# Remedying Undue Discrimination Through Open Access Transmission Service and Standard Electricity Market Design > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A02-21479 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** August 29, 2002 - **Citation:** 67 FR 55452 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM01-12-000] Remedying Undue Discrimination Through Open Access Transmission Service and Standard Electricity Market Design July 31, 2002. AGENCY: Federal Energy Regulatory Commission, DOE. ACTION: Notice of proposed rulemaking. SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes to amend its regulations under the Federal Power Act (FPA) to modify the pro forma open access transmission tariff established under the Commission's Order No. 888 to remedy remaining undue discrimination in the provision of interstate transmission services and in other industry practices, and to assure just and reasonable rates within and among regional power markets. The Commission proposes to require all public utilities with open access transmission tariffs to file modifications to their tariffs to reflect non-discriminatory, standardized transmission service and standardized wholesale electric market design. DATES: Initial comments are due on October 15, 2002. Comments should include an executive summary that does not exceed 10 pages. ADDRESSES: Send comments to: Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. FOR FURTHER INFORMATION CONTACT: Alice Fernandez (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 208-0089. (202) 502-6389 (after Aug. 7, 2002). David Mead (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 208-1024. (202) 502-8028 (after Aug. 7, 2002). Mark Hegerle (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 208-0287. (202) 502-8287 (after Aug. 7, 2002). David Withnell (Legal Information), Office of General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 208-2063. (202) 502-8421 (after Aug. 15, 2002). SUPPLEMENTARY INFORMATION: In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's home page ( http://www.ferc.gov ) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Washington, DC 20426. Table of Contents Paragraph I. Introduction 1 II. Background: Order No. 888 and Order No. 2000 20 A. Order Nos. 888 and 888-A 20 B. Order No. 2000 24 III. Need for Reform 31 A. Undue Discrimination and Impediments to Competition Remain 31 B. Specific Instances of Undue Discrimination and Impediments to Competition 36 1. Transmission Market Power by Utilities that are Not Independent 38 a. Load Growth 41 b. Delays in Responding to Requests for Service 43 c. Scheduling Advantages 45 d. Imbalance Resolution 48 e. Available Transfer Capability and Affiliates 50 f. OASIS Postings 52 g. Capacity Benefit Margin Manipulation 55 h. Discretionary Use of Transmission Loading Relief 57 2. Lack of Common Rules Governing Transmission 61 3. Congestion Management 71 4. Seams Problems 80 5. Market Design Flaws 86 C. Reform Essential Given the Changed Nature of the Electric Industry 91 D. Legal Authority and Findings 100 IV. The Proposed Remedy 107 A. The Interim Tariff 117 1. Placing Bundled Retail Customers under the Interim Tariff 118 2. Additional Interim Revisions to the Pro Forma Tariff 121 B. Independent Transmission and Markets 124 1. Independent Transmission Providers 125 2. Role of Independent Transmission Companies in Standard Market Design 132 C. The New Transmission Service 136 1. Basic Rights 139 2. Access to Transmission Service 143 3. Service Limitations in the Existing Pro Forma Tariff 146 4. Conditions for Receiving Service 148 5. Scheduling Transmission Service and Acquiring Congestion Revenue Rights 149 6. Designating Resources and Loads 152 7. Substituting Receipt and Delivery Points 154 8. System Impact and Facilities Studies 157 9. Load Shedding and Curtailments 158 10. Trading (Reassigning) Congestion Revenue Rights 162 11. Ancillary Services 164 D. Transmission Pricing 165 1. Recovery of Embedded Costs 167 2. Rates for Bundled Retail Customers 176 3. Inter-Regional Transfers 179 4. Application of Inter-Regional Pricing to Parallel Path Flows 190 5. Pricing of New Transmission Capacity 191 E. The New Congestion Management System 203 1. Locational Marginal Pricing 204 2. LMP and Energy Markets 221 3. Congestion Revenue Rights 235 a. General Features 237 b. Types of Congestion Revenue Rights 241 (1) Receipt Point-to-Delivery Point Rights 242 (2) Obligations and Options 245 (3) Flowgate Rights 246 c. Requirement for Offering Rights 248 d. Funding for the Congestion Revenue Rights 250 e. Auctions and Resales of Congestion Revenue Rights 252 f. Including Energy and Ancillary Services in the Congestion Revenue Rights Auctions 254 F. Day-Ahead and Real-Time Market Services 256 1. Design of the Day-Ahead Markets 257 a. Scheduling Transmission Service Day Ahead 258 (1) General Features 258 (2) Transmission Service Across Borders 264 b. Transmission Losses 267 c. Day-Ahead Energy Market 269 (1) General Features 269 (2) Bidding and Scheduling Rules 270 (3) Price Determination and Settlement 277 d. Day-Ahead Ancillary Service Markets 284 (1) General Features 284 (2) Bidding and Scheduling Rules 287 (3) Price Determination and Settlement 291 2. Scheduling After the Close of the Day-Ahead Market 298 a. Replacement Reserves 298 b. Changes to Transmission Schedules 303 3. Design of the Real-Time Markets 305 a. Real-Time Energy Markets 306 (1) General Features 306 (2) Bidding and Scheduling Rules 307 (3) Price Determination and Settlement 310 b. Real-Time Ancillary Services Markets 320 4. Market Rules for Shortages or Emergencies 326 G. Other Changes to Improve the Efficiency of the Markets under Standard Market Design 328 1. Capacity Benefit Margin 330 2. Regional and Independent Calculation of Available Transfer Capability, Performance of Facilities Studies and OASIS 333 3. Regional Planning Process 335 4. Modular Software Design 351 5. Transmission Facilities That Must be Under the Control of an Independent Transmission Provider 361 a. Before Order No. 888 362 b. Order No. 888 365 c. Test for Transmission Facilities 367 H. Transition to Single Transmission Tariff 370 1. Treatment of Customers under Existing Wholesale Contracts 372 2. Allocation of Congestion Revenue Rights 376 3. Reciprocity Provision 383 4. Force Majeure and Indemnification Provisions 385 I. Market Power Mitigation and Monitoring in Markets Operated by the Independent Transmission Provider 390 1. Principles and Objectives 390 2. Overview of the Market Power Mitigation Measures 398 3. Market Power Mitigation for Local Market Power 406 4. The Safety-Net Bid Cap 413 5. Mitigation Triggered by Market Conditions 415 6. Establishing Bid Caps or Competitive Reference Bids 418 7. Exemptions 428 8. Monitoring 429 a. Framework for Analyzing Market Structure and Market Conduct 436 b. Data Requirements and Data Collection 447 c. Reporting Requirements 451 d. Enforcement of the Tariff Rules 454 J. Long-Term Resource Adequacy 457 1. The Reason for the Requirement 460 a. Spot Market Prices Alone Will Not Signal The Need to Begin Development of New Resources in Time to Avert a Shortage 462 b. Spot Market Prices that are Subject to Mitigation Measures May Not Produce an Adequate Level of Investment When a Shortage Occurs 467 c. Load-Serving Entities Will Underinvest in Resources Needed for Reliability if They Can Depend on the Resource Development Investments of Others 469 2. Basic Features of the Requirement 474 a. Demand Forecast 485 b. Level of Resource Adequacy 487 c. Load-Serving Entities 494 d. Load-Serving Entity's Share of the Regional Resource Requirement 497 e. Resources That Can Satisfy the Resource Needs 503 (1) Generation and Transmission 504 (2) Demand Response 507 3. Resource Standards 509 a. Generation Standards 511 b. Transmission Standards 514 c. Demand Response Standards 517 4. Planning Horizon 520 5. Enforcement 526 6. Regional Flexibility 542 K. State Participation in RTO Operations 551 L. Governance for Independent Transmission Providers 556 1. Responsibilities of the Board of Directors 558 2. Stakeholder Participation 560 3. Initial Selection Process for Board of Directors 562 4. Succession of Board Members 569 5. Mergers of Independent Transmission Providers 573 M. System Security 575 V. Implementation 580 VI. Public Comment Procedures 595 VII. Regulatory Flexibility Act 599 VIII. Environmental Statement 603 IX. Public Reporting Burden and Information Collection Statement 604 X. Document Availability 612 Regulatory Text Appendices A. Interim Pro Forma Tariff Revisions B. Standard Market Design Tariff (SMD Tariff) C. Examples of Flaws in the Current Regulatory Environment D. Conversion of the Order No. 888-A Pro Forma Tariff to the Revised Standard Market Design Pro Forma Tariff E. Standard Market Design and Trading Strategies Encountered in the Independent Transmission System Operators F. Access Charges and Congestion Revenue Rights G. Form for the Annual Self-Certification of Compliance with FERC Security Standards I. Introduction 1. This notice of proposed rulemaking represents the third in a series of initiatives undertaken by the Commission to harness the benefits of competitive markets for the nation's electric energy customers, in order to meet our statutory responsibility to assure adequate and reliable supplies of electric energy at a just and reasonable price. In 1996, the Commission issued Order No. 888, which required, as a remedy for undue discrimination, that all public utilities provide open access transmission. 1 In 1999, the Commission issued Order No. 2000. 2 The Commission's objective was “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 [RTOs] in a timely manner.” 3 1 Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12,274 (March 14, 1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part, remanded in part on other grounds sub nom. Transmission Access Policy Study Group, et al. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 122 S. Ct. 1012 (2002). 2 Regional Transmission Organizations, Order No. 2000, 65 FR 809 (January 6, 2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh'g, Order No. 2000-A, 65 FR 12,088 (February 25, 2000), FERC Stats. & Regs ¶ 31,092 (2000), petitions for review dismissed, Public Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001). 3 Regional Transmission Organizations, 64 FR 31,389 (May 13, 1999), FERC Stats. & Regs. ¶ 32,541 at 33,685 (1999) (Notice of Proposed Rulemaking). 2. Order No. 888 and Order No. 2000 set the foundation upon which to build regional transmission institutions and competitive electricity markets. However, as events have transpired, there remain significant impediments to competitive markets and to the infrastructure needed to meet our electric energy demand. Unduly discriminatory transmission practices have continued to occur and inconsistent design and administration of short-term energy markets has resulted in pricing inefficiencies that can cause rates to be unjust and unreasonable. At the same time, the nature of the electric industry has changed in a way that makes the development of competitive wholesale markets all the more critical. The electric industry has evolved from one characterized by large, vertically integrated utilities to an industry with increasing wholesale trade and increasing numbers of independent buyers and sellers of wholesale power seeking non-discriminatory access to transmission facilities. Public utilities today purchase significantly more wholesale power to meet their load than in the past. Indeed, from 1989 through 2000, their wholesale purchases increased from 18 percent of their total available electric energy to over 37 percent, and this percentage is expected to continue to grow. 4 4 See Section III.C. for a more detailed discussion. 3. The Commission's objectives in this third rulemaking initiative, therefore, are to remedy remaining undue discrimination and establish a standardized transmission service and wholesale electric market design that will provide a level playing field for all entities that seek to participate in wholesale electric markets. The Commission proposes to provide new choices through a flexible transmission service, and an open and transparent spot market 5 design that provides the right pricing signals for investment in transmission and generation facilities, as well as investment in demand reduction. 5 The term “spot market” typically refers to a trade that covers a short period in the very near future. Trading in an independent transmission system operator (ISO) real-time or day-ahead market is referred to here as occurring in the spot market. In the Western price mitigation order, the Commission defined a spot market trade as any trade lasting 24 hours or less, whether a bilateral trade or a trade occurring in an organized real-time or day-ahead market that does not match up particular sellers and buyers. See San Diego Gas and Electric Company v. Sellers of Energy and Ancillary Services into Markets Operated by the California Independent System Operator and the California Power Exchange, 95 FERC ¶ 61,418 at 64,525 n.3 (2001). We will adopt this meaning for this rulemaking. 4. When supply and demand do not support fully competitive markets, market design should provide protection against market power. We seek in this rulemaking to put in place sufficient regulatory backstops to protect customers against the exercise of market power when structures do not support a competitive market. Market monitoring at all times, and market power mitigation when needed, are critical pieces of this initiative. 5. A significant impediment to achieving the full benefits of competition is that there is no single set of rules governing transmission of electric energy. Not only does the Order No. 888 pro forma tariff contain provisions that allow different types of customers to be treated differently, but there also are conflicting state and Federal rules governing the use of interstate transmission facilities. This provides opportunities for transmission providers to establish and apply rules in a way that unduly discriminates against certain classes of customers, leads to significant transaction costs and threatens reliability. 6. To remedy undue discrimination, enhance competition, remove economic inefficiencies and ensure just and reasonable rates, terms and conditions transmission of electric energy, the Commission proposes to: Exercise jurisdiction over the transmission component of bundled retail transactions; modify the existing pro forma transmission tariff to include a single flexible transmission service (Network Access Service) that applies consistent transmission rules for all transmission customers—wholesale, unbundled retail and bundled retail; and provide a standard market design for wholesale electric markets. While it is critical that the same non-rate terms and conditions be applied to all transmission uses, including bundled retail, as soon as possible, we intend to work closely with our state colleagues with respect to transition issues involving bundled retail transmission rates 7. The proposed Network Access Service would combine features of both existing open access transmission services—the flexibility and resource and load integration of Network Integration Transmission Service; and the reassignment rights of Point-to-Point Transmission Service. It would give a customer the right to transmit power between any points on the transmission system—so long as the transaction is feasible under a security-constrained dispatch. 8. We expect that most if not all entities will become members of RTOs and that the new Network Access Service would be provided through these RTOs. However, this rule may become effective at a time when some transmission owners and operators have not yet become members of functioning RTOs. Thus, we propose that all transmission owners and operators that have not yet joined an RTO must contract with an independent entity to operate their transmission facilities. This proposed rule refers to both the RTO and those independent entities as “Independent Transmission Providers.” An Independent Transmission Provider would have no financial interest, either directly or through an affiliate, as defined in section 2(a)(11) of the Public Utility Holding Company Act (15 U.S.C. 79b(a)(11), in any market participant 6 in the region in which it provides transmission services or in neighboring regions. We propose that all Independent Transmission Providers administer the day-ahead and real-time markets. As discussed infra, we also have identified long-term planning and expansion, system impact and facilities studies and transmission transfer capability calculations (including postings on an Open Access Same-time Information System (OASIS)) as tasks that must be done on a regional basis. Thus, we propose that all Independent Transmission Providers perform these tasks. 6 A market participant means: (i) Any entity that, either directly or through an affiliate, sells or brokers electric energy, or provides ancillary services to the [RTO], unless the Commission finds that the entity does not have economic or commercial interests that would be significantly affected by the [RTO's] actions or decisions; and (ii) Any entity that the Commission finds has economic or commercial interests that would be significantly affected by the [RTO's] actions or decisions. 18 CFR 35.34 (2) (2002). 9. In addition to creating the new Network Access Service, the revised tariff would include requirements to standardize wholesale electric market design. The fundamental goal of the Standard Market Design requirements, in conjunction with the standardized transmission service, is to create “seamless” wholesale power markets that allow sellers to transact easily across transmission grid boundaries and that allow customers to receive the benefits of lower-cost and more reliable electric supply. For example, currently a supplier that seeks to serve load in a distant state may need to cross several utility systems or independent system operator systems (ISOs), all of which have different rules for such things as reserving and scheduling transmission and scheduling generation. This can either result in an efficient transaction not occurring at all or it can add significant time and costs to the transaction. Standard Market Design seeks to eliminate such impediments. 10. Central to the Standard Market Design concept is its reliance on bilateral contracts entered into between buyers and sellers. The resource adequacy requirement strongly encourages such long-term contracts. The short-term spot markets set out below are intended to complement bilateral procurement. To handle generation imbalances and the procurement of ancillary services, the Commission proposes to require that all Independent Transmission Providers operate markets for energy and for the procurement of certain ancillary services in conjunction with markets for transmission service. These markets would be bid-based, security-constrained spot markets operated in two time frames: (1) A day ahead of real-time operations, and (2) in real time. The adoption of a market-based locational marginal pricing (LMP) transmission congestion management system is designed to provide a mechanism for allocating scarce transmission capacity to those who value it most, while also sending proper price signals to encourage short-term efficiency in the provision of transmission service as well as wholesale energy, and to encourage long-term efficiency in the development of transmission, generation and demand response infrastructure. We expect that market participants will strike an appropriate balance between bilateral contracts and spot market transactions. Efficient spot markets with appropriate price signals bring bilateral and spot market prices closer together, helping to assure customers of efficient bilateral markets. 11. Several changes required by Standard Market Design promote greater customer access to low-cost power. We note that this may raise concerns that cheap power may leave one region for sale in another, higher-priced region. This can only happen with generation that is not already under contract for purchase. Thus, customers in low-cost regions can ensure that low-cost power “stays home” by contracting for that power. This way, only excess power will leave the region to serve another market. 12. The Commission proposes a pricing policy and process for recovering the costs of new transmission investment so as to develop the infrastructure needed to support competitive markets. The policy builds on the price signals provided by the proposed spot market design. However, there are cases where LMP price signals alone will not encourage all beneficial transmission investments. Therefore, we propose to require market participants to participate in a regional process to identify the most efficient and effective means to maintain reliability and eliminate critical transmission constraints. 13. Even with good market design rules, current supply and demand conditions make a market monitoring and market power mitigation plan necessary. The market power mitigation proposed in this rule would rely on a combination of methods to protect against the exercise of market power by preventing sellers from withholding economical supplies from the market, while permitting prices to reflect true scarcity. The proposed market power mitigation method should be more restrictive at times or places where the exercise of market power is more likely to occur than at times or places where the market is sufficiently competitive. 14. However, because market power mitigation may tend to suppress scarcity prices that signal the need for investment, a companion mechanism besides spot prices is needed. The Commission proposes a resource adequacy requirement to ensure adequate electric generating, transmission and demand response infrastructure, the level of which is to be determined on a regional basis. Recognizing that supply planning and retail customer demand response are the states' responsibility, the Commission proposes a resource adequacy requirement intended to complement existing state programs. In particular, the Commission proposes that an RTO or other regional entity must forecast the region's future resource needs, facilitate regional determination of an adequate future level of resources and assess the adequacy of the plans of load-serving entities 7 to meet the regional needs. Each load-serving entity would be required to meet its share of the future regional need through a combination of generation and demand reduction. 7 A load-serving entity is an entity, including a municipal electric system and an electric cooperative, authorized by law, regulatory authorization or requirement, agreement, or contractual obligation to supply energy, capacity, and/or ancillary services to retail customers located within the transmission provider's service area, including an entity that takes service directly from the transmission provider to supply its own load in the transmission provider's service area. See SMD Tariff § 1. 15. In summary, in this proceeding, the Commission, pursuant to its authority under sections 205 and 206 of the Federal Power Act, 8 proposes to: 8 16 U.S.C. 824d and 824e (1994). (1) Establish a single non-discriminatory open access transmission tariff with a single transmission service (Network Access Service) that is applicable to all users of the interstate transmission grid: wholesale and unbundled retail transmission customers, and bundled retail customers; (2) Require all public utilities that own, control or operate interstate transmission facilities to become an Independent Transmission Provider, turn over their transmission facilities to an Independent Transmission Provider or contract with an Independent Transmission Provider to operate their facilities. An Independent Transmission Provider is any public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce, that administers the day-ahead and real-time energy and ancillary services markets in connection with its provision of transmission services pursuant to the SMD Tariff, and that is independent ( i.e. , has no financial interest, either directly or through an affiliate, as defined in section 2(a)(11) of the Public Utility Holding Company Act (15 U.S.C. 79b(a)(11), in any market participant in the region in which it provides transmission service or in neighboring regions). (3) Require that an Independent Transmission Provider provide transmission services and administer the day-ahead and real-time energy and ancillary services markets; (4) Establish an access charge to recover embedded transmission costs based on a customer's load ratio share of the Independent Transmission Provider's costs, and would be paid by any customer taking power off the grid; 9 9 As explained in section IV.D.1, current long-term point-to-point customers that seek to receive Congestion Revenue Rights would also pay the access charge. (5) Use LMP as the system for transmission congestion management and provide tradable financial rights—Congestion Revenue Rights 10 as a means to lock in a fixed price for transmission service; 10 These rights were called “Transmission Rights” in the Working Paper on Standardized Transmission Service and Wholesale Electric Market Design, Docket No. RM01-12-000 (Mar. 15, 2002) (hereinafter Working Paper). (6) Establish a preference for the auction of Congestion Revenue Rights, but initially allow regional flexibility for a four-year transition period in determining whether to allocate Congestion Revenue Rights to existing customers or auction such rights such that revenues are allocated to existing customers to hold them financially harmless; (7) Establish open imbalance energy markets to allow all market participants to buy or sell their imbalances in a fair, efficient and non-discriminatory market. Imbalance markets would be neutral towards fuel sources and treat demand resources on an equal footing with supply; (8) Permit customers under existing contracts to receive the same level and quality of service under Standard Market Design that they receive under their current contracts, to the greatest extent feasible; (9) Establish procedures to mitigate market power in the day-ahead and real-time markets required by Standard Market Design and mechanisms for market monitoring; (10) Establish procedures to assure, on a long-term regional basis, that there are adequate transmission, generation and demand-side resources; (11) Provide a formal role for state representatives to participate in the decision-making processes of Independent Transmission Providers; and (12) Clarify the obligation of all users of the transmission system to comply with all appropriate standards for ensuring system security and reliability. 16. The Commission's focus is on promoting the development of competitive wholesale markets and we do not intend to interfere with the legitimate concerns of state regulatory authorities. It remains within a state's authority to determine whether or not to provide retail access. Nevertheless, the reforms proposed in this rulemaking will benefit customers in states with or without retail access. In addition, we seek to formally involve state representatives in the decision-making processes of regional entities. We also recognize the need to permit parties to continue to rely on existing contracts and scheduling practices, including those involving hydroelectric power, and these are fully accommodated under Standard Market Design. 17. The Commission recognizes that differences exist throughout the regions of the country; however, the Commission's goal is to remedy undue discrimination by standardizing transmission service and wholesale electric market design as much as possible. We propose to allow certain regional variations, as described infra . 18. Finally, the Commission recognizes that implementation of a revised open access transmission tariff and Standard Market Design on a nationwide basis may take some time. Thus, the Commission proposes a phased compliance process. By July 31, 2003, all public utilities that own, operate or control interstate transmission facilities must file revised open access transmission tariffs (Interim Tariffs) to become effective September 30, 2004, that reflect the inclusion of bundled retail customers as eligible customers. By December 1, 2003, all public utilities that own, control or operate interstate transmission facilities must file revised open access transmission tariffs (SMD Tariffs), to become effective no later than September 30, 2004, or such other time as directed by the Commission, that reflect all of the remaining revisions and requirements of the Final Rule in this proceeding. The Commission and its staff will work with regional organizations and stakeholders in facilitating full and efficient compliance with this rule. 19. Below in Section II we set out the relevant developments in the electric industry. In Section III and Appendix C we explain the need for further reform. In Appendix E, we discuss various allegations of market manipulation strategies encountered in the organized markets and how Standard Market Design will address these strategies. In Section IV we explain our specific remedy for pervasive problems in the industry consistent with our statutory responsibilities. In Section V, we set out the implementation process and dates. Finally, the glossary for the terms used in this document is found in the Definitions section of the SMD Tariff in Appendix B, and the revisions to the Interim Tariff are set out in Appendix A. II. Background: Order No. 888 and Order No. 2000 A. Order Nos. 888 and 888-A 20. In April 1996, in Order No. 888, the Commission found that unduly discriminatory and anticompetitive practices existed in the electric industry, and that public utilities that own, control or operate interstate transmission facilities had discriminated against others seeking transmission access. It 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. 11 The Commission stated that its goal was to ensure that customers have the benefits of competitively priced generation. 11 See Order No. 888 at 31,652. 21. 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 certain minimum, non-price terms and conditions, and (2) functionally unbundle wholesale power services from transmission services. 12 Functional unbundling requires public utilities to: (1) Take wholesale transmission services under the same tariff of general applicability as they offer their customers; (2) state separate rates for wholesale generation, transmission, and ancillary services; and (3) rely on the same electronic information network that their transmission customers rely on to obtain information about the utilities' transmission systems. 13 In Order No. 889, issued concurrent with Order No. 888, the Commission also imposed standards of conduct governing communications between the utility's transmission and wholesale power functions, to prevent the utility from giving its power marketing arm preferential access to transmission information. 14 Under Order No. 889, all public utilities that own, control or operate facilities used in the transmission of electric energy in interstate commerce are required to create or participate in an OASIS that provides existing and potential transmission customers the same access to transmission information that will enable them to obtain open access non-discriminatory transmission service. 12 See id. at 31,635-36. 13 See id. at 31,654. 14 See Open Access Same-Time Information System and Standards of Conduct, Order No. 889, 61 FR 21,737 (April 24 1996), FERC Stats. & Regs. ¶ 31,035 at 31,588-91 (1996), order on reh'g, Order No. 889-A, 62 FR 12,484 (March 4, 1997), FERC Stats. & Regs. ¶ 31,049 (1997). 22. The Commission declined to require corporate unbundling at the time of Order No. 888, and stated instead that efforts to remedy undue discrimination should begin by requiring the less intrusive functional unbundling approach. 15 While the Commission in Order No. 888 encouraged the creation of ISOs and set forth eleven principles for assessing ISO proposals submitted to the Commission, it did not mandate regional organizations. 16 The Commission in Order No. 888 stated: 15 See Order No. 888 at 31,654. 16 See id. at 31,730-32. [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. 17 17 Id. at 31,655. Order No. 888-A reaffirmed the findings of Order No. 888. The Court of Appeals for the District of Columbia Circuit upheld the orders “in nearly all respects.” 18 The Supreme Court recently affirmed. 19 18 Transmission Access Policy Study Group, 225 F.3d at 681. 19 See New York v. FERC, 122 S.Ct. 1012. 23. A number of significant developments took place in the electric utility industry following issuance of Order No. 888. All public utilities filed non-discriminatory, open access transmission tariffs stating rates, terms and conditions for comparable wholesale transmission service to third-party users of their transmission systems. With the advent of OASIS systems, improved information about transmission systems became available to all participants in the bulk power market at the same time that it was available to utilities' own wholesale merchant functions and wholesale marketing affiliates (although further information improvements are still needed). New generation resources were developed in areas that had experienced generation shortages. 20 Regional trading patterns have expanded. In addition, the Commission granted a large number of merger applications and applications to charge market-based rates, effecting structural changes in the industry. The industry thus became less localized and more regionalized, with a growing need for regional planning and regulation. And as part of that regionalization, the Commission also approved voluntary ISOs in five regions of the country—New England, New York, PJM, 21 the Midwest and California (an ISO was also formed in ERCOT, but it is not under the Commission's full jurisdiction). These ISOs are the precursors to regional entities identified as RTOs, in the Commission's Order No. 2000, discussed below. 20 See Staff Report to the Federal Energy Regulatory Commission on the Causes of the Pricing Abnormalities in the Midwest During June 1998 (1998), available in http://www.ferc.gov/electric/mastback.pdf. 21 The PJM ISO takes its name from the former Pennsylvania, New Jersey, Maryland Power Pool, which serves New Jersey, Maryland, Delaware, much of eastern Pennsylvania, the District of Columbia, and a small area of Virginia. B. Order No. 2000 24. Order No. 2000, issued in December 1999, was the Commission's second major step toward establishing competitive wholesale power markets and eliminating residual undue discrimination in interstate transmission services. It identified two broad categories of impediments to competitive electricity markets: (1) The engineering and economic inefficiencies inherent in the current operation and expansion of the transmission grid, and (2) 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. 22 Further, evidence indicated that local management of the transmission grid by many individual vertically integrated utilities was inadequate to support the efficient, reliable regionwide operation that was needed for continued development of competitive markets. The Commission concluded that establishing independent RTOs would eliminate residual undue discrimination in transmission, enhance the benefits of competitive electricity markets, and could: (1) Improve efficiency in transmission grid management; (2) improve grid reliability; (3) remove remaining opportunities for discriminatory transmission practices; (4) improve market performance; and (5) facilitate lighter-handed regulation. The Commission anticipated that formation of regional transmission grids would result in a substantial cost savings to the electric utility industry and its customers. 23 22 Order No. 2000 identified four specific areas of concerns: (1) Calculation and posting of Available Transfer Capability in a manner favorable to the transmission provider; (2) standards of conduct violations; (3) line loading relief and congestion management; and (4) OASIS sites that are difficult to use. See Order No. 2000 at 31,005 n.69. The order also identified parallel path flows, planning and investing in new transmission facilities, pancaking of access charges, the absence of secondary markets in transmission service and the possible disincentives created by the level and structure of transmission rates. See id. at 31,014. 23 See id. at 30,993. 25. Order No. 2000 encouraged all transmission owners to voluntarily place their transmission facilities in the hands of appropriate RTOs. The Commission stated that RTOs could include ISOs or independent for-profit transmission companies (ITCs). However, all RTOs must meet four minimum characteristics and eight minimum functions that were identified in Order No. 2000, and also must have an open architecture framework that would permit an RTO and its members flexibility to improve their structures over time. 24 24 The four RTO characteristics are: (1) Independence; (2) scope and regional configuration; (3) operational authority; and (4) short-term reliability. The eight RTO functions are: (1) Tariff administration and design; (2) congestion management; (3) parallel path flow; (4) ancillary services; (5) OASIS, Total Transfer Capability and Available Transfer Capability; (6) market monitoring; (7) planning and expansion; and (8) interregional coordination. See Order No. 2000 at 30,993-94. 26. Following Order No. 2000, some transmission-owning public utilities began to file proposals to participate in RTOs. The process has been slow for several reasons, one of which is stakeholder uncertainty about what the Commission would require for RTO approval—not only for the RTO scope and independence characteristics, but also regarding such RTO functions as congestion management and market-oriented provision of ancillary services. 27. Order No. 2000 called for RTOs to be in operation across the nation by December 2001. To date, there is only one RTO fully approved by the Commission, the Midwest ISO, which began operating in early 2002. 25 The Midwest ISO is large. It stretches from an eastern boundary in western Pennsylvania westward to the Rocky Mountains, northward into Manitoba, Canada and southward to the Texas border. 25 See Midwest Independent System Operator, Inc., 97 FERC ¶ 61,326 (2001). 28. Although progress with Commission-approved RTOs has been slow, regionalization has also occurred through the ISO formation process that was encouraged in Order No. 888. The Northeast and California ISOs are engaged in a process to become Commission-approved RTOs or to join larger RTOs. In eastern North America, close coordination is developing between U.S. and Canadian transmission systems and market designs. 29. In addition to the Midwest ISO, the Commission has provisionally approved other RTOs, 26 and authorized operation of ITCs that operate under an RTO umbrella. 27 The Commission also ordered Northeastern and Southeastern RTO applicants, including some applicants whose RTO proposals had been provisionally approved, into mediation proceedings to facilitate the formation of RTOs in those areas. 28 The Commission further noted that a “west wide RTO, or a seamless integration of Western RTOs, is the best vehicle for designing and implementing a long-term regional solution” to the West's electric generation supply crisis. 29 26 See GridSouth Transco, LLC, 94 FERC ¶ 61,273 (2001); GridFlorida, LLC, 94 FERC ¶61,363 (2001); and PJM Interconnection, LLC, 96 FERC ¶61,061 (2001). 27 See TRANSLink Transmission Company, L.L.C., et al., 99 FERC ¶61,106 (2002) (authorizing operation of ITC within the Midwest ISO), reh'g pending, [Docket Nos. EC01-156-001 et al.; Alliance Companies, et al., 99 FERC ¶61,105 (2002) (authorizing the operation of an ITC). 28 See Regional Transmission Organizations, 96 FERC ¶61,065 (2001) (initiating mediation proceedings between Northeastern RTO applicants); Regional Transmission Organizations, 96 FERC ¶61,066 (2001) (initiating mediation proceedings between Southeastern RTO applicants). 29 Removing Obstacles to Increased Electric Generation and Natural Gas Supply in the Western United States, 94 FERC ¶61,272 at 61,974 (2001). A coalition of Western utilities (RTO West Filing Utilities) filed a proposal on October 16, 2001 to create RTO West. The Commission granted several of the RTO West Filing Utilities' requests for declaratory order on April 26, 2001, finding some of RTO West's proposed characteristics and functions compliant with Order No. 2000. See Avista Corporation, et al., 95 FERC ¶61,114 (2001). The RTO West Filing Utilities then filed a proposal for Stage 2 of RTO West's creation on March 28, 2002. The Stage 2 proposal is intended to enable the Commission to determine whether the RTO West proposal fulfills all of the Order No. 2000 characteristics and functions. See Stage 2 Filing and Request for Declaratory Order Pursuant to Order 2000 at 5, Docket No. RT01-35-000 (Mar. 28, 2002). 30. The following section and related Appendix C discuss specific features of today's wholesale electricity markets that inhibit the development of competition and efficient regional markets, and identify areas in which the Commission must direct reforms to eliminate remaining undue discrimination and inefficiencies, and ensure just and reasonable rates. III. Need for Reform A. Undue Discrimination and Impediments to Competition Remain 31. Since the issuance of Order Nos. 888 and 2000, it has become clear that additional, mandatory measures are needed to achieve the goals of non-discriminatory transmission access and competition in electricity markets. Vertically integrated transmission owners and operators continue to use their interstate transmission facilities in ways that inhibit competition in wholesale power markets as well as competition in those retail power markets where states have adopted retail choice. The discriminatory preferences that these transmission owners and operators give to their own uses of the interstate transmission grid to serve their retail customers (whether or not they are in retail choice states) results in discrimination against, and in costs being borne by, other wholesale and retail customers who also rely on the interstate transmission facilities to buy power. The discriminatory preferences also create barriers to new sellers that could provide lower-cost power. This could result in higher prices to the native load served by the transmission owner. For example, transmission-dependent utilities 30 and other load-serving entities need the interstate transmission facilities to move power they are purchasing by contract from distant generators or suppliers, but allege that despite the requirements of Order No. 888, they are denied comparable access to the grid. Similarly, new generators wishing to compete in wholesale markets or for retail customers in retail choice states tell us that they are denied comparable access to the grid, thus inhibiting entry of new, lower-cost, efficient and environmentally superior power suppliers. 30 A transmission-dependent utility is a utility that does not own generation and relies on its neighboring utilities to transmit power to it that it purchases from its suppliers. 32. The Commission recently has taken additional steps to address some of the remaining impediments to non-discriminatory transmission access and competition in wholesale power markets. For example, the Commission's recently issued Generator Interconnection proposed rule seeks to remove one particular type of undue discrimination occurring in the marketplace—barriers to obtaining interconnections to the interstate transmission grid—so that new generators can compete with vertically integrated transmission providers to serve load. 31 However, this initiative will resolve only one aspect of remaining discriminatory practices. Other opportunities for vertically integrated transmission providers to operate in ways that favor their own generation remain within the construct of the pro forma tariff ( e.g. , preferences for native load and network customers to reserve transmission capability, differing transmission services that raise barriers to competition, the lack of inclusion of all services under the same tariff). As noted in Order No. 2000, “perceptions of discrimination are significant impediments to competitive markets. Efficient and competitive markets will develop only if market participants have confidence that the system is administered fairly.” 32 31 See Standardization of Generator Interconnection Agreements and Procedures, 67 FR 22,249 (May 2, 2002), FERC Stats. & Regs. ¶32,560 at 34,174 (2002) (Notice of Proposed Rulemaking). The proposed rule defines interconnection study time frames and grants all generators the opportunity to be treated as competing network resources in meeting load and load growth. See id. at 34,243-45. 32 Order No. 2000 at 31,017. Lack of market confidence may lead to 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 a competitive advantage to their affiliated power marketers. It may also deter generation expansion and lead to the perception that the transmission provider's generation is more reliable, thereby reducing competition and raising prices for customers. See id. 33. Furthermore, it has become apparent that there are also opportunities to discriminate and to hinder an efficient, competitive marketplace due to the absence of standardization with respect to market rules and practices within and between regional markets. So-called “seams” problems ( e.g. , different rules and different pricing systems) create transaction costs and artificial barriers to trade. These problems inhibit the Commission from fulfilling its statutory responsibility to ensure that customers receive reliable power supplies at the lowest reasonable costs. 33 33 See FPC v. Hope Natural Gas Company, 320 U.S. 591, 610 (1944). 34. Finally, innovation that the Commission expected to see with respect to new service offerings has been sporadic and unsteady. Innovations in transmission control and pricing ( e.g. , ISO control of transmission and LMP for generation and transmission services in the Northeast, RTO formation in the Midwest), while impressive, have been slow to take root in other regions of the country. The pro forma tariff was envisioned as the baseline above which transmission providers were encouraged to develop competitive and customer-responsive service offerings. But Florida Power Corporation's network contract demand service, a hybrid of Network Integration Transmission Service and Point-to-Point Transmission Service features, 34 and Duke Energy Corporation's “recallable long-term firm” service 35 are the only noteworthy new services accepted by the Commission for use with a single utility's open access transmission tariff. Other proposed pro forma tariff revisions amounted to little more than working around the edges of the existing services and procedures and did not produce more competitive transmission service that reduces overall electricity costs. 34 See Florida Power Corporation, 81 FERC ¶ 61,247 (1997). 35 See Duke Energy Corporation, 88 FERC ¶ 61,184, reh'g denied, 89 FERC ¶ 61,190 (1999). 35. Most ISOs recently introduced centralized short-term real-time hourly markets and day-ahead markets for energy ( i.e. , spot markets) where sellers sell into the market and buyers buy from the market without matching a particular seller with a particular buyer. In such organized spot markets, there is a single market clearing price established that is received by all generators who bid into the market below that price and is paid by all load that bids in above that price. However, the ability of customers to bid demand reductions into the spot market in response to supplier prices is still limited and needs to be improved significantly for short-term markets to operate more competitively. Further, while there have been benefits of market development in the Northeast (PJM, New York ISO, ISO-New England), Texas and California (during the first two years of its restructuring), the Midwest ISO is still in the formative stages of operation with respect to markets, and few market benefits have materialized in the Southeast and West. B. Specific Instances of Undue Discrimination and Impediments to Competition 36. The specific reasons for requiring reform are many. Market participants have identified, through formal complaints, hotline calls, public conferences, and pleadings, the difficulties they have experienced in gaining equal access to the transmission grid to compete with vertically integrated utilities to serve load. Much of this problem is directly attributable to the remaining ability of such vertically integrated utilities (and the existence of sufficient incentives) to exercise some degree of transmission market power in order to protect their own generation market share. Further complicating transmission access is the fact that not all transmission service is provided under the rates, terms and conditions of the Commission's pro forma tariff. Rather, over 60 percent of load has been subject to various state rules governing the transmission component of bundled retail transactions. Independent transmission service under a common set of rules would solve many of these problems. 37. Nevertheless, new problems have been created by some of the market design experiments. In regions of the country where the separation of transmission from generation has been addressed through the creation of ISOs (which, in some instances, have placed nearly all load under a single tariff), market design flaws create inefficiencies in the marketplace and opportunities for the exercise of market power. Conflicting market rules and procedures in neighboring ISOs have created or perpetuated seams problems that impede the economic flow of power from one region to another. All of these problems have hindered the progress towards competitive regional electricity markets. Standard Market Design is intended to address these problems. 1. Transmission Market Power by Utilities That Are Not Independent 38. By differing means, Order Nos. 888 and 2000 attempt to effect open access transmission by reducing the ability of transmission owners that also own generators to act in anticompetitive or unduly discriminatory ways against other generators. In both orders, the Commission attempted to move the electric industry into a competitive wholesale market without mandating corporate restructuring. Through Order Nos. 888 and 2000, the Commission required open access to public utility transmission systems, encouraged the formation of ISOs and, later, RTOs to achieve control of the transmission grid by entities that are independent from generation marketing or sales. However, only limited portions of the country have moved beyond the basic requirements of open access ( e.g. , through the voluntary divestiture of generation or establishment of RTOs, ISOs, or ITCs). In the rest of the country, the remaining corporate ties between generation and transmission within public utilities have proven problematic for transmission access. Thus, across most of the nation, barriers to entry remain for new generators and new load-serving entities. 39. A large portion of this problem is directly attributable to the continued ability of vertically integrated transmission providers to exercise some degree of transmission market power to advantage their own or affiliated generation. The longer the vertically integrated transmission provider can use access to interconnection or transmission service to delay or prevent entry of competing generators to its service territory, the longer it can profit from its own generation sales with a limited threat of competition. Vertically integrated transmission providers have found numerous ways to delay or prevent entry of competitors, some within the existing rules and some by exceeding reasonable discretion afforded to the transmission provider. All of these are difficult to monitor or prevent with behavioral rules. 36 36 See Working Paper at 21 (Mar. 15, 2002); see also Comment of the Staff of the Bureau of Economics and Office of General Counsel of the Federal Trade Commission, Docket No. RM01-12-000 (July 23, 2002). 40. As part of Standard Market Design, we propose that an Independent Transmission Provider operate all transmission facilities. The requirement for independent control of the transmission grid, preferably by an RTO, resolves these types of problems. a. Load Growth 41. Under the current pro forma tariff, a transmission provider is required to plan its system to allow customers with existing long-term contracts to extend, or roll over, those contracts. 37 However, the transmission provider has a right to recall that transmission capacity if it identified in the initial agreement with the customer that it had projected native load growth that would require that transmission capacity. 38 Transmission providers have failed to identify any native load growth at the time of the initial agreement, and disputes have arisen with customers claiming they were denied the ability to roll over their contracts because the transmission provider claimed, well after the contract was executed, that the transmission capacity at issue was required to serve native load growth. 39 37 See Section 2.2 of the current pro forma tariff. 38 See Order No. 888-A at 30,277. 39 See Public Service Company of New Mexico v. Arizona Public Service Co., 99 FERC ¶ 61,162 (2002), for a recent example. In this case, the Commission directed APS to grant PSNM's request to extend its contract for 60 MW of Point-to-Point Transmission Service. APS had attempted to deny the rollover request on the basis that it had verbally informed PSNM that capacity would not be available due to APS's future native load growth. The Commission restated the principle that a transmission provider can deny a customer the ability to roll over its long-term firm service contract only if the transmission provider includes in the service agreement a specific limitation based on reasonably forecasted native load needs that will use the transmission capacity provided under the contract at the end of the contract term. 42. In Standard Market Design, we propose to eliminate the preference for future native load growth. Instead, since Congestion Revenue Rights will be used to assure price certainty, Congestion Revenue Rights will be apportioned based on historical use or by an auction, neither of which grants preference for future load growth by a particular supplier; this approach resolves these concerns. b. Delays in Responding to Requests for Service 43. Another type of anticompetitive behavior centers on a vertically integrated transmission provider delaying the processing of a competitor's request for new transmission service or interconnection (including the related system impact or facilities studies). Transmission providers have done so by failing to follow time lines or expansively interpreting the tariff procedures. These delays may be enough to cause the competing generator to lose the sale, particularly if the potential customer is concerned that it may lose service completely if it does not stay with the transmission provider. 40 40 See Kinder Morgan Power Co. v. Southern Company Services, Inc., 97 FERC ¶ 61,240 (2001), reh'g denied, 98 FERC ¶ 61,044 (2002) (finding Southern's interconnection procedures delayed and discriminated against customer's ability to develop new projects). 44. Under Standard Market Design, these types of delays are resolved through the requirement for an independent entity, preferably an RTO, to perform studies and calculate available transfer capability (ATC), 41 since an independent entity would have no incentive to favor one customer over another. 41 The Commission used the term ‘‘Available Transmission Capability” in Order No. 888 to describe the amount of additional capability available in the transmission network to accommodate additional transmission services. To be consistent with the term generally accepted throughout the industry, “Available Transfer Capability” will be used. c. Scheduling Advantages 45. A vertically integrated transmission provider has a structural advantage over many competitors to make economy sales or to serve its own load, primarily because it has a large portfolio of both generators and loads. A competitor with access only to generation outside of the control area and no native load has to identify the delivery point of its power before being able to secure transmission service. But a vertically integrated transmission provider does not have to identify a specific location on the grid to serve its load because its load is dispersed across its entire system. A vertically integrated transmission provider also does not have to identify a single generation location, but can run a combination of its own generators or purchase from lower cost-suppliers inside or outside of its system. It can schedule purchased power to one of its own loads (in place of power from one of its own generators) in order to secure transmission service for the purchase. Later, it can find a buyer for the power and schedule transmission service from one of its internal generators to the load. This often is enough of a scheduling advantage over a competing supplier to ensure that the transmission provider (or its affiliated power marketer) gets the sale. 46. While it is true that all network customers have these same rights and abilities, in many areas of the country the only customer using network service is the vertically integrated transmission provider. Moreover, the vertically integrated transmission provider's size of resources and loads is usually much greater than any other network customer, giving it that much more of an advantage in flexibility. In addition, the vertically integrated transmission provider may have an advantage through access to better or more transmission and other related information. 47. Under Standard Market Design, all transmission service will be provided under a new Network Access Service. Having one service for all customers will eliminate scheduling advantages of competing suppliers. d. Imbalance Resolution 48. Customers have also alleged that vertically integrated transmission providers have an advantage over competitors in the resolution of energy imbalances. Transmission providers with generation and load of their own can resolve their own energy imbalances through in-kind energy exchanges with neighboring systems. In contrast, other customers of the transmission provider face higher costs if they take service from other suppliers that could balance against each other. This difference gives the transmission provider a competitive advantage over other sellers of power. 49. Under Standard Market Design, all suppliers and loads on a system will resolve imbalances through the same energy imbalance procedures. This will remove any competitive advantage the transmission owner with its own generation and load may have over competing power suppliers. e. Available Transfer Capability and Affiliates 50. Another source of discrimination is the calculation of Available Transfer Capability. A transmission provider that is not independent calculates its Available Transfer Capability, using its own proprietary data and its own equations. This discretion gives it the ability and the opportunity to discriminate in its own favor against entities that rely upon the OASIS for Available Transfer Capability information. In several cases, the Commission has found that utilities' OASIS postings reflect an inaccurate Available Transfer Capability. Indeed, in response to “serious concerns about the integrity of the postings of ATC” on the OASIS systems of two transmission providers, the Commission required the transmission providers to employ an independent third party to administer their OASIS systems. 42 42 See AEP Power Marketing, Inc., et al., 97 FERC ¶ 61,219 at 61,973 (2001), reh'g pending, Docket Nos. ER96-2495-016, et al. See also American Electric Power Company, Inc. and Central and South West Corporation, 90 FERC ¶ 61,242 at 61,789 (2000) (requiring AEP to turn over its OASIS and ATC calculation functions to an independent entity as a condition of the applicants' merger). See also Appendix C for other examples. 51. Under Standard Market Design, an independent entity will calculate Available Transfer Capability and schedule transmission service. This will eliminate this potential for undue discrimination. f. OASIS Postings 52. Manipulation or violation of OASIS posting requirements and the Commission's standards of conduct is another way vertically integrated transmission providers that control their own OASIS sites are able to engage in undue discrimination. This can occur through prohibited off-OASIS communications between the transmission provider and its affiliated market participant, e.g. , informing only the affiliate about Available Transfer Capability that will soon become available and posted on the OASIS so that the affiliate will be first in line to claim the capability. 43 Such abuses reinforce our belief that, in the absence of an independent entity calculating Available Transfer Capability and operating a transmission provider's OASIS, “a transmission provider's self-monitoring of its standards of conduct is not sufficient, and that it is essential for interested parties to be able to participate in this process” of reviewing communications between market participants. 44 Further, even with the best of intentions, it is not possible for a single transmission provider in a region to calculate Available Transfer Capability on its system alone without accounting for the transactions over all the other systems in its region and neighboring regions. 43 See Aquila Energy Marketing Corporation v. Niagara Mohawk Power Corporation, 87 FERC ¶ 61,328 (1999) (finding that off-OASIS communication between utility and its marketing affiliate led to preferential treatment of the affiliate); The Washington Water Power Company, 83 FERC ¶ 61,097 (1998) (finding favorable treatment of affiliate and expressing concern that this treatment may have been the result of prohibited off-OASIS communication). 44 Aquila Energy Marketing Corporation v. Niagara Mohawk Power Corporation, 87 FERC ¶ 61,238 at 62,279 (1999). 53. Similarly, control over the design, function and maintenance of OASIS systems may also present opportunities for discrimination. The Commission has been concerned for some time that transmission providers have the ability to impede competition by making their OASIS sites difficult to use, limiting users' access to OASIS and limiting access to information about transmission curtailments and interruptions that would allow the Commission to identify instances of undue discrimination. 45 45 See Regional Transmission Organizations, FERC Stats. & Regs. ¶ 32,541 at 33,713 (describing market participants' perceptions that transmission providers may use OASIS to discriminate among market participants); Open Access Same-Time Information System, 64 FR 34,117 (June 25, 1999), FERC Stats. & Regs. ¶ 31,075 (1999) (articulating changes to Commission regulations that would make available more information about transmission curtailments and interruptions and limit OASIS hosts' ability to disconnect users). 54. Under Standard Market Design, an independent entity will operate an OASIS on a regional basis, and thus will remove any advantages one seller may have over another and improve the accuracy of regional Available Transfer Capability postings on the OASIS. g. Capacity Benefit Margin Manipulation 55. The Commission has found instances of transmission providers taking advantage of their ability to reserve interface capability to serve their own load while limiting the ability of competing suppliers to access customers on its system. For instance, transmission providers have reserved excessive amounts of capacity benefit margin (CBM) to serve their own load, 46 and violated the pro forma tariff by reserving large amounts ( e.g. , 2,000 MW) of transfer capability at multiple interfaces, under the label of “firm import for native load,” without designating resources or loads associated with the reservations as other transmission customers are required to do. 47 Import capability reserved by the transmission provider blocks a competing supplier from securing firm service across the interface, limiting that supplier's ability to compete to serve load on the system, or on neighboring systems. A related issue is whether those who set aside transmission for CBM are reserving it and paying for it under the terms of the pro forma tariff. When transfer capability for CBM is set aside for the use of one market participant, its cost is not necessarily allocated to that market participant alone. Because transmission facility embedded costs are allocated to transmission customers on the basis of use—capacity reservation for Point-to-Point Transmission Service customers and load ratio share (which does not include the transmission capability set-aside of CBM) for Network Integration Transmission Service customers—all customers may unfairly subsidize the cost of the CBM capability. 46 See Delegated Letter in Docket No. ER98-4410-000 (Feb. 8, 1999); Entergy Services, Inc., 87 FERC ¶ 61,156 (1999) (directing Entergy, which had reserved 2900 MW, to recompute ATC). 47 See Aquila Power Corporation v. Entergy Services, Inc., 90 FERC ¶ 61,260, reh'g denied, 92 FERC ¶ 61,064 (2000), appeal docketed, No. 00-1417 (D.C. Cir. Sept. 22, 2000). The Commission did not order a remedy in the complaint docket since the compliance filing in Docket No. ER98-4410 to remedy the excessive native load reservations would also provide a remedy for the improper native load reservations at the interfaces. See id. at 61,860. 56. Under Standard Market Design, entities that want to reserve transfer capability must pay for that capability to reach generation reserves across an interface. Thus, the preferential treatment would be eliminated. h. Discretionary Use of Transmission Loading Relief 57. The opportunity for anticompetitive behavior arises when transmission providers have discretion to dispatch their own generation to serve their own load in a way that requires transmission service curtailments through the use of transmission loading relief (TLR) procedures. 58. There has been a sharp increase in the number of TLRs used in some regions, suggesting that transmission operators rely upon them to do more than simply relieve emergency transmission overloads. 48 There are unmistakable financial incentives to rely on TLRs in forward transmission planning: 48 In the Southeast, the incidence of TLRs increased 354 percent from the summer of 1999 to the summer of 2000. See Staff Report to the Federal Energy Regulatory Commission on the Bulk Power Markets in the United States (Nov. 1, 2000), available in , at 3-38. In the Midwest, the incidence increased 472 percent over the same time period. See Staff Report to the Federal Energy Regulatory Commission on the Bulk Power Markets in the United States (Nov. 1, 2000), available in , at 2-32. The lack of a centralized market, particularly in the Southeast, has limited market liquidity and, thus, increased the likelihood of TLRs. The increased incidence of TLRs may suggest that some transmission capacity is being oversold. Market participants have attributed a tendency to implement a greater number of TLRs to the commercial reality that transmission providers do not have to refund transmission reservation fees for service curtailed because a TLR is called. 49 49 Staff Report to the Federal Energy Regulatory Commission on the Bulk Power Markets in the United States (Nov. 1, 2000), available in at 3-39. 59. When a vertically integrated transmission provider injects power from its own generation onto its own power lines to meet the constantly shifting demands of the load on its system, it has both the opportunity and the incentive to manipulate the transmission system for its own benefit. It can either dispatch generators to create a transmission constraint that prevents a competitor from making a sale that the transmission provider would also like to make, or it can capitalize on legitimate constraints into a load pocket to curtail a competitor's transmission transaction and serve the customer with its own generation instead. The key here is that none of the transmission provider's actions require direct communication with its merchant function or marketing affiliate. A simplified hypothetical example of such anti-competitive behavior is set forth in Appendix C. 60. Several aspects of our proposed remedy address this concern, including the use of LMP to manage congestion and the requirement that transmission facilities be operated by an Independent Transmission Provider. 2. Lack of Common Rules Governing Transmission 61. Some of the difficulties that come from having different rules as power moves across the grid are discussed later in the Seams Problems Section III.B.4), where a “seam” is a dividing line between different sets of grid rules. 62. Having two or more different sets of rules governing the operation of a transmission system makes it difficult—if not at times impossible—for that system to support an efficient regional electric power market. If the interstate transmission system is to provide fair and efficient movement of power on behalf of all users of the system, the same general rules must govern such matters as who gets service, who has the right to transmission service when not all service requests can be accepted, how the transmission facility costs are allocated among transmission customers, who gets its transmission curtailed and by how much when a transmission outage prevents all the planned services from being accommodated, who plans the additions to the grid and who pays for these additions. 63. Today there are not only different rules in different public utility systems, but there may be more than one set of rules for transmission owned by a single utility. This is because there are different rules for two types of wholesale transmission service, and the rules for bundled retail transmission service may differ from the rules for wholesale and unbundled retail transmission services. 64. The Commission established an open access transmission tariff under Order No. 888 that provides for two distinct types of wholesale transmission services—Network Integration Transmission Service and Point-to-Point Transmission Service. Network Integration Transmission Service was designed primarily to meet the needs of the transmission customer that wants to integrate many generators and many loads at diverse locations on the public utility's grid; it was intended to be comparable to the service that the public utility provided to its own bundled retail customers. Point-to-Point Transmission Service, as the name implies, was designed primarily for the customer that wants to move power from one discrete location to another. 65. At the time Order No. 888 issued, the Commission recognized the potential for problems with having two wholesale services that could not be truly equal, especially the problem of dealing with claims of undue discrimination between the services. Consequently, along with the issuance of Order No. 888 the Commission proposed a rule to create a new tariff, called the Capacity Reservation Tariff. 50 It was intended to remedy the anticipated problems by establishing a new tariff that would replace the two wholesale services with one. The Commission received many comments on the proposed rule and held a technical conference with representatives of diverse stakeholders. 51 50 See Capacity Reservation Open-Access Transmission Tariffs, 61 FR 21,847 (May 10, 1996), FERC Stats. and Regs. ¶ 32,519 (1996) (Notice of Proposed Rulemaking). 51 See Capacity Reservation Open-Access Transmission Tariffs, 76 FERC ¶ 61,065 (1996) (notice extending deadline for filing written comments and convening technical conference). 66. Some parties expressed concern about moving quickly to a single service based on the Capacity Reservation Tariff model, while other parties asserted that, although a single tariff reducing the two services to one was a good policy, there were problems with the particular Capacity Reservation Tariff that was proposed. They recommended that the Commission delay acting on the proposed rule until it learned the best form of single service tariff through industry experience with open access. This is the approach that the Commission in effect followed. Since the two Order No. 888 services were adopted, however, there have been allegations of undue discrimination between customers of the two services as discussed later in this section. 67. There are also different rules for bundled retail transmission service and for wholesale and unbundled retail transmission services. States have historically established the rules for the transmission component of bundled retail transactions, while the Commission has established the rules for wholesale and unbundled retail transmission services. 68. Despite the requirement in Order No. 888 that no transmission customer may have any undue advantage over another, there remain real or perceived advantages for the customers of vertically integrated transmission owners. In many cases, the perceived advantage is one of Network Integration Transmission Service over Point-to-Point Transmission Service, where Network Integration Transmission Service is available to both bundled retail transmission customers and wholesale Network Integration Transmission Service customers, while Point-to-Point Transmission Service is taken primarily for wholesale transmission by independent power producers and marketers. 69. Four prominent examples highlight the alleged advantages that a public utility's bundled retail customers have over wholesale and unbundled retail customers. First, certain reliability practices related to keeping the transmission system balanced may allow a public utility that is responsible for keeping generation and load in balance to obtain lower costs for its own power customers. Second, a transmission-owning public utility may have more de facto flexibility to designate transmission receipt and delivery points than other transmission customers, if that public utility also provides power to customers on its transmission system. Third, the bundled retail customers of a transmission owner may have certain transmission reservation and pricing advantages regarding transmission transfer capability set aside for reliability. Fourth, state transmission curtailment rules that favor a public utility's bundled retail customers may conflict with the Commission's transmission curtailment rules, resulting in a transmission preference to customers in one state over customers served in other states. 52 The first three of these were summarized above, and a detailed discussion with examples is set forth in Appendix C. 52 We emphasize that transmission curtailment does not necessarily mean a power outage. 70. The requirement for all services on the transmission grid to be taken under a common set of rates, terms and conditions will resolve these concerns. 3. Congestion Management 71. Due to new transmission usage patterns and the lack of transmission infrastructure improvements, congestion has increased. However, economically sound congestion management plans do not exist in most parts of the country, and transmission customers have been exposed to transmission service interruptions and increasing generation costs due to the risk of interruption. The operating rules that do exist were not designed as a congestion management tool for allocating scarce transmission capacity, but were designed to keep facilities from overloading in an emergency, such as when a transmission facility unexpectedly goes out of service. 72. Currently, under the existing pro forma tariff, congestion is managed primarily through a system of physical reservation of capacity, based on each individual transmission provider's calculation of the Available Transfer Capability of its grid, a calculation often made without knowledge of the power flows on its grid that result from transactions scheduled over other grids in its region. Under the current pro forma tariff, customers reserve capacity on either a firm or non-firm basis, based on the assumed contract path that the transaction will use. Once the customer has reserved capacity on a firm basis, it is supposed to receive certainty both that power will be delivered and the price that the customer will be charged for transmission. If the customer has non-firm capacity, it has no certainty that capacity will be available to deliver power, but does know that there will be no congestion charge if the delivery does occur. 73. The existing pro forma tariff also provides that the redispatch of a transmission provider's generating units to relieve congestion is required only if it can be achieved while maintaining reliable operation of the transmission system in accordance with prudent utility practice. The recovery of the higher generation costs resulting from such generator redispatch, which are a subset of opportunity costs, requires that (1) a formal generator redispatch protocol be developed and made available to all transmission customers and (2) all information to calculate redispatch costs be made available to the customer for audit. If a transmission provider collects revenues to cover the redispatch costs from a specific transmission customer, it must credit these revenues to the cost of fuel and purchased power expense included in its wholesale fuel adjustment clause. Various tariff provisions specify how redispatch is to be implemented. For instance, Sections 33.2 and 33.3 of the existing pro forma tariff provide that the redispatch of all network resources and the transmission provider's own resources, on a least-cost basis without regard to ownership, is to be performed only to maintain system reliability, not for economic reasons. Under those circumstances, the redispatch costs would be shared among the network customers and the transmission provider on a load ratio basis. Sections 13.5 and 27 of the existing pro forma tariff permit the transmission provider to provide the requested transmission service and relieve a system constraint by redispatching the transmission provider's resources: (1) If this costs less than constructing network upgrades; and (2) if, under Section 13.5, the transmission customer agrees to compensate the transmission provider for any such redispatch costs on an incremental basis as specified in the customer's service agreement prior to the commencement of service. 74. Although the existing pro forma tariff allows the recovery of generating unit redispatch costs, the Commission generally has not accepted proposals submitted by single-utility transmission providers to recover such costs. For instance, the Commission rejected Bangor Hydro-Electric Company's (Bangor Hydro) proposed formula to recover opportunity costs for lack of supporting data showing that its opportunity cost pricing would be consistent with the principle of comparability and because the formula lacked sufficient detail to operate as a rate formula itself. 53 The Commission directed Bangor Hydro to submit a separate section 205 filing with revised opportunity cost pricing before implementing such pricing. The Commission also rejected a proposal by the operating companies of Central and South West Corporation (CSW) regarding redispatch costs because they did not provide sufficient specificity to enable a customer to calculate or verify redispatch costs and because the formula lacked sufficient detail to operate as a formula rate. 54 The Commission also directed CSW to submit a separate filing under section 205 before implementing such pricing. 53 See Allegheny Power System, Inc., et al. , 80 FERC ¶ 61,143 (1997). 54 Central Power and Light Company, 81 FERC ¶ 61,311 (1997). 75. Because it is difficult for a single-utility transmission provider to develop a formula that specifies the costs of redispatch and protects transmission customers' interests, generation redispatch has not been used as extensively as it could be used to relieve congestion. A transmission provider will not redispatch generating units if it cannot collect its higher generation costs, and less transmission transfer capability will be available to the energy market. 76. In 1998, the Commission called on public utilities to work with the North American Electric Reliability Council (NERC) to develop a congestion management system based on redispatch. 55 NERC responded with its pilot Market Redispatch program that relied on counterflow transactions, i.e. , power transfers against the prevailing flows on the constraint, to relieve the congestion. 56 Although the program has been in place for several years, it has been implemented only infrequently because of the difficulty in establishing counterflow transactions and the limited availability of data to the transmitting customer. 57 55 The NERC rules for protecting the system were designed to adapt the Commission's Order No. 888 individual utility transmission curtailment requirements to multi-system transactions and parallel flows. See North American Electric Reliability Council, 85 FERC ¶ 61,353, 62,363-64 (1998). 56 See North American Electric Reliability Council, et al. , 87 FERC ¶ 61,160 (1999). 57 NERC identified several problems with the program in a January 31, 2002 submittal to the Commission: (1) The Market Redispatch customer cannot easily anticipate and specify in advance which facilities will overload and require transmission curtailment; (2) the Market Redispatch transaction must provide a counterflow for the entire protected transaction even though the required transmisssion curtailment may be only a portion of the original protected transaction; and (3) the Market Redispatch customer cannot easily discover the availability of generator pairs for counterflow transactions. See Report on Market Redispatch Pilot Program by NERC Market Interface Committee and Motion to Continue Market Redispatch Program, Docket No. ER02-933-000, at 3 (Jan. 31, 2002). 77. In 1998, Commonwealth Edison Company (ComEd) proposed a similar voluntary redispatch program, which predated NERC's Market Redispatch Program. 58 In November 1998, ComEd submitted the first of two interim reports to the Commission summarizing its experience with the program. 59 It determined that a single utility cannot effectively offer redispatch over other systems, especially where other generation owners do not participate. 58 See Commonwealth Edison Company, et al. , 83 FERC ¶ 61,145 (1998). 59 Interim Report on Non-Firm Redispatch , Docket No. ER98-2279-000 (Dec. 17, 1998). 78. The overall result of the Order No. 888 congestion management system is that the transmission system is not utilized in the most efficient manner. Customers can be denied access to lower-cost supplies that could be made available if the congestion management and pricing system had an efficient and fair method of recovering the cost of generator redispatch. 79. Managing congestion using an LMP system, coupled with a single transmission service that relies on price (rather than first-come, first-served) to allocate limited transmission capacity, will resolve these problems. 4. Seams Problems 80. A lack of common transmission rules inhibits competition in power markets not only when there are different rules for different customers under one public utility's tariff or one RTO's tariff, but also when there are different rules from one public utility to the next, or from one RTO to the next. The term “seam” has come into common use in the electric power industry over the last several years to refer to a boundary between areas with different transmission or other market rules. Market participants assert that it can be difficult to move power “across a seam” from one area to another. 81. Seams issues include differences in transmission rules as well as differences in power market rules. They include such diverse matters as different operating rules ( e.g. , rules for recalling firm transmission capacity; coordination of generation and transmission maintenance schedules; how parallel path flows are determined to affect other regions); different market rules ( e.g. , bidding rules; market product definitions); different market designs ( e.g. , congestion management procedures; demand response rules; market price intervention practices); different business practices ( e.g. , scheduling practices; reservation practices; OASIS designs; processes to verify transactions between ISOs and market participants; transmission and generation outage information dissemination, compensation, and coordination rules; generation interconnection practices; liability provisions); and different electronic and telephonic communications protocols. 82. Market participants have called for a “seamless market,” by which they mean a market whose operation is not encumbered by differences in rules at public utility or RTO boundaries. To achieve a seamless market, some assert that rules may differ but only in ways that the differences are invisible to power sellers and buyers. Others assert that such management of differences rarely works in practice and that the rules must be the same everywhere to achieve a seamless market. 83. The Commission has long recognized the need for more coordination and uniformity throughout a region in transmission matters. Our Regional Transmission Group Policy Statement of 1993 60 encouraged public utilities to develop a common set of rules for regional expansion planning, and our Transmission Pricing Policy Statement of 1994 61 encouraged the development of a common pricing policy for a region that would internalize and rationalize the pricing of parallel path flows. As explained above, Order Nos. 888 and 2000 recognized the need to bring the various public utility transmission systems in a region under a common set of transmission rules. Order No. 888 not only applied a common set of open access transmission rules to public utility transmission systems, but included a reciprocity provision that conditioned a non-public utility's use of a public utility's open access transmission tariff on the non-public utility's agreement to provide comparable transmission service to the public utility. Indeed, Order No. 888 also encouraged the formation of ISOs not only to bring all the transmission systems in a region under common rules, but also under unified operation. Many parties in Canada have stressed the necessity of having a common set of rules for reliability and trading protocols for cross-border transmission facilities. 62 Order No. 2000 built on this theme by strongly encouraging the formation of RTOs to bring all facilities in a region under a common set of transmission rules. However, RTOs have not developed at the pace anticipated when Order No. 2000 was issued and seams problems continue to exist. In June 2001, the Commission held a technical conference on seams issues. 63 Participants to the seams conference explained that resolution of seams issues is critical for making the inter-RTO transmission systems and power markets work. 60 Policy Statement Regarding Regional Transmission Groups: Policy Statement, 58 FR 41,626 (August 5, 1993), FERC Stats. & Regs. ¶ 30,976 (Jul. 30, 1993). 61 Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities Under the Federal Power Act, 59 FR 55,031 (November 3, 1994), FERC Stats. & Regs. ¶ 31,005 (Oct. 26, 1994), order on reconsideration and clarifying policy statement , 71 FERC ¶ 61,195 (1995). 62 See, e.g. , Ambassador Michael Kergin (Canada) letter to Honorable Thomas A. Daschle, Senate Majority Leader, dated November 2, 2001: Canadian electricity companies are linked to their counterparts in the U.S. through a number of major connections crossing our common border. We share a truly international electricity grid. This interconnectedness itself enhances our respective energy security, but it also places an onus on our countries to act together to manage the grid. Nowhere is that more important than in the area of electricity reliability. * * * Because uniformity in reliability standards is required to enable effective electricity trade, variations in standards would impede electricity trade and balkanize markets. 63 Conference on RTO Interregional Coordination , Docket No. PL01-5-000, June 19, 2001. Called by many the “FERC Seams Conference,” this technical conference on the RTO interregional coordination requirements of Order No. 2000 helped the Commission learn about seams issues and about how uniform standards for some rules could benefit power markets. 84. We set forth in Appendix C a number of examples of differences in rules that can create seams problems, and a discussion of efforts at the Commission or within the industry to address seams problems. 85. The requirement under Standard Market Design for a single tariff and a single market design operating with the same set of rules throughout the entire interconnection resolves the seams problems discussed above. 5. Market Design Flaws 86. Poorly designed market rules, or market rules with unforeseen or unintended consequences, can have a debilitating effect on markets, market pricing and overall confidence in the markets of the market participants. Moreover, differences in market designs in neighboring regions can also lead to problems such as the exercise of market power through the exploitation of the differences. 87. Wholesale electricity markets are complex, with multiple products traded at multiple locations on different time-frames, while subject to the unique physical characteristics of electricity ( e.g. , non-storable, need for system stability and balancing, physics of power flows). Market rules have been affected by the variation in generation mix, the transmission network layout and the local and regional regulatory history in different regions of the country. For example, the initial California markets had a design quite different from the designs of the markets in the Northeast region (PJM, New York and New England). 88. In the regions where voluntary, organized ISO markets for energy, transmission and ancillary services have been established under the existing tariff, problems due to the design choices have been characterized as “market design flaws.” A market design flaw is a market rule—including product specification, bid format, auction rules and pricing rules—that allows distortions in the market prices or availability of a product or service, whether energy, ancillary services, transmission service or installed capacity. In the years since the ISO markets have been operating, dozens of market design flaws have been identified, ranging from minor problems that cause temporary inconveniences to major problems that require markets to be re-designed. No region has been exempt from market design flaws of one type or another. We set forth in Appendix C examples of specific design flaws. 89. These problems have resulted in markets that are inefficient and do not produce the lowest reasonable prices for electric power. These problems cannot be resolved on a case-by-case basis because that will maintain and exacerbate the problems due to local differences in rules. Only standardization of electricity market design will solve these problems. In the parts of the country in which markets are most mature, including the Northeast, Midwest and California, there is broad consensus on the principal elements of market design and business practices. A standard market design rule will help advance this process and extend it to other regions. Our goal is to use the Standard Market Design rulemaking to address and remedy many of the market design flaws identified to date and to raise the quality of all electric markets simultaneously. 90. Market rules will need to be flexible and have the ability to evolve over time. However, consistent rules across the entire interconnection based on best practices, coupled with sound market monitoring to promptly identify and correct any design flaws will provide the necessary foundation for future market innovation and improvement. C. Reform Essential Given the Changed Nature of the Electric Industry 91. The need to address the instances of discrimination described above is all the more critical given the changing nature of the electric industry. The United States electric power industry is in the middle of a transition from a predominantly monopoly industry to a predominantly competitive industry. The fundamental economic driver of change has been, and continues to be, the reduction of economies of scale in new generation construction, combined with environmental restrictions that encourage gas-fired units. This is due in large part to the introduction during the 1980s of highly efficient gas turbines and combined cycle generators that produce much more electricity from a given amount of gas. A relatively small gas-fired generator can compete effectively with power from a large central generating station. Additionally, small distributed generation is becoming economic, and some renewable energy resources, especially wind power generation, are also on the verge of becoming competitive. 64 In the right locations, wind generating units can compete with the much larger coal, nuclear and hydroelectric units. 65 64 See, e.g. , International Energy Agency, Distributed Generation in Liberalized Electricity Markets, International Energy Agency (June 2002); and Ann Chambers, et al. , Distributed Generation: A Nontechnical Guide (PennWell Corp. 2001). 65 See Christine Real de Azua, Wind Power: Poised for Take Off? A Survey of Projects and Economics, Pub. Util. Fort., Aug. 2001 at 38. 92. Because of these fundamental changes in industry technology, small producers of electricity can compete with large producers, and both the smaller utilities and the retail customers of a number of utilities have demanded access to competing power suppliers in hopes of lowering their electric bills, improving service and harnessing new technologies. The pressures for retail access have been greater in regions with higher rates, which are typically regions with few low-cost natural resources for generating electric power, such as nearby coal mines, gas fields, and hydroelectric areas. 66 Many of these regions have taken the lead in retail restructuring, while regions with historically low electricity production costs have proceeded more cautiously or even affirmatively decided not to change their retail access policies or to support their local utilities' participation in regional programs at this time. 67 66 See Energy Information Administration, The Changing Structure of the Electric Power Industry 2000: An Update, at 81-82 (2000), available in http://www.eia.doe.gov/cneaf/electricity/ chg_stru_update/update2000.pdf > (hereinafter Electric Power Industry 2000 Update). 67 See id. 93. One hallmark of electric industry restructuring has been the growth of wholesale trade. In the past, wholesale power purchases made up a small fraction of a large vertically integrated utility's power supply, with most of its power needs met by its own generation. Today, however, even large vertically integrated utilities rely increasingly on wholesale purchases for their energy supplies. For example, as shown in Table 1, between 1989 and 2000, generation by investor-owned utilities grew from 2,132 thousand GWh to 2,230 thousand GWh, an increase of less than 5 percent. During this time, wholesale power purchases by these utilities almost tripled. Table 1 also shows that in 1989 wholesale power purchases provided 18 percent of the total electric energy available to investor-owned utilities from both wholesale purchases and their own generation. By 2000, wholesale purchases provided over 37 percent of investor-owned utility electric energy. This percentage has steadily increased since 1989, and is expected to continue to grow as utility-owned plants are sold or retired and new power supplies are acquired competitively in most parts of the country. Table 1.—Investor-Owned Utilities' Total Purchases, 1989-2000, As a Percentage of Energy Purchased and Self-Generated Year IOUs' purchases (GWh) IOUs' generation (GWh) Purchases (purchases + generation) (%) 1989 460,627 2,132,065 17.8 1990 530,325 2,134,429 19.9 1991 635,015 2,145,435 22.8 1992 671,758 2,143,847 23.9 1993 718,876 2,216,724 24.5 1994 732,710 2,237,652 24.7 1995 786,676 2,269,958 25.7 1996 916,087 2,308,156 28.4 1997 1,080,538 2,321,225 31.8 1998 1,073,638 2,402,571 30.9 1999 1,083,892 2,353,639 31.5 2000 1,324,558 2,229,617 37.3 Source: RDI POWERDAT Database. Note: Data for 2001 is not yet available. Investor-owned utility purchases include purchases from affiliates. 94. Table 1 demonstrates the increasing importance of competitive wholesale energy acquisition in the United States electric power industry, and the need for this Commission to ensure that transmission, market rules and institutions are reformed as necessary to support the new environment. It also makes clear that a retreat from competitive markets to a cost-regulated vertically integrated world would be difficult—the nation now depends increasingly on wholesale interstate electricity markets. 95. Similar data are presented in Tables 2 and 3 for large public power utilities and generation and transmission cooperatives that generate at least some of their own power. 68 These tables show that wholesale purchases, on average, provide about 40 percent of the power needs of these large utilities. Data are not presented for the smaller public power and cooperative utilities because they typically do not self-generate but buy all of their power at wholesale. 68 Note that the data available for large public power and cooperative utilities is not complete but represents a sampling of these utilities. The sample size typically grew each year so that an apparent growth in the wholesale purchase percentages could reflect the addition of smaller utilities that purchase more power at wholesale. Table 2.—Large Public Power Utilities' Total Purchases, 1992—2000, As a Percentage of Energy Purchased and Self-Generated Year Utilities' purchases (GWh) Utilities' generation (GWh) Purchases (Purchases + generation) (%) 1992 297,076 520,348 36.3 1993 314,472 549,810 36.4 1994 331,643 555,198 37.4 1995 332,962 586,737 36.2 1996 350,880 645,740 35.2 1997 349,641 674,725 34.1 1998 364,434 676,698 35.0 1999 394,617 634,548 38.3 2000 429,369 631,143 40.5 Source: RDI POWERDAT Database. “Large Public Power Utilities” includes municipals, federal power authorities. Data for 2001 is not yet available. Table 3.—Generation & Transmission Cooperatives' Total Purchases, 1992—2000 As a Percentage of Energy Purchased and Self-Generated Year Cooperatives' purchases (GWh) Cooperatives' generation (GWh) Purchases (Purchases + generation) (%) 1992 85,226 136,417 38.5 1993 93,756 149,783 38.5 1994 96,148 156,589 38.0 1995 99,909 166,099 37.6 1996 117,455 172,161 40.6 1997 112,822 176,689 39.0 1998 115,003 177,534 39.3 1999 122,151 172,323 41.5 2000 127,785 171,198 42.7 Source: RDI POWERDAT Database. Note: “Generation & Transmission Cooperatives” includes cooperatives with generation and transmission facilities, but excludes distribution cooperatives. Data for 2001 is not available yet. 96. The transition to competitive electricity markets is characterized by opportunity and uncertainty. The promise of competition is the opportunity to develop more innovative technologies, improve services, lower average electric rates and provide more customer choice than is likely under a strictly regulated monopoly environment. During the transition to competition, these promises are only partly fulfilled, and results vary regionally as a result of different choices about retail restructuring. Additionally, the California electricity crisis of 2000-2001, allegations of improper trading practices, the collapse of Enron Corporation in December 2001 and the deteriorating financial health of many electric suppliers and marketers at this time have added unprecedented uncertainty about, and lack of confidence in, today's electric markets. 97. In addition to general concerns about adequate constraints on the exercise of market power by power sellers, there is uncertainty in the industry about impediments to new generators entering the market, adequacy of incentives to build much needed generation and transmission infrastructure, availability of non-discriminatory transmission service for all sellers and buyers in a regional market and the risk of making long-term commitments when market rules are subject to frequent experiment and change. Differences in market rules between regions make it difficult to transact business across regions and thus also lead to increased uncertainty in the industry and the risk of market manipulation. 98. Investors, generators and transmission providers are reluctant to invest in new generation and transmission infrastructure if the rules for setting energy or transmission prices are not yet known or are subject to frequent revision. 69 Thus, uncertainty about the direction of competition policies inhibits the development of the very infrastructure needed both to allow competition to work and to assure reliability in a competitive environment. Customers are reluctant to sign contracts for power or to change suppliers if long-term power markets are unnecessarily volatile and they cannot obtain price certainty. 69 See generally U.S. Department of Energy, National Transmission Grid Study (May 2002), available in (hereinafter DOE National Transmission Grid Study). 99. The promise of wholesale competition may go unfulfilled—or at best continue to be delayed at great cost—unless many of these uncertainties are resolved. This proposed rule is intended to help resolve generically many of the uncertainties facing the electric power industry and to restore confidence in future power markets. D. Legal Authority and Findings 100. The primary purposes of the Federal Power Act are to curb abusive practices by public utilities and to protect customers from excessive rates and charges. To achieve these ends, section 205 of the Federal Power Act requires that no public utility shall “make or grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage,” with respect to the transmission of electric energy in interstate commerce or wholesale sales. 70 Section 206 of the Federal Power Act authorizes the Commission to investigate and remedy unduly discriminatory or preferential rules, regulations, practices or contracts affecting public utility rates for transmission in interstate commerce and for sales for resale of electric energy in interstate commerce. 71 It also authorizes the Commission to investigate and remedy unjust and unreasonable rates, charges or classifications, and any rules, regulations, practices or contracts affecting such rates, charges or classifications. 70 16 U.S.C. 824d. 71 16 U.S.C. 824e. 101. Moreover, the Commission's regulatory authority “clearly carries with it the responsibility to consider, in appropriate circumstances, the anticompetitive effects of regulated aspects of interstate utility operations pursuant to [Federal Power Act sections] 202 and 203, and under like directives contained in [Federal Power Act sections] 205, 206, and 207.” 72 The Commission's authority to remedy undue discrimination and anticompetitive effects is broad. 73 72 See Order No. 888 at 31,669 (quoting Gulf States Utilities Co. v. FPC, 411 U.S. 747, 758-59, reh'g denied, 412 U.S. 944 (1973)). See also City of Huntingburg v. FPC , 498 F.2d 778, 783-84 (D.C. Cir. 1974) (finding that the Commission has a duty to consider the potential anticompetitive effects of a proposed interconnection agreement). 73 See Order No. 888 at 31,669 (the Federal Power Act fairly bristles with concern for undue discrimination (citing Associated Gas Distributors v. FERC, 824 F.2d 981, 998 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988))). 102. The Court of Appeals for the District of Columbia Circuit reviewed challenges to Order No. 888 and found that the “open access requirement is authorized by and consistent with the [Federal Power Act],” and upheld the order. 74 On appeal, the Supreme Court affirmed the Commission in applying its open access requirements to transmission used for wholesale and unbundled retail sales of electric energy in interstate commerce, but also concluded that the Commission had jurisdiction over transmission used for bundled retail sales of electric energy in interstate commerce. The Supreme Court further stated that the Commission may regulate bundled retail transmission of energy as a means of addressing undue discrimination. While the Court did not adopt the appellants' suggestions that the Commission's finding of discrimination in the wholesale electricity market suggested the presence of discrimination in the retail electricity markets, 75 it stated that “[w]ere FERC to investigate this alleged discrimination and make findings concerning undue discrimination in the retail electricity market, § 206 of the FPA would require FERC to provide a remedy for that discrimination * * * And such a remedy could very well involve FERC's decision to regulate bundled retail transmissions” of energy. 76 74 Transmission Access Policy Study Group v. FERC, 225 F.3d at 685. 75 See id. at 1028. 76 Id. 103. We find that undue discrimination and anticompetitive behavior persist, as detailed in Section III and Appendix C, in both wholesale and retail transmission of energy. Pursuant to our statutory mandate to remedy undue discrimination and anticompetitive effects in these markets, as interpreted by the Supreme Court, we will apply the requirements of this rule to the transmission component of bundled retail transactions. At a minimum, all transmission service in interstate commerce must be subject to the same non-discriminatory non-rate terms and conditions in order to eliminate undue discrimination in wholesale markets and in retail choice markets. With respect to rates for bundled retail transmission service, however, we will work with states to address difficult transition rate issues. 104. In light of these statutory responsibilities and authorities under the Federal Power Act, we have assessed the state of the electric utility industry and determined that it is necessary to act promptly to provide stability to the industry and to assure that customers receive adequate supplies of electric energy at the lowest reasonable price. During the past six years, the implementation of open access transmission under Order No. 888 has fundamentally altered the landscape of the electric utility industry by removing major discriminatory barriers to the use of the interstate transmission grid and thereby opening the door to competition in wholesale electric power markets. However, even with the Order No. 888 open access pro forma transmission tariff and Order No. 889 transmission standards of conduct in place, there continues to be undue discrimination in the provision of interstate services. Experience under the pro forma tariff has demonstrated that unduly discriminatory transmission practices continue today. Further, existing trading rules and design of wholesale power markets do not consistently prevent market manipulation or send proper price signals to participants or allocate scarce resources to those who value them most and thus could result in unjust and unreasonable rates. Thus, competition either does not exist in many areas of the country or competition is distorted. 105. We find that: (1) the operation of the Commission's pro forma transmission tariff (which is administered by vertically integrated as well as non-vertically integrated public utilities such as ISOs) contains provisions that, in practice, permit undue discrimination in the provision of transmission services; (2) public utilities that own, operate or control transmission facilities and also participate in power markets continue to possess substantial transmission market power and retain the ability to unduly discriminate in the provision of transmission service and spot market energy services; (3) lack of standardized wholesale electric market design allows undue discrimination within and across regions, can result in unjust and unreasonable pricing and allocation of transmission and permits the exercise of market power (and thus unjust and unreasonable rates) in power markets; and (4) proper price signals are not being sent to the marketplace, with the result that market-based rates in many places are distorted, and reasonably accurate price signals necessary for infrastructure additions are not being sent. 106. To remedy remaining undue discrimination in the provision of interstate transmission services and in other industry practices, and to ensure just and reasonable rates for sales of electric energy within and among regional power markets, the Commission proposes to modify the Order No. 888 pro forma tariff to reflect non-discriminatory, standardized transmission service and require standardized wholesale electric market design. The Commission also proposes to expressly exercise jurisdiction over all transmission in interstate commerce by public utilities. IV. The Proposed Remedy 107. The Commission's goal in Order Nos. 888 and 2000 was to harness the benefits of competition for the nation's electricity customers by assuring adequate and reliable supplies of electricity at a just and reasonable price. As discussed above in the Need for Reform section (Section III), the current rules and regulations have prevented the full attainment of that objective. To address these problems in the current system, we are proposing a comprehensive package of reforms that are described more fully in this section. 108. Section III and Appendix C provide numerous examples of ways that an entity that owns both transmission and generation can discriminate in favor of its own customers or generation under the current tariff. The problem stems from the differences in the sets of rules that apply to users of the transmission system. First, the current regulatory system allows vertically integrated utilities to discriminate in favor of their bundled retail load at the expense of wholesale customers. This occurs because transmission service for bundled retail customers is subject to different rules and rates than service for wholesale customers. Second, the current distinction between Point-to-Point Transmission Service and Network Integration Transmission Service also creates opportunities for undue discrimination in favor of generation owned by the transmission owner or an affiliate. 109. To remedy this discrimination we propose to place all transmission customers under the same set of rules. We propose to place transmission service for bundled retail customers under the same terms and conditions of service as wholesale transmission service. To accomplish this we propose to revise the existing pro forma tariff to remove provisions that grant preferential treatment to transmission service for bundled retail customers. We propose that all public utilities that own, control or operate interstate transmission file these interim changes no later than July 31, 2003. We also propose that no later than September 30, 2004, or such date as the Commission may establish, only Independent Transmission Providers would operate Commission-jurisdictional facilities. This requirement will apply whether or not the public utility that owns, controls or operates interstate transmission facilities has joined an RTO. 77 We are proposing specific governance requirements that must be met by the Independent Transmission Provider. 77 A Commission-approved RTO would meet the requirements of an Independent Transmission Provider. 110. Also, no later than September 30, 2004, or such date as the Commission may establish, we propose to eliminate the distinction between Point-to-Point and Network Integration Transmission Services by having one service, Network Access Service, that contains elements of both types of service—the flexibility of Network Integration Transmission Service and the tradability of Point-to-Point Transmission Service. We propose these time periods to provide sufficient time for the development of the necessary new software systems. Network Access Service is based on an open spot market for imbalance energy and a uniform congestion management methodology, i.e. , LMP, to more efficiently manage the transmission grid. The spot energy market and LMP rely on management of the transmission system and bidding by supply and demand resources attached to the transmission grid under market rules and protocols. 111. To provide the price signals needed to manage congestion, the Independent Transmission Provider will be required to operate a day-ahead and real-time market for energy. To provide customers with a mechanism for achieving price certainty under the new congestion management system, we also propose to require that customers be given Congestion Revenue Rights for their historical uses that protect against congestion costs when specific receipt and delivery points are used. 112. LMP and Congestion Revenue Rights will provide price signals to indicate where new investment is needed; however, the price signals alone may not guarantee sufficient investment. We also propose to require a regional transmission planning and expansion process to provide a backstop process for ensuring that needed transmission construction is undertaken. We propose that this process begin six months from the effective date of the Final Rule, even though much of the country will not have had the opportunity to respond to LMP and Congestion Revenue Rights for another few years. 113. At this stage of the industry's evolution, structural barriers to competitive markets remain, so to address this we are proposing market power mitigation measures for the spot markets that will be operated by the Independent Transmission Provider. These measures are designed to address the two significant structural problems in wholesale energy markets—the existence of localized market power that arises from transmission constraints, and the lack of price-responsive demand. The market power mitigation proposal is a framework that can be tailored to reflect the competitive conditions of the particular region. It is designed to be reexamined annually and adjusted as needed to reflect changes in the competitive structure of the region, including a phasing out of mitigation measures as resource adequacy and demand response develops. Because market power mitigation of spot market prices will tend to suppress the price signals for new entry, we are also proposing a non-price mechanism to assure that load meets a long-term resource adequacy requirement. 114. To avoid the market design flaws discussed in the Need for Reform section (Section III) and Appendix C and market manipulation in Appendix E, and to minimize the potential for seams issues, we propose a standardized tariff that incorporates the best practices and builds on the lessons from our experience with organized markets. In Appendix B, the proposed SMD Tariff standardizes many aspects of the basic market design. However, it also allows flexibility in a number of areas to customize the basic market design to meet regional requirements where such customization will not lead to further discrimination or inefficiencies. 115. We propose to permit small entities to seek waiver of the Standard Market Design Final Rule requirements. The regulations we propose include waiver provisions under which public utilities, and non-pu [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%3A02-21479. Public record. Not legal advice.