information about its transmission system when buying or selling power.7 Order No. 889 required that all public utilities establish or participate in an Open Access Same- Time Information System (OASIS) that meets certain specifications, and comply with standards of conduct designed to prevent employees of a public utility (or any employees of its affiliates) engaged in wholesale power marketing functions from obtaining preferential access to pertinent transmission system information. --------------------------------------------------------------------------- \7\ Id. at 31,654-55. --------------------------------------------------------------------------- During the course of the Order No. 888 proceeding, the Commission received comments urging it to require generation divestiture or structural institutional arrangements such as regional independent system operators (ISOs) to better assure non-discrimination. The Commission responded that, while it believed that ISOs had the potential to provide significant benefits, efforts to remedy undue discrimination should begin by requiring the less intrusive functional unbundling approach. Order No. 888 set forth eleven principles for assessing ISO proposals submitted to the Commission. 8 Order No. 888 also stated: \8\ Id. at 31,730. --------------------------------------------------------------------------- [W]e see many benefits in ISOs, and encourage utilities to consider ISOs as a tool to meet the demands of the competitive marketplace. As a further precaution against discriminatory behavior, we will continue to monitor electricity markets to ensure that functional unbundling adequately protects transmission customers. At the same time, we will analyze all alternative proposals, including formation of ISOs, and, if it becomes apparent that functional unbundling is inadequate or unworkable in assuring non-discriminatory open access transmission, we will reevaluate our position and decide whether other mechanisms, such as ISOs, should be required. 9 --------------------------------------------------------------------------- \9\ Id. at 31,655. --------------------------------------------------------------------------- In section III.A.2 of this Notice of Proposed Rulemaking, we discuss our experiences to date with functional unbundling. It has become apparent that several types of regional transmission institutions, in addition to the kinds of ISOs approved to date, may also be able to provide the benefits attributed to ISOs in Order No. 888. B. Developments Since Order Nos. 888 and 889 In the three years since Order Nos. 888 and 889 were issued, numerous significant developments have occurred in the electric utility industry. Some of these reflect changes in governmental policies; others are strictly industry driven. These activities have resulted in a considerably different industry landscape from the one faced at the time the Commission was developing Order No. 888, resulting in new regulatory and industry challenges. Order Nos. 888 and 889 required a significant change in the way many public utilities have done business for most of this century, and most public utilities accepted these changes and made substantial good faith efforts to comply with the new requirements. Virtually all public utilities have filed tariffs stating rates, terms and conditions for third-party use of their transmission systems. In addition, improved information about the transmission system is available to all participants in the market at the same time that it is available to the public utility as a result of utility compliance with the OASIS regulations. The availability of tariffs and information about the transmission system has fostered a rapid growth in dependence on wholesale markets for acquisition of generation resources. Areas that have experienced generation shortages have seen rapid development of new generation resources. For example, New England, where there was deep concern about adequacy of generation supply only three years ago, now has approximately 30,000 MW of generation proposed. That response comes almost entirely from independent generating plants that are able to sell power into the bulk power market through open access to the transmission system. Power resources are now acquired over increasingly large regional areas, and interregional transfers of electricity have increased. The very success of Order Nos. 888 and 889, and the initiative of some utilities that have pursued voluntary restructuring beyond the minimum open access requirements , have put new stresses on regional transmission systems--stresses that call for regional solutions. 1. Industry Restructuring and New Stresses on the Transmission Grid Open access transmission and the opening of wholesale competition in the electric industry have brought an array of changes in the past several years: divestiture by many integrated utilities of some or all of their generating assets; significantly increased merger activity both between electric utilities and between electric and natural gas utilities; increases in the number of new participants in the industry in the form of independent power marketers and generators; increases in the volume of trade in the industry, particularly as marketers make multiple sales; state efforts to create retail competition; and new and different uses of the transmission grid. With respect to divestiture, since August 1997, approximately 50,000 MW of generating capacity have been sold (or are under contract to be sold) by utilities, and an additional 30,000 MW is currently for sale. In total, this represents more than 10 percent of U.S. generating capacity. In all, according to publicly available data, 27 utilities have sold all or some of their generating assets and 7 others have assets for sale. Buyers of this generating capacity have included traditional utilities with specified service territories as well as independent power producers with no required service territory. Since Order No. 888 was issued, there have been more than 20 applications filed with us to approve proposed mergers involving public utilities. Most of these mergers have been approved by various regulatory authorities, including the Commission, although a few have been rejected or withdrawn, and several mergers are pending regulatory approval. Most of these merger proposals have been between electric utilities with contiguous service areas, while some of the proposed mergers have been between utilities with non- [[Page 31394]] contiguous service areas. The Commission has also been presented with merger applications involving the combination of electric and natural gas assets. There has been significant growth in the volume of trading in the wholesale electricity market. In the first quarter of 1995, according to power marketer quarterly filings, marketer sales totaled 1.8 million MWh, but by the second quarter of 1998, such sales escalated to 513 million MWh.10 Many new competitors have entered the industry. For example, in the first quarter of 1995, there were eight power marketers (either independent or affiliated with traditional utilities) actively trading in wholesale power markets, but by the second quarter of 1998, there were 108 actively trading power marketers. The Commission has granted market-based rate authority to well over 500 wholesale power marketers, of which some are independent of traditional investor-owned utilities, some are affiliated with traditional utilities, and some are traditional utilities themselves.11 --------------------------------------------------------------------------- \10\ Power marketer quarterly filings, cited in Staff Report to the Federal Energy Regulatory Commission on the Causes of Wholesale Electric Pricing Abnormalities in the Midwest During June 1998, (September 22, 1998) (Staff Price Spike Report) at 3-1 to 3-2. It must be noted that a significant portion of the sales represent the retrading of power by a number of different market participants. In other words, there may be multiple resales of the same generation. \11\ Id. at 3-1. --------------------------------------------------------------------------- State commissions and legislatures have been active in the past few years studying competitive options at the retail level, setting up pilot retail access programs, and, in some states, implementing full scale retail access programs. As of May 1, 1999, 18 states have enacted electric restructuring legislation, 3 have issued comprehensive regulatory orders, and 28 others have legislation or orders pending or investigations underway.12 Fifteen states have implemented full-scale or pilot retail competition programs that offer a choice of suppliers to at least some retail customers. Eight states have set in motion programs to offer access to retail customers by a date certain. --------------------------------------------------------------------------- \12\ ``Status of Electric Utility Deregulation Activity as of May 1, 1999,'' Energy Information Administration. --------------------------------------------------------------------------- Because of the changes in the structure of the electric industry, the transmission grid is now being used more intensively and in different ways than in the past. The Commission is concerned that the traditional approaches to operating the grid are showing signs of strain. According to the North American Electric Reliability Council (NERC), ``the adequacy of the bulk transmission system has been challenged to support the movement of power in unprecedented amounts and in unexpected directions.'' 13 These changes in the use of the transmission system ``will test the electric industry's ability to maintain system security in operating the transmission system under conditions for which it was not planned or designed.'' 14 It should be noted that, despite the increased transmission system loadings, NERC believes that the ``procedures and processes to mitigate potential reliability impacts appear to be working reliably for now,'' and that even though the system was particularly stressed during the summer of 1998, ``the system performed reliably and firm demand was not interrupted due to transmission transfer limitations.'' 15 --------------------------------------------------------------------------- \13\ Reliability Assessment 1998-2007, North American Electric Reliability Council (September 1998), at 26. \14\ Id. \15\ Id. --------------------------------------------------------------------------- An indication that the increased and different use of the transmission system is stressing the grid is the increased use of transmission line loading relief (TLR) procedures. 16 NERC's TLR procedures were invoked 250 times between January 1 and September 1, 1998 to prevent facility or interface overloads on the Eastern Interconnection. 17 --------------------------------------------------------------------------- \16\ The TLR procedures are designed to remedy overloads that result when a transmission line or other transmission equipment carries or will carry more power than its rating, which could result in either power outages or damage to property. The TLR procedures are designed to bring overloaded transmission equipment to within NERC's Operating Security Limits essentially by curtailing transactions contributing to the overload. See North American Electric Reliability Council, 85 FERC para. 61,353 (1998) (NERC). \17\ Reliability Assessment 1998-2007 at 27. --------------------------------------------------------------------------- It appears that the planning and construction of transmission and transmission-related facilities may not be keeping up with increased requirements. According to NERC, ``Business is increasing on the transmission system, but very little is being done to increase the load serving and transfer capability of the bulk transmission system.'' 18 The amount of new transmission capacity planned over the next ten years is significantly lower than the additions that had been planned five years ago, and most of the planned projects are for local system support. 19 NERC states that, ``The close coordination of generation and transmission planning is diminishing as vertically integrated utilities divest their generation assets and most new generation is being proposed and developed by independent power producers.'' 20 --------------------------------------------------------------------------- \18\ Id. at 26. \19\ Id. at 7. \20\ Id. --------------------------------------------------------------------------- The transition to new market structures has resulted in new challenges and circumstances. For example, during the week of June 22- 26, 1998, the wholesale electric market in the Midwest experienced numerous events that led to unprecedented high spot market prices. Spot wholesale market prices for energy briefly rose as high as $7,500 per MWh, compared to an average price for the summer of approximately $40 per MWh in the Midwest if the price spikes are excluded. 21 This experience led to calls for price caps, allegations of market power, and a questioning of the effectiveness of transmission open access and wholesale electric competition. --------------------------------------------------------------------------- \21\ Staff Price Spike Report at 3-8 to 3-11. --------------------------------------------------------------------------- The Commission staff undertook an investigation of the price spike incident. Staff's report concluded that the unusually high price levels were caused by a combination of factors, particularly above-average generation outages, unseasonably hot temperatures, storm-related transmission outages, transmission constraints, poor communication of price signals, lowered confidence in the market due to a few contract defaults, and inexperience in dealing with competitive markets. 22 --------------------------------------------------------------------------- \22\ Id. at v. --------------------------------------------------------------------------- The Commission's staff found that the market institutions were not adequately prepared to deal with such a dramatic series of events. Regarding regional transmission entities, the staff report observed: ``The necessity for cooperation in meeting reliability concerns and the Commission's intent to foster competitive market conditions underscores the importance of better regional coordination in areas such as maintenance of transmission and generation systems and transmission planning and operation.'' 23 Support for this view comes from many sources. For example, the Public Utilities Commission of Ohio, in its own report on the price spikes, recommended that policy makers ``take unambiguous action to require coordination of transmission system operations by regionwide Independent System Operators.'' 24 --------------------------------------------------------------------------- \23\ Id. at 5-8. \24\ Ohio's Electric Market, June 22-26, 1998, What Happened and Why, A Report to the Ohio General Assembly, at iii. --------------------------------------------------------------------------- On September 29, 1998, the Secretary of Energy Advisory Board Task Force on Electric System Reliability published its [[Page 31395]] final report. 25 The Task Force was convened in January 1997 to provide advice to the Department of Energy on critical institutional, technical, and policy issues that need to be addressed in order to maintain bulk power electric system reliability in a more competitive industry. The Task Force found that ``the traditional reliability institutions and processes that have served the Nation well in the past need to be modified to ensure that reliability is maintained in a competitively neutral fashion;'' that ``grid reliability depends heavily on system operators who monitor and control the grid in real time;'' and that ``because bulk power systems are regional in nature, they can and should be operated more reliably and efficiently when coordinated over large geographic areas.'' 26 --------------------------------------------------------------------------- \25\ Maintaining Reliability in a Competitive U.S. Electricity Industry; Final Report of the Task Force on Electric System Reliability (Sept. 29, 1998) (Task Force Report). The Task Force was comprised of 24 members representing all major segments of the electric industry, including private and public suppliers, power marketers, regulators, environmentalists, and academics. \26\ Task Force Report at x-xi. --------------------------------------------------------------------------- The report noted that many regions of the United States are developing ISOs as a way to maintain electric system reliability as competitive markets develop. According to the Task Force, ISOs are significant institutions to assure both electric system reliability and competitive generation markets. The Task Force concluded that a large ISO would: (1) be able to identify and address reliability issues most effectively; (2) internalize much of the loop flow caused by the growing number of transactions; (3) facilitate transmission access across a larger portion of the network, consequently improving market efficiencies and promoting greater competition; and (4) eliminate ``pancaking'' of transmission rates, thus allowing a greater range of economic energy trades across the network. 27 --------------------------------------------------------------------------- \27\ Id. at 76. --------------------------------------------------------------------------- 2. Successes, Failures, and Haphazard Development of Regional Transmission Entities Since Order No. 888 was issued, there have been both successful and unsuccessful efforts to establish ISOs, and other efforts to form regional entities to operate the transmission facilities in various parts of the country. While we are encouraged by the success of some of these efforts, it is apparent that the results have been inconsistent, and much of the country's transmission facilities remain outside of an operational regional transmission institution. Proposals for the establishment of five ISOs have been submitted to and approved, or conditionally approved, by the Commission. These are the California ISO,28 the PJM ISO,29 ISO New England ISO,30 the New York ISO,31 and the Midwest ISO.32 In addition, the Texas Commission has ordered an ISO for the Electric Reliability Council of Texas (ERCOT).33 Moreover, our international neighbors in Canada and Mexico are also pursuing electric restructuring efforts that include various forms of regional transmission entities.34 --------------------------------------------------------------------------- \28\ Pacific Gas & Electric Company, et al., 77 FERC para.61,204 (1996), order on reh'g, 81 FERC para.61,122 (1997) (Pacific Gas & Electric). \29\ Pennsylvania-New Jersey-Maryland Interconnection, et al., 81 FERC para.61,257 (1997), reh'g pending (PJM). \30\ New England Power Pool, 79 FERC para.61,374 (1997), order on reh'g, 85 FERC para.61,242 (1998) (order conditionally authorizing ISO New England); New England Power Pool, 83 FERC para.61,045 (1998), reh'g pending (order on NEPOOL tariff and restructuring)(NEPOOL). \31\ Central Hudson Gas & Electric Corporation, et al., 83 FERC para.61,352 (1998), order on reh'g, 87 FERC para.61,135 (1999) (Central Hudson). \32\ Midwest Independent Transmission System Operator, et al., 84 FERC para.61,231, order on reconsideration, 85 FERC para.61,250, order on reh'g, 85 FERC para.61,372 (1998) (Midwest ISO). \33\ See 16 Texas Administrative Code Sec. 23.67(p). \34\ See Policy Proposal for Structural Reform of the Mexican Electricity Industry, Secretary of Energy, Mexico (February 1999); Third Interim Report of the Ontario Market Design Committee (October 1998); TransAlta Enterprises Corporation, 75 FERC para.61,268 at 61,875 (1996) (recognition of the restructuring in the Province of Alberta, Canada to create a Grid Company of Alberta). --------------------------------------------------------------------------- The PJM, New England and New York ISOs were established on the platform of existing tight power pools. It appears that the principal motivation for creating ISOs in these situations was the Order No. 888 requirement that there be a single system wide transmission tariff for tight pools. In contrast, the establishment of the California ISO and the ERCOT ISO was the direct result of mandates by state governments. The Midwest ISO, which is not yet operational, is unique. It began through a consensual process and was not driven by a pre-existing institution. Two states in the region subsequently required utilities in their states to participate in either a Commission-approved ISO (Illinois and Wisconsin), or sell their transmission assets to an independent transmission company (Wisconsin). The approved ISOs have similarities as well as differences. All five Commission-approved ISOs operate, or propose to operate, as non- profit organizations. All five ISOs include both public and non-public utility members. However, among the five, there is considerable variation in governance, operational responsibilities, geographic scope and market operations. Four of the ISOs rely on a two-tier form of governance with a non-stakeholder governing board on top that is advised, either formally or informally, by one or more stakeholder groups. In general, the final decision making authority rests with the independent non-stakeholder board. One ISO, the California ISO, uses a board consisting of stakeholders and non-stakeholders. Four of the five ISOs operate traditional control areas, but the Midwest ISO does not currently plan to operate a traditional control area. Three are multi-state ISOs (New England, PJM and Midwest), while two ISOs (California and New York) currently operate within a single state. The current Midwest ISO members do not encompass one contiguous geographic area and there are holes in its coverage. The ISO New England administers a separate NEPOOL tariff, while the other four administer their own ISO transmission tariffs. Three ISOs operate or propose to operate centralized power markets (New England, PJM and New York), and one ISO (California) relies on a separate power exchange (PX) to operate such a market.35 The Midwest ISO did not originally envision an ISO-related centralized market for its region.36 In addition, at least one separate PX has begun to do business in California apart from the PX established through the restructuring legislation.37 --------------------------------------------------------------------------- \35\ The California PX offers day-ahead and hour-ahead markets and the ISO operates a real-time energy market. Participation in the PX market is voluntary except that the three traditional investor- owned utilities in California must bid their generation sales and purchases through the PX for the first five years. New York will offer day-ahead and real-time energy markets that will be operated by the ISO. PJM and New England offer only real-time energy markets, although PJM has proposed to operate a day-ahead market. The ERCOT ISO is the only other ISO that does not currently operate a PX. \36\ There are indications, however, that the Midwest ISO is considering the formation of a power exchange. See Joint Committee for the Development of a Midwest Independent Power Exchange, ``Solicitation of Interest-Creation of an Independent Power Exchange for the U.S. Midwest,'' February 5, 1999. \37\ See Automated Power Exchange, Inc., 82 FERC para. 61,287, reh'g denied, 84 FERC para. 61,020 (1998), appeals docketed, No. 98- 1415 (D.C. Cir. Sept. 14, 1998) and No. 98-1419 (D.C. Cir. Sept. 14, 1998). --------------------------------------------------------------------------- Not all efforts to create ISOs have been successful. For example, after more than two years of effort, the proponents of the IndeGO ISO in the Pacific Northwest and Rocky Mountain regions ended their efforts to create an ISO. More recently, members of MAPP, an existing power pool that covers six U.S. [[Page 31396]] states and two Canadian provinces, failed to achieve consensus for establishing a long-planned ISO. In the Southwest, proponents of the Desert Star ISO have not been able to reach agreement on a formal proposal after more than two years of discussion. Various reasons have been advanced to explain why it is difficult to form a voluntary, multi-state ISO. These include cost shifting in transmission capital costs; disagreements about sharing of ISO transmission revenues among transmission owners; difficulties in obtaining the participation of publicly-owned transmission facilities; concerns about the loss of transmission rights and prices embedded in existing transmission agreements; the likelihood of not being able to maintain or gain a competitive advantage in power markets through the use of transmission facilities; and the preference of certain transmission owners to sell or transfer their transmission assets to a for-profit transmission company in lieu of handing over control to a non-profit ISO. Apart from these efforts to create ISOs, we have received proposals for other types of transmission entities. For example, in October 1998 a group of Arizona entities filed a request with the Commission to create an ``independent scheduling administrator'' (ISA) in Arizona.38 Unlike an ISO, this entity would not administer its own transmission tariff nor would it have any direct operational responsibilities. Instead, it appears that its functions would be limited to monitoring the scheduling decisions and OASIS site operation of the Arizona utilities that operate transmission facilities.39 In case of disputes, the ISA would provide a type of expedited dispute resolution process. The applicants state that the ISA would be a transitional organization that would ultimately evolve or be merged into a stronger, multi-state ISO.40 In other developments, one public utility has recently made a filing with us to sell its transmission assets to a newly formed affiliate.41 Another public utility recently filed a request for declaratory order asking us to find that its proposal to transfer its transmission assets (in the form of ownership or a lease) to a ``transco'' in return for a passive ownership interest in the transco, would satisfy the Commission's eleven ISO principles.42 --------------------------------------------------------------------------- \38\ Arizona Independent Scheduling Administrator Association, Docket No. ER99-388-000 (filed October 29, 1998). \39\ A proposal for a similar entity has been in the Pacific Northwest. This entity, described as an independent grid scheduler, would make actual scheduling decisions rather than simply monitoring the decisions made by current transmission owners. See Regional ISO Conference (Portland), transcript at 39-40. \40\ See Applicant's filing, Docket No. ER99-388-000, at 3. \41\ FirstEnergy, Inc., Docket No. EC99-53-000 (filed March 19, 1999). \42\ Entergy Services, Inc., Docket No. EL99-57-000 (filed April 5, 1999). --------------------------------------------------------------------------- As part of general restructuring initiatives, several states now require independent grid management organizations. For example, an Illinois law requires that its utilities become members of a FERC- approved regional ISO by March 31, 1999, and Wisconsin law gives its utilities the option of joining an ISO or selling their transmission assets to an independent transmission company by June 30, 2000. In both states, the backstop is a single-state organization if regional organizations are not developed. Recently, Virginia and Arkansas have also enacted legislation requiring their electric utilities to join or establish regional transmission entities. 3. The Commission's ISO and RTO Inquiries; Conferences with Stakeholders and State Regulators In light of the various restructuring activities occurring throughout the U.S., the Commission has, within the past year, held 11 public conferences in 9 different cities across the country to hear the views of industry, consumers, and state regulators with respect to the need for RTOs and their appropriate roles and responsibilities. The Commission initiated an inquiry in March 1998 pertaining to its policies on ISOs. A notice establishing procedures for a conference gave the following rationale: In Order Nos. 888 and 889 and their progeny, the Commission established the fundamental principles of non-discriminatory open access transmission services. Nevertheless, many issues remain to be addressed if the Nation is to fully realize the benefits of open access and more competitive electric markets. * * * * * Given the dramatic changes taking place in both wholesale and retail electric markets and the many proposals under consideration with respect to the creation of ISOs or other transmission entities, such as transmission-only utilities, it is time for the Commission to take stock of its policies in order to determine whether they appropriately support our dual goals of eliminating undue discrimination and promoting competition in electric power markets.\43\ \43\ Inquiry Concerning the Commission's Policy on Independent System Operators, Notice of Conference, Docket No. PL98-5-000, at 1- 2 (March 13, 1998). --------------------------------------------------------------------------- Accordingly, the Commission held a series of eight conferences in 1998 to gain insight into participants' views on the formation and role of ISOs in the electric utility industry. The first conference was held in April 1998 at the Commission's offices in Washington, D.C. Between May 28 and June 8, 1998, the Commission held seven regional conferences in Phoenix, Kansas City, New Orleans, Indianapolis, Portland, Richmond and Orlando. As a result of these conferences, the Commission heard approximately 145 oral presentations and received a large number of written comments on the appropriate size, scope, organization and functions of regional transmission institutions. A number of different viewpoints were expressed. They will be discussed elsewhere in this NOPR and are summarized in Appendix A hereto. On October 1, 1998, the Secretary of Energy delegated his authority under section 202(a) of the FPA to the Commission. In doing so the Secretary stated that section 202(a) ``provides DOE with sufficient authority to establish boundaries for Independent System Operators (ISOs) or other appropriate transmission entities.'' \44\ The Secretary also stated, \44\ 63 FR 53889 (1998). --------------------------------------------------------------------------- FERC is also increasingly faced with reliability-related issues. Providing FERC with the authority to establish boundaries for ISOs or other appropriate transmission entities could aid in the orderly formation of properly-sized transmission institutions and in addressing reliability-related issues, thereby increasing the reliability of the transmission system. On November 24, 1998, we gave notice in this docket of our intent to initiate a consultation process with State commissions pursuant to section 202(a).45 The purpose of the consultations was to afford State commissions a reasonable opportunity to present their views with respect to appropriate boundaries for regional transmission institutions and other issues relating to RTOs. Conferences with State commissioners were held in St. Louis, Missouri on February 11, 1999; in Las Vegas, Nevada on February 12, 1999; and in Washington, D.C. on February 17, 1999. In all, we heard oral presentations by representatives of 41 state commissions during these consultations, with others monitoring or providing written comments.46 During these sessions, we received much valuable advice. We have set forth in Appendix B a summary of the comments received, and discuss in [[Page 31397]] Section III.B below our response to some of the major concerns expressed. --------------------------------------------------------------------------- \45\ Notice of Intent to Consult Under Section 202(a), 63 FR 66158 1998*), FERC Stats & Regs. para. 35,534 (1998). \46\ See Appendix B for a list of commenters. --------------------------------------------------------------------------- C. Statutory Framework The Commission is granted the authority and responsibility by FPA sections 205 and 206, 16 U.S.C. 824d, 824e, to ensure that the 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, and to remedy undue discrimination in the provision of such services. In fulfilling its responsibilities under FPA sections 205 and 206, the Commission is required to address, and has the authority to remedy, undue discrimination and anticompetitive effects. The Commission has a statutory mandate under these sections to ensure that transmission in interstate commerce and rates, contracts, and practices affecting transmission services, do not reflect an undue preference or advantage (or undue prejudice or disadvantage) and are just, reasonable, and not unduly discriminatory or preferential.47 Additionally, as discussed in Order No. 888,48 there is a substantial body of case law that holds that the Commission's regulatory authority under the FPA ``clearly carries with it the responsibility to consider, in appropriate circumstances, the anticompetitive effects of regulated aspects of interstate utility operations pursuant to [FPA] Secs. 202 and 203, and under like directives contained in Secs. 205, 206, and 207.'' 49 --------------------------------------------------------------------------- \47\ Once such a finding is made, the Commission is required to remedy it. See, e.g., Southern California Edison Company, 40 FERC para. 61,371 at 62,151-52 (1987), order on reh'g 50 FERC para. 61,275 at 61,873 (1990), modified sub nom., Cities of Anaheim v. FERC, 941 F.2d 1234 (D.C. Cir. 1991); Delmarva Power and Light Company, 24 FERC para. 61,199 at 61,466, order on reh'g 24 FERC para. 61,380 (1983). \48\ Order No. 888, FERC Stats. & Regs. at 31,669. \49\ Gulf States Utilities Co. v. FPC, 411 U.S. 747, 758-59, reh'g denied, 412 U.S. 944 (1973) (Gulf States). See also City of Huntingburg v. FPC, 498 F.2d 778, 783-84 (D.C. Cir. 1974) (Commission has a duty to consider the potential anticompetitive effects of a proposed Interconnection Agreement.) --------------------------------------------------------------------------- The Commission also has the authority and responsibility under section 203 of the FPA to review mergers and other transactions involving public utilities, including dispositions of jurisdictional facilities by public utilities. This includes public utilities' transfers of control of jurisdictional transmission facilities to entities such as RTOs. Under section 203, the Commission must approve a proposed disposition of jurisdictional facilities if it is consistent with the public interest. The Commission may grant an application under section 203 upon such terms and conditions as it finds necessary to secure the maintenance of adequate service and the coordination in the public interest of jurisdictional facilities. Further, section 202(a) of the FPA, whose authority has recently been delegated to the Commission by the Secretary of Energy,50 authorizes and directs the Commission ``to divide the country into regional districts for the voluntary interconnection and coordination of facilities for the generation, transmission, and sale of electric energy * * *.'' The purpose of this division into regional districts is for ``assuring an abundant supply of electric energy throughout the United States with the greatest possible economy and with regard to the proper utilization and conservation of natural resources * * *.'' Section 202(a) states that it is ``the duty of the Commission to promote and encourage such interconnection and coordination within each such district and between such districts.'' --------------------------------------------------------------------------- \50\ 63 FR 53889 (1998). --------------------------------------------------------------------------- III. Discussion A. Barriers to Assuring an Abundant Supply of Electric Energy Throughout the United States with the Greatest Possible Economy In light of our experiences with ISOs and other utility restructuring activity in the aftermath of Order Nos. 888 and 889, and after almost three years of experience with implementation of Order Nos. 888 and 889, we believe that there remain important transmission- related impediments to a competitive wholesale electric market. We have grouped these remaining impediments into two broad categories. The first category of impediments consists of engineering and economic inefficiencies inherent in the current operation and expansion of the transmission grid--inefficiencies that, in and of themselves, are hindering fully competitive power markets and imposing unnecessary costs on electric consumers. The second category of impediments consists of continuing opportunities for transmission owners to unduly discriminate in the operation of their transmission systems so as to favor their own or their affiliates' power marketing activities. Both sets of impediments unnecessarily restrict the scope of bulk power markets and inhibit the large-scale competition that we sought in issuing Order Nos. 888 and 889. The situation of the electric industry is somewhat analogous to the natural gas industry after the initial step of open access transportation was taken. In 1985, the Commission issued Order No. 436,51 which instituted open-access, nondiscriminatory transportation of natural gas with the goal of increasing competition and permitting gas users to purchase gas directly from gas merchants. However, the Commission subsequently found that open access alone was not sufficient to remove all barriers to competition. 52 Because of the different structures of the electric and gas industries, the specific remaining impediments to competition may not be the same, but there are similarities in that open access, without sufficient mechanisms for ensuring that such access is equal and efficient for all participants, may not be enough to promote a fully competitive market. 53 --------------------------------------------------------------------------- \51\ Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 436, 50 FR 42408 (Oct. 18, 1985), FERC Stats. & Regs. [Regulations Preambles 1982-1985] para. 30,665 1985), vacated and remanded, Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988), readopted on an interim basis, Order No. 500, 52 FR 30334 (Aug. 14, 1987), FERC Stats. & Regs. [Regulations Preambles, 1986-1990] para.30,761 (1987), remanded, American Gas Association v. FERC, 888 F.2d 136 (D.C. Cir. 1989), readopted, Order No. 500-H, 54 FR 52334 (Dec. 21, 1989), FERC Stats. & Regs. [Regulations Preambles 1986-1990] para. 30,867 (1989), reh'g granted in part and denied in part, Order No. 500-I, 55 FR 6605 (Feb. 26, 1990), FERC Stats. & Regs. [Regulations Preambles 1986-1990] para. 30,880 (1990), aff'd in part and remanded in part, American Gas Association v. FERC, 912 F.2d 1496 (D.C. Cir. 1990), cert. denied, 111 S. Ct. 957 (1991). \52\ In the case of natural gas, we found that the principal remaining barrier was the continued existence of bundled city-gate firm sales service that had a transportation component of higher quality than available through open access. Hence, we issued Order No. 636 to unbundle services and equalize the quality of service offered. See Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 57 FR 13267 (April 16, 1992), III FERC Stats. & Regs. para. 30,939 (April 8, 1992), reh'g granted and denied in part, Order No. 636-A, 57 FR 36128 (August 12, 1992), III FERC Stats. & Regs. para. 30,950 (August 3, 1992), order on reh'g Order No. 636-B, 57 FR 57911 (December 8, 1992), 61 FERC para. 61,272 (1992), Notice of Denial of Rehearing (January 8, 1993), 62 FERC para. 61,007 (1993), aff'd in part and vacated and remanded in part, United Dist. Companies v. FERC, 88 F.3d 1105 (D.C. Cir. July 16, 1996), order on remand, Order No. 636-C, 78 FERC para. 61,186 (1997). \53\ For a discussion of the similarities and differences in the structure and regulation of the natural gas and electric industries, see generally Santa and Sikora, Open Access And Transition Costs: Will The Electric Industry Transition Track The Natural Gas Restructuring?, 15 Energy L.J. 273 (1994). --------------------------------------------------------------------------- Our current understanding of industry conditions, as set forth below, will be enhanced by future consultations with and analysis from all industry stakeholders, including state commissions. The Commission seeks comments in order to achieve a deeper [[Page 31398]] appreciation of any impediments to competition in the Nation's electricity markets and how they should be addressed. 1. Engineering and Economic Inefficiencies in the Operation, Planning and Expansion of Regional Transmission Grids The transmission facilities of any one utility in a region are part of a larger, integrated transmission system. From an electrical engineering perspective, each of the three interconnections in the United States (the Eastern, the Western and ERCOT) operates as a single ``machine.'' 54 The Eastern Interconnection also extends into Canada, and the Western Interconnection includes parts of Canada and Mexico. --------------------------------------------------------------------------- \54\ North American Electric Reliability Council, Electric Reliability Panel, ``Reliable Power: Renewing the North American Electric Reliability Oversight System,'' December 1997, at 9. --------------------------------------------------------------------------- Problems have arisen over the last three years, in part, because we have multiple operators of each of these machines. Each separate operator usually makes independent decisions about the use, limitations and expansion of its piece of the interconnected grid based on incomplete information. This approach--separate operation of each utility's own transmission facilities--would make engineering sense only if each system operated independently of the others. But the physical reality is that, within the three interconnected grids, any action taken by one transmission provider can have major and instantaneous effects on the transmission facilities of all other transmission providers.55 --------------------------------------------------------------------------- \55\ U.S. Congress, Office of Technology Assessment, ``Electric Power Wheeling and Dealing, Technological Considerations for Increasing Competition,'' May, 1989. --------------------------------------------------------------------------- This is not a new phenomenon. Since the very first transmission interconnection between two neighboring utilities, interconnected utilities have had to cope with the fact that electricity will flow over others' lines. In the past, these effects were often small or infrequent and the utility could generally pass any costs through to captive customers. Today, with the increase in bulk power trade and the large shifts in power flows, the effects may be large, frequent and not recoverable by the utility bearing the cost. Another important change is that the structure of the industry that exists today is very different from the industry that existed three years ago when we issued Order No. 888. The industry is no longer composed uniformly of vertically-integrated, self-sufficient public utilities that do not compete with each other. Instead, it is an increasingly de-integrated and decentralized industry with many new and existing participants that actively compete against each other.56 --------------------------------------------------------------------------- \56\ For example, there are now about 550 Commission-approved power marketers. Decentralization has also increased because of divestiture of generating plants by traditionally vertically integrated utilities. Such sales are frequently required by state governments as one element of the structural reforms that accompany the introduction of retail competition. During the last three years, utilities have sold or have contracts to sell more than 50,000 MW of existing generating capacity. About 30,000 MW of additional capacity is currently being offered for sale. --------------------------------------------------------------------------- As a consequence of these changes in trade patterns and industry structure, certain operational problems have become more significant and more difficult to resolve. These include: maintaining reliable grid operations; determining available transmission capability (ATC); 57 managing transmission congestion; and planning and investing in new transmission facilities. In addition, traditional approaches to the pricing and provision of transmission service may be hindering the further development of competitive and efficient bulk power markets. These impediments include: pancaking of transmission access charges; non-market approaches to managing congestion; the absence of clear transmission rights; the absence of secondary markets in transmission service; and the possible disincentives created by the level and structure of transmission rates. The Commission believes that properly structured RTOs can address both sets of problems and further the development of competitive bulk power markets. --------------------------------------------------------------------------- \57\ See definition of ATC infra. --------------------------------------------------------------------------- a. Reliable Grid Operations The United States has one of the most reliable power systems in the world. For over thirty years, NERC and the regional reliability councils have developed and implemented voluntary standards to maintain the security of the transmission systems. There is no net public policy benefit to promoting competition if reliability suffers as a consequence.58 The promotion of competition must therefore go hand-in-hand with the creation of new institutions to ensure that reliability is maintained or improved in any new industry structure.59 We fully agree with the findings of the DOE Reliability Task Force: \58\ Unless otherwise noted, we use the term ``reliability'' to refer to the reliable or secure operation of the bulk power grid. This is one component of the broader NERC definition, which also includes ``adequacy'' (i.e., sufficient generation and transmission capacity) as a second component of overall reliability. See North American Electric Reliability Council, ``Glossary of Terms,'' August 1996, at 21. \59\ See George C. Loehr, ``Ten Myths About Electric Deregulation: Electrons May Seem Imaginary, But Reliability Is Real,'' Public Utilities Fortnightly, April 15, 1998, at 28-31. --------------------------------------------------------------------------- * * * there is a critical need to be sure that reliability is not taken for granted as the industry restructures, and thus does not ``fall through the cracks.'' 60 \60\ DOE Task Force Report, at xv. --------------------------------------------------------------------------- The DOE Reliability Task Force also pointed out that with the entry of many new participants, dramatic increases in unbundled power sales and shifts in electrical flows, the nation's bulk power system is being stressed in ways that have never been experienced before. A similar conclusion was reached by NERC in its 1998 summer assessment of bulk power reliability: Throughout the Regions, parallel path flows from increased electricity transfers are stressing the transmission systems. These flows are at magnitudes and in directions not anticipated at the time the systems were designed.* * *The transmission system will be required to operate under unprecedented, and sometimes unstudied, conditions.61 \61\ NERC, ``1998 Summer Assessment: Reliability of Bulk Electricity Supply in North America,'' May 1998, at 2-3. --------------------------------------------------------------------------- These stresses have always existed but not in these magnitudes. Moreover, they could be more readily accommodated through voluntary ad hoc agreements when there were fewer industry participants who generally did not compete against each other in any significant way.62 But as we have noted, this traditional industry structure is rapidly disappearing. Our concern is that the reliability fault lines may become more prominent and dangerous. --------------------------------------------------------------------------- \62\ In assessing the continued viability of the current system, NERC's blue-ribbon Electric Reliability Panel concluded that: ``The competitive dynamics among a much larger universe of players is not at all conducive to a system of voluntary peer compliance.'' Electric Reliability Panel Report, December 1997, at 28. --------------------------------------------------------------------------- It is well accepted that the operation of interconnected transmission networks requires careful coordination and the exchange of information between many individual systems. Any operational change on one system in the network instantly affects other systems. For example, the shipment of power from one location to another will divide among all transmission paths from source to destination based on the laws of physics.63 This is referred to as [[Page 31399]] parallel path or loop flow. Such flows will also affect a neighboring system's ability to determine ATC accurately. In addition, if a transmission facility is already loaded close to its operating limit, the additional flow resulting from a transaction contracted for on a neighboring system may overload the facility and threaten reliability. In order to operate the system in a reliable manner, a single, independent grid operator must know all sources and destinations for each transaction. The Commission believes that an RTO, as the only transmission provider and security coordinator in its region, would have the information needed to identify the effects of parallel flows and accommodate them in its operations. --------------------------------------------------------------------------- \63\ The amount of power flowing on any path in an electrical network is inversely proportional to that path's impedance. Impedance will depend on the actual length of the line and its voltage. See U.S. Congress, Office of Technology Assessment, Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition, OTA-E-409, May 1989, at 110-11. --------------------------------------------------------------------------- At present, the industry's ability to maintain reliable grid operation is hindered by the existence of many separate organizations that directly or indirectly affect the operation and expansion of the grid. There are more than 100 owners of the Nation's grid who operate about 140 separate control areas.64 In addition, there are 10 regional reliability councils, 23 security coordinators, 5 regional transmission groups (RTGs) and 5 independent system operators. With so many entities, the lines of authority and communication are not always as clear as they should be.65 An additional complication is that many of these entities also own generation or have a decision making process that continues to be dominated by traditional vertically integrated utilities.66 Therefore, their independence and commercial neutrality as grid operators is subject to question. --------------------------------------------------------------------------- \64\ A control area is an electrical system bounded by interconnection (tie-line) metering and telemetry. Within a control area, resources are balanced against load, and generation is regulated to maintain interchange schedules with other control areas and to achieve the target frequency (60 hz) for the entire Interconnection. See NERC Operating Policies Manual (available on the NERC website at www.nerc.com). \65\ See, e.g., Western Systems Coordinating Council, EL99-23- 000, comments of Enron Power Marketing, Inc. at 4-5. \66\ See, e.g., New England Power Pool, 86 FERC para. 61,262 at 61,965 (1999). --------------------------------------------------------------------------- It appears that information that is critical for maintaining reliability is not being shared as readily now as was generally the case in the past. NERC recently observed that there is a growing ``reluctance on the part of the market participants to share operational real-time and operational planning data with TPs [transmission providers].'' 67 This is not surprising because, as we have noted before, information that is needed for reliability purposes may also have a commercial value.68 If market participants believe that the entity that receives operational information for reliability reasons may use it for commercial advantage, they will understandably be reluctant to supply the information. After spending more than 18 months reviewing the current reliability system, the DOE Reliability Task Force concluded that this inherited system, with its patchwork of organizations, inadequate information sharing and overlapping and sometimes unclear responsibilities, is ``clearly unsustainable'' and that until new policies and institutions are in place, ``substantial parts of North America will be exposed to unacceptable risk.'' 69 --------------------------------------------------------------------------- \67\ NERC, Reliability Assessment 1998-2007 at 39 (1998). \68\ Midwest ISO, 84 FERC at 62, 158-159. \69\ DOE Task Force Report at vii and xi. --------------------------------------------------------------------------- This is not just a theoretical concern. During last year's regional ISO conferences, several industry participants described three ``reliability near misses'' in the Midwest. The three incidents on July 22, 1993, August 7, 1996 and July 11, 1997 came very close to producing major outages throughout the Midwest.70 While there has been some improvement in coordination among different systems, we believe that there are limits to the amount of coordination that can be achieved between separate organizations, especially if they are competing for the right to use the same limited transmission capacity and sometimes competing for the same customers. While competition requires decentralization, we think that reliable and efficient grid operation requires more coordination. The Commission believes that a beneficial platform for both competition and reliability is a single independent grid operator that sees the ``big picture'' by having access to real-time information on conditions and schedules for the entire regional grid.71 Such an entity does not exist in several regions of the country. As a consequence, there is, at present, a disconnect between electrical flows and information flows that could have major reliability consequences. --------------------------------------------------------------------------- \70\ Regional ISO Conference (Indianapolis), transcript at 24- 29. \71\ The importance of a single operator for reliability was stressed in comments of AMEREN and Commonwealth Edison. See Regional ISO Conference (Indianapolis), transcript at 19-29. --------------------------------------------------------------------------- b. Determining Available Transmission Capability (ATC) Any transportation service provider should know how much commodity it can carry. For electric transmission service providers, the calculations of total transmission capability (TTC) and ATC are needed to make this determination. TTC and ATC are key elements of the OASIS information system.72 Order No. 889 requires each transmission provider to calculate and post TTC and ATC numbers to give its transmission customers a reasonable estimate of how much power can be carried between any two locations on the grid and how much capacity is available to support additional trade at any given time. --------------------------------------------------------------------------- \72\ ATC is a measure of transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses. TTC is the amount of electric power that can be transferred over the interconnected transmission network in a reliable manner based on certain specified conditions, North American Reliability Council, Glossary of Terms (1996). --------------------------------------------------------------------------- We have received many complaints about the accuracy and usefulness of posted ATC numbers. There are several reasons why it is difficult to determine available transmission capability accurately. First, ATC numbers are still calculated on an individual company basis in many areas of the country. Separate calculations of ATC by individual companies are fundamentally inconsistent with the physical reality of an interconnected transmission system. An individual transmission provider may post ATC numbers in good faith, and attempt to provide transmission service based on these numbers, only to learn later that the transfer capability that it thought was available no longer exists because of decisions made by other transmission providers that it did not know about at the time it made its calculations. Accurate ATC numbers would require reliable and timely information about load, generation, facility outages and transactions on neighboring systems. Individual transmission operators will generally not have this information. They also may apply differing assumptions and criteria to ATC calculations, which may produce wide variations in posted ATC values for the same transmission path.73 All these considerations make it virtually impossible for an individual transmission provider that operates one [[Page 31400]] part of a large interconnected grid to calculate ATC accurately.74 --------------------------------------------------------------------------- \73\ This, in turn, creates other problems. According to NERC, the ``inconsistent calculation [of ATC] can increase the use of TLR and other operational complexities, which has the potential to cause reliability problems.'' NERC, Reliability Assessment, 1998-2007, September, 1998, at 40. (See definition of TLR in section II.) \74\ In addition, it has been frequently alleged that individual transmission may intentionally post inaccurate ATC numbers to favor their own power marketing efforts. These allegations are discussed in section III.A.2. --------------------------------------------------------------------------- Second, requests for transmission service are usually based on ``contract path'' scheduling. This is the practice of finding a contiguous chain of utilities from the power supplier to the power consumer and contracting with those utilities to transmit the power. The implicit assumption is that all the power flows through the utilities along this ``contract path.'' In fact, the power divides up and flows along all paths from the supplier to the buyer. All utilities in the region are affected. Contract path scheduling provides little or no information about actual flows on the grid.75 In its October 1997 report to the Commission, the Commercial Practices Working Group commented that: ``Reserving and scheduling transmission on a contract path basis does not even closely resemble the physical impact on the system.'' 76 We note that NERC is encouraging initiatives that would move the industry toward recognizing actual flows in scheduling.77 --------------------------------------------------------------------------- \75\ See Allegheny Power Service Corporation et al., 78 FERC para. 61,314 at 62,339. \76\ October 31, 1997 report, at 39. \77\ See NERC, 85 FERC at 62,363. --------------------------------------------------------------------------- c. Managing Congestion Congestion occurs when requests for transmission service exceed the capability of the grid. When transmission constraints limit the amount of power that can be transmitted, the loads on the system may not be able to be served by the least-cost mix of available generators. The constraints may reflect voltage, temperature and dynamic limits. Relieving congestion leads to a more costly pattern of generation dispatch. The cost of congestion is the additional energy cost associated with the new pattern of dispatch. We recognize that even optimally designed systems will normally experience at least occasional congestion that at times can be significant and costly. In general, congestion can be managed in two ways: the construction of new transmission facilities that increase grid capacity; or the redispatch of existing or new generators to reduce flows or create counterflows on the constrained facility. The complete elimination of congestion would typically require the construction of new transmission facilities. While this may be a physically effective solution, it may not always be cost effective. Because of this, we believe that an efficiently operated transmission system should have in place mechanisms for pricing congestion and then managing congestion through changes in the pattern of dispatch. Without mechanisms for determining the cost of congestion, it will be virtually impossible to make rational, cost effective decisions to expand the grid. The Commission believes that efficient congestion management is best performed at the regional level. At present, outside of the operational ISOs, transaction curtailment through transmission loading relief (TLR) procedures is the dominant approach for dealing with congestion in the Eastern Interconnection. NERC has reported that its TLR procedures were invoked 329 times between July 1997 and October 1998 on the Eastern Interconnection.78 Current TLR procedures are cumbersome, inefficient and disruptive to bulk power markets because they rely exclusively on physical measures of flows with no attempt to assess the relative costs of different congestion management options. Moreover, TLR actions are typically taken by one utility without assessing the costs imposed on other grid users. This inevitably raises the suspicion that the TLR request could be motivated by competitive rather than reliability concerns. For these reasons, the Commission has encouraged NERC to develop regional market approaches to managing congestion.79 --------------------------------------------------------------------------- \78\ North American Electricity Reliability Council, Interim Market Interface Committee, Minutes of Jan. 12 and 13, 1999 meeting, Exhibit D. \79\ See NERC, 85 FERC at 62,364. --------------------------------------------------------------------------- The Commission recognizes, however, that NERC may not be able to comply fully with this policy in the absence of regional organizations that have the authority and ability to promote regional congestion markets. There are three considerations that support this conclusion. First, a regional organization would have accurate and reliable information about existing and possible future conditions on the grid. Such information is generally not available to individual transmission providers. RTOs would have this information because they would function as both regional security coordinators and regional transmission providers. Second, congestion management is best performed at a regional level. This is shown in the largely unsuccessful efforts of Commonwealth Edison to create congestion markets that would allow transmission customers to ``buy-through'' (i.e., firm up) transmission rights on congested flow gates. After six months of its one year experiment, we note that Commonwealth concluded that it is ``difficult for one transmission owner to identify and implement redispatch'' when the physical limitations and cost effective options for relief exist on other transmission systems that are beyond their reach.80 --------------------------------------------------------------------------- \80\ Commonwealth Edison, Interim Report on Non-Firm Redispatch, Docket No. ER98-2279, December 17, 1998, at 4, 10. --------------------------------------------------------------------------- Third, RTOs will be able to establish and define rights to the use of the grid. At present, with multiple and independent operators of the grid, individual users and owners have unclear and conflicting rights to the grid. This makes it difficult to establish congestion markets. A congestion market, like any other market, cannot develop in the absence of clear rights.\81\ Such rights, whether held by transmission users or owners, are a necessary prerequisite for establishing congestion markets. Without establishing such rights, the industry will continue to grapple with the problem of incomplete markets. Thus, it is difficult to achieve efficient and competitive regional bulk power markets if congestion on the transmission grid is not accurately priced. --------------------------------------------------------------------------- \81\ Robert Cooter and Thomas Ulen, Law and Economics, Scott, Foresman and Company, 1988, at 91 (``From a legal viewpoint, property is a bundle of rights''). --------------------------------------------------------------------------- d. Planning and Expanding Transmission Facilities Transmission planning and expansion are more difficult today than three years ago. While uncertainty has always been a fact of life for any transmission planning exercise, the level of uncertainty has increased with the increasing number and distance of unbundled transactions and the wider variation in generation dispatch patterns. Uncertainty has also increased because: Generation developers are reluctant to disclose their plans for future capacity additions. Similarly, utilities intending to purchase from others are reluctant to speculate on whom or where their suppliers might be, making modeling of such transactions for transmission analysis virtually impossible.\82\ --------------------------------------------------------------------------- \82\ NERC, ``Reliability Assessment, 1998-2007,'' September 1998, at 39. One troubling consequence of this uncertainty has been a noticeable decline in planned transmission investments. NERC recently reported that the level of planned transmission [[Page 31401]] additions is significantly lower than five years ago despite an overall increase in load growth and unbundled transmission service.\83\ While this could simply reflect better utilization of the existing grid, the Commission is concerned that it may also reflect an incompatibility of existing planning institutions with the new market realities. --------------------------------------------------------------------------- \83\ Id. at 7. --------------------------------------------------------------------------- We are also concerned that the existing approach to transmission pricing may not sufficiently encourage the investments in transmission facilities that are needed to improve the reliability and efficiency of the grid. Inadequate investment could be a major impediment to the development of regional bulk power markets and a possible source of future reliability problems. There are at least three concerns about the way transmission prices are set. First, although there are varying degrees of investment coordination around the country, utilities ultimately make transmission investment decisions individually rather than through joint decisions that internalize commercial and reliability effects of the investment. It may be unclear which utility should have the responsibility for expanding capacity to relieve a transmission constraint. For example, power flows scheduled by one utility with ample transmission capacity on its own lines may overload a neighbor's lines. The first utility may be unwilling to expand transmission capacity because it needs no extra transmission capacity itself, and the second utility may be unwilling to expand transmission capacity because it collects no revenues from the power flows scheduled by others. In a multi-utility region, decisions about where to site new facilities and who should pay for capacity expansions can be even more complex unless a regional body provides a forum for discussions and a method for resolving disputes. Second, the motivation for constructing new facilities is changing as the industry changes. Formerly, a utility built transmission primarily to deliver power from its generating plants to its customers. Inadequate transmission would have hurt power sales, the principal source of utility revenue. Today, facility expansion may be needed to transmit power sold by others. As generation and transmission ownership become increasingly separate and as many states implement or even merely consider retail access, the transmission owner's traditional incentive for making new transmission investment to support its power sales erodes. Incentives for transmission investment need to be related more to the power needs of the region than the generation stock of the transmission owners. Third, the transmission owner that does invest in transmission to overcome a constraint may be concerned about recovering its investment. Under traditional ratemaking practices, it must recover its investment over a long period of time, typically thirty years. But subsequent generation construction on the power-poor side of the constraint may obviate the need for the line and threaten recovery of its capital cost. In addition, where there is higher risk, a higher return commensurate with the higher risk may be appropriate. To support this, customers and regulators would want assurance that the decision to invest in transmission is made in the best interests of the region, considering not only all the transmission options but also the generation and demand management alternatives to transmission construction. Therefore, as discussed below, we will consider concrete proposals from regional transmission organizations for transmission pricing reforms and the explicit use of pricing incentives to encourage RTOs to make efficient investments in new transmission facilities. e. Pancaked Transmission Rates With the exception of power pools, open access under Order No. 888 focuses on individual, existing transmission providers. Order No. 888 does not require transmission pricing reforms that are needed to support efficient and competitive bulk power markets. The ``missing'' reforms include, among others, the elimination of pancaked transmission access charges, the use of reservation-based (as opposed to load-based) transmission tariffs and the availability of secondary markets in transmission rights.84 In this section, we will focus on the problems created by the widespread pancaking of transmission access charges.85 --------------------------------------------------------------------------- \84\ See, e.g., Capacity Reservation Open Access Transmission Tariffs, Notice of Proposed Rulemaking, FERC Stats. and Regs. para. 32,519 (1996) and Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities Under the Federal Power Act: Policy Statement, 69 FERC para. 61,086 (1994). \85\ We did, however, require non-pancaked rates for power pools that offer non-pancaked rates to their own members in Order No. 888. Order No. 888, FERC Stats, and Regs. at 31,727-28. --------------------------------------------------------------------------- In most of the United States, a transmission customer pays separate, additive access charges every time its contract path crosses the boundary of a transmission owner. By raising the cost of transmission, pancaking reduces the size of geographic power markets. This, in turn, can result in concentrated electricity markets. Balkanization of electricity markets hurts electricity consumers, in general, by forcing them to pay higher prices than they would in a larger, more competitive, bulk power market.86 --------------------------------------------------------------------------- \86\ While it is difficult to estimate the exact impact on consumers, we note that there have been studies of the deregulated British power markets that have found excessive concentration in generation has produced prices 20 to 40 percent above competitive levels at certain times. Richard Green and David Newbery, Competition in the British Electricity Spot Market, 100 J. Pol. Econ., 929, 1992. --------------------------------------------------------------------------- The Commission has heard from many states about the negative effects of pancaked rates in their efforts to introduce retail competition. At this time, about 21 states have introduced or are planning to introduce competition for retail loads under their jurisdiction.87 Because the Commission has jurisdiction over transmission service and rates for unbundled retail customers, we have an obligation to address these concerns.88 A retail choice initiative, no matter how well designed at the state level, may fail if the pool of potential competitors is effectively limited to a few nearby supply sources because of pancaked transmission charges. --------------------------------------------------------------------------- \87\ ``Status of Electric Utility Deregulation as of May 1, 1999,'' Energy Information Administration. \88\ Order No. 888, FERC Stats. and Regs. at 31,651-52. --------------------------------------------------------------------------- This concern of pancaked rates was highlighted to us in the recent consultations with our state commission colleagues. Several state commissioners emphasized that the success of their retail competition initiatives is related to the adoption of non-pancaked transmission tariffs and other ISO policies.89 We believe that the likelihood of success for existing and planned retail choice initiatives is significantly enhanced if the Commission can ensure fair and efficient access to a regional market without pancaked transmission access charges, and that we need to take steps beyond Order No. 888 to accomplish this. --------------------------------------------------------------------------- \89\ See, e.g., Comments of Gerald Thorpe (Maryland) and President Herbert Tate (New Jersey), RTO Conference (Washington, DC), transcript at 37-39; 49-51. --------------------------------------------------------------------------- f. Conclusion We believe that the preferred solution to the engineering and economic problems discussed in this section is a regional solution. Notwithstanding it success, Order No. 888 has not been able to produce a fully efficient and competitive outcome because it does not address ATC calculations, congestion [[Page 31402]] management, reliability, pancaking of transmission access charges, and grid planning and expansion. These are regional problems. Therefore, we are proposing a rule to encourage the development of independent regional transmission operators that can promote both electric system reliability and competitive generation markets. 2. Actual and Perceived Discriminatory Conduct by Transmission Owners to Favor Their Own or Affiliated Merchant Operations In addition to operational inefficiencies impeding full competition, there also exist questions about residual discrimination in the provision of transmission services by public utilities. As discussed below, many in the industry have expressed a fundamental mistrust of transmission owners. In addition, there are allegations, and in some circumstances findings, of actual discrimination by transmission owners. We discuss below indications of discriminatory conduct by vertically integrated utilities and seek further comment on utility practices subsequent to Order No. 888. Utilities that control monopoly transmission facilities and also have power marketing interests 90 have poor incentives to provide equal quality transmission service to their power marketing competitors. It is, in fact, in the economic self-interest of transmission-owning utilities to favor their own power marketing interests and frustrate their competitors. As the Commission stated in Order No. 888: \90\ The term power marketing interests is used as shorthand herein to include the utility's own wholesale merchant function as well as any affiliates with wholesale merchant functions. --------------------------------------------------------------------------- It is in the economic self-interest of transmission monopolists, particularly those with high-cost generation assets, to deny transmission or to offer transmission on a basis that is inferior to that which they provide themselves. The inherent characteristics of monopolists make it inevitable that they will act in their own self- interest to the detriment of others by refusing transmission and/or providing inferior transmission to competitors in the bulk power markets to favor their own generation, and it is our duty to eradicate unduly discriminatory practices.\91\ --------------------------------------------------------------------------- \91\ Order No. 888, FERC Stats. and Regs. at 31,682. The exercise of transmission market power allows transmission providers with power marketing interests to benefit in the short-run by making more power sales at higher prices, and benefit in the long-run by deterring entry by other market participants. As a result, prices to the Nation's electricity consumers will be higher than need be. It was to eliminate this inherent tendency of a vertically- integrated utility to favor its own power sales that Order Nos. 888 and 889 required utilities to functionally unbundle their transmission and power merchant services. Generally, functional unbundling requires a public utility to: separate its transmission system functions and staff from wholesale generation marketing functions and staff; abide by a standard of conduct to define impermissible contact between generation and transmission personnel; take transmission services under the same open access tariff of general applicability as do others; state separate rates for wholesale generation, transmission, and ancillary services; and rely on the same Open Access Same-Time Information System (OASIS) that its transmission customers rely on to obtain information about its transmission system when buying or selling power.92 The Commission imposed these requirements to establish a foundation for open grid access and competitive electricity markets. --------------------------------------------------------------------------- \92\ Id. at 31,654-55. --------------------------------------------------------------------------- Functional unbundling did not change the incentives of vertically- integrated utilities to use their transmission assets to favor their own generation, but instead attempted to reduce the ability of utilities to act on those incentives. In Order No. 888, the Commission received and considered numerous comments that functional unbundling was unlikely to work, and that more drastic restructuring, such as corporate unbundling, was needed.\93\ However, the Commission decided at the time to adopt what it considered to be the less intrusive and less costly remedy. --------------------------------------------------------------------------- \93\ Id. at 31,653-54. --------------------------------------------------------------------------- Clearly, Order No. 888 has resulted in wholesale power markets becoming more competitive, more transmission services being made available to more potential users than ever before, and generally lower transaction costs. However, market participants increasingly have alleged that numerous transmission service problems related to discriminatory conduct remain, and that these problems are impeding competitive wholesale power markets.\94\ Our information about alleged continued discriminatory practices comes from several sources. These include formal complaints filed with the Commission, informal complaints made to the Commission's enforcement hotline, oral and written comments made in conjunction with public conferences held by the Commission, and pleadings filed with the Commission in various dockets. --------------------------------------------------------------------------- \94\ See, e.g., of Roger Fontes on behalf of the Northern California Power Agency, Regional ISO Conference (Phoenix), Transcript at 136 (``In general, orders 888 and 889 have not fully remedied undue discrimination in providing transmission service in this country.'') --------------------------------------------------------------------------- Compared to the situation before Order No. 888, transmission-owning utilities must now resort to more subtle means to frustrate their marketing competitors and favor their own marketing interests. Continued discrimination may be conscious and deliberate, but it may also result from the failure to make sufficient efforts to change the way integrated utilities have done business for many years. In either case, the tendency of transmission owners to confer advantages, however subtle, upon their own marketing interests is discriminatory as against other marketers. In the sections that follow, we will outline the information derived from filings and other sources about remaining impediments to competition caused by continued discriminatory conduct by transmission owners. We note, and we are well aware, that many allegations that have been made in various forums are unproved, and perceived discrimination may in fact turn out to have justifiable explanations. It is often hard to determine, on an after-the-fact basis, whether an action was motivated by an intent to favor affiliates or simply resulted from the need to serve native load customers or the impartial application of operating or technical requirements. Given our considerable difficulty in determining whether there has been compliance with our regulations, the question arises whether functional unbundling is an appropriate long-term regulatory solution. We consider allegations of discrimination, even if not reduced to formal findings, to be a serious concern for two reasons. First, we may be seeing only the ``tip of the iceberg.'' We are aware that instances of actual discriminatory conduct may be undetectable in a non- transparent market. In addition, there are significant disincentives to filing and pursuing formal complaints that would result in definitive findings. Transmission customers often tell the Commission's enforcement staff that they are reluctant to make even informal complaints because of concerns that the Commission will not take strong action, and fear, perhaps most importantly, of retribution by their transmission supplier.95 We also have been told that [[Page 31403]] the complaint process is costly and time-consuming,96 and that the Commission's remedies for transmission violations do not impose sufficient financial harms on the transmission provider to act as a significant deterrent.97 --------------------------------------------------------------------------- \95\ See Comments of Dan Jones on behalf of the Public Utilities Commission of Texas, Regional ISO Conference (Kansas City), Transcript at 1985 (``And we've also heard that these entities are hesitant to bring those complaints forward because they have to deal with both sides of that utility''). \96\ We note that we have recently issued a Final Rule regarding complaint procedures designed to make them more efficient. See Complaint Procedures, Final Rule, Docket No. RM98-13-000, 86 FERC para. 61,324 (issued March 31, 1999). \97\ Comments of National Energy Marketers Association, Docket No. RM98-5-000 (filed January 22, 1999). --------------------------------------------------------------------------- Perhaps the most problematic aspect of relying on after-the-fact enforcement in the fast-paced business of power marketing, however, is that there may be no adequate remedy for lost short-term sale opportunities. For example, the Electric Power Supply Association has told us: Furthermore, even if the exercise of such discrimination could be adequately documented and packaged in the form of a complaint under Section 206 of the Federal Power Act under a more streamlined complaint process contemplated by the Commission, it would still be extremely costly and inefficient to deal with such complaints on a case-by-case basis. More than likely, the potential power transactions for which transmission principally was sought would disappear by the time a Commission ruling was obtained.98 \98\ Motion to Intervene and Comments of Electric Power Supply Association in Support of Petition for Rulemaking, Docket No. RM98- 5-000 (filed Sept. 21, 1998), at 3. Accordingly, actual problems with functional unbundling may be more pervasive than formally adjudicated complaints would suggest, and the informal allegations we hear provide valuable insight. Second, we consider the allegations of discrimination to be serious because, if nothing else, they represent a perception by market participants that the market is not working fairly because such participants know that integrated utilities have the incentive and opportunity to discriminate. Mistrust in the market can itself be a serious impediment to competition. If market participants perceive that other participants have an unfair advantage through the affiliation with the transmission provider, it can inhibit their willingness to participate in the market, including, for example, building new generating units, thus thwarting the development of robust competition. Such mistrust can also harm reliability. As stated by NERC, there is a reluctance on the part of market participants to share operational real-time and planning data with transmission providers because of the suspicion that they could be providing an advantage to their affiliated marketing groups.99 --------------------------------------------------------------------------- \99\ NERC Reliability Assessment 1998-2007, at 39. --------------------------------------------------------------------------- The functional unbundling policy underlying Order No. 888 was an attempt to regulate the behavior of transmission owners. There are growing indications, however, that the conflicting incentives that vertically integrated utilities have regarding transmission access may be too difficult to police. Many have asserted that it is not realistic even to expect functional unbundling to eliminate attempts by transmission owners to gain economic advantage. Companies have an obligation to maximize value for shareholders, and it should be no surprise that they will be aggressive in doing so. For example, in comments to the Commission in the Order No. 888 proceeding, the Federal Trade Commission advised the Commission that a functional unbundling approach ``* * * would leave in place the incentive and opportunity for some utilities to exercise market power in the regulated system. Preventing them from doing so by enforcing regulations to control their behavior may prove difficult.'' A representative of Lafayette Utilities told us at the New Orleans ISO Conference: Notwithstanding functional separation and the requirement not to discriminate, transmission personnel are well aware of the interests of their company's generation function, and can find a way to give preferential treatment. * * * 100 --------------------------------------------------------------------------- \100\ Comments of Frank Ledoux on behalf of Lafayette Utilities System, Regional ISO Conference (New Orleans), Transcript at 180. --------------------------------------------------------------------------- A representative of a Wisconsin public utility told us: Administration of the tariff entails a myriad of decisions that require discretion, as well as ``technical'' judgments (like [available transmission capability] and [capacity benefit margin]) that have significant competitive ramifications. It is inevitable that these decisions and judgments will be made with competitive concerns in mind. Functional separation does not solve this problem.101 \101\ Statement of Roy Thilly on behalf of Wisconsin Public Power, Inc. at 2, Docket No. PL98-5-000 (filed April 15, 1998). Similarly, at our regional ISO conference in Indianapolis, we were --------------------------------------------------------------------------- told: In a capital intensive industry where a high percentage of the investment is in generation assets, it is inconceivable that a utility, which in some cases has very high generation cost, would somehow manage its transmission system so as not to give its generation a competitive advantage. I think this is self- evident.102 \102\ Comments of Kenneth Hegemann on behalf of American Municipal Power, Ohio, Regional ISO Conference (Indianapolis), Transcript at 174. --------------------------------------------------------------------------- While it should not be assumed that such problems exist in every circumstance, clearly many market participants do not believe the market can yet be trusted with respect to their commercial interests, at least in some areas. We now turn to some of the areas that have produced the most complaints about continuing discrimination. a. Calculation and Posting of Available Transmission Capability in a Manner Favorable to the Transmission Provider Perhaps the most significant complaint with respect to alleged discriminatory conduct under functional unbundling concerns the important function of calculating and posting the amount of transmission capability that is available on a transmission provider's system. The transmission provider is required to calculate and post on its OASIS the TTC and ATC for each posted transmission path.103 ATC is the capacity that is stated to be available for transmission service requests. As we discussed above in Section III.A.1, it is not possible to calculate accurately the transmission capability of one system without knowing the flows scheduled by all other interconnected transmission providers in the region. Given this technical problem, it may be impossible to distinguish an inaccurate ATC presented in good faith from an inaccurate ATC presented for the purpose of favoring the transmission provider's marketing interests. --------------------------------------------------------------------------- \103\ See 18 CFR 37.6(b) (1998). --------------------------------------------------------------------------- Transmission providers with power marketing interests have incentives to understate ATC on those paths valuable to its marketing competitors, or to divert transmission capacity so that it is available for use by its own marketing interests. If there is insufficient ATC, competitors may be forced to forego power sale transactions or use a less desirable alternative path if one is available. The Commission has found violations of ATC postings in three cases. In Washington Water Power Company,104 the transmission owning utility showed that it had no firm ATC, which would have discouraged any potential marketers who needed firm transmission service to make a sale. However, the utility then offered its power marketing affiliate, Avista [[Page 31404]] Energy, an ``interruptible firm'' transmission service that was not available to competitors. As the Commission explained in finding a violation of Order No. 888: \104\ 83 FERC para. 61,097 (1998), further order, 83 FERC para. 61,282 (1998). --------------------------------------------------------------------------- Avista received a preference from Washington Water Power that was not available to any of its competitors. Simply stated, Avista's customer was deprived of the benefit of choosing among all potential power suppliers. The case of Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public Service Corporation, et al. (Wisconsin Public) 105 demonstrates both the difficulties and suspicions of discrimination resulting from when a transmission customer requests transmission service from an integrated utility. WPPI was seeking additional network transmission service from both Wisconsin Public Service Corporation (WPSC) and Wisconsin Power & Light Company (WP&L). In both cases, the requests were denied because of claims that the transmission owners were using all available capacity. In the case of WPSC, the Commission initially found that the utility had not properly reserved capacity for its merchant function and directed that it recompute its ATC without that reservation. After WPSC submitted additional documentation, the Commission accepted some of WPSC's merchant priority, but still found that it had violated its obligations under its tariff, and that its actions raised serious concerns about the functional separation of its staff. With respect to WP&L, the Commission found that it provided unduly preferential treatment to its merchant function, had been changing its ATC without posting those changes on OASIS, and had been computing ATC where none exists.106 --------------------------------------------------------------------------- \105\ 83 FERC para. 61,198 (1998), order on reh'g, 84 FERC para. 61,120 (1998). \106\ 83 FERC at 61,860. --------------------------------------------------------------------------- The Wisconsin Public cases demonstrate, if nothing else, the difficulty of achieving, and enforcing, functional separation of a utility's transmission and merchant functions. These types of cases require substantial Commission investigative and adjudicative resources, not to mention the resources of the parties involved. The Commission recognized in Wisconsin Public how RTOs could help eliminate these problems. The Commission stated: As we recently explained in Louisville Gas & Electric Company, et al., 82 FERC para. 61,308 at 62,222 & n. 39 (1998), a properly structured ISO, or other transmission entity can eliminate the potential for the strategic use of a transmission owner's priority to use internal system capacity for native load. The ISO or other transmission entity can also eliminate the incentive to engage in strategic curtailments of generation that a transmission operator's generation service competitors own and can remove any incentive to game OASIS operations. This will promote generation entry and competition, since a properly structured ISO or other transmission entity would have no economic stake in favoring certain market participants over others and potential entrants would likely see the transmission market as fair. An ISO, therefore, could help to solve the problems established in the instant complaints.107 \107\ Id. at 61,859. --------------------------------------------------------------------------- The case of Morgan Stanley Capital Group v. Illinois Power Company 108 also demonstrated problems associated with ATC and a transmission provider's use of its system for its own purposes. Morgan Stanley complained that Illinois Power failed to accurately post ATC, failed to award transmission capacity in a non-discriminatory manner, and allocated transmission in favor of its own bulk power marketing arm. Illinois Power admitted the ATC posting error, and the Commission found other violations of its tariff in responding to Morgan Stanley's request for service. Although the Commission initially also found that Illinois Power [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A99-12553. Public record. Not legal advice.