ÿ 78 FERC  61,220 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION 18 CFR Part 35 [Docket Nos. RM95-8-001 and RM94-7-002; Order No. 888-A] Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities (Issued March 4, 1997) AGENCY: Federal Energy Regulatory Commission. ACTION: Order No. 888-A (Order on Rehearing). SUMMARY: The Federal Energy Regulatory Commission (Commission) reaffirms its basic determinations in Order No. 888 and clarifies certain terms. Order No. 888 requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to have on file open access non- discriminatory transmission tariffs that contain minimum terms and conditions of non-discriminatory service. Order No. 888 also permits public utilities and transmitting utilities to seek recovery of legitimate, prudent and verifiable stranded costs associated with providing open access and Federal Power Act section 211 transmission services. The Commission's goal is to remove impediments to competition in the wholesale bulk power marketplace and to bring more efficient, lower cost power to the Nation's electricity consumers. EFFECTIVE DATE: Changes to Order No. 888 made in this order on rehearing will become effective on [insert date 60 days after date of publication in the Federal Register].ÿ ÿ -2- FOR FURTHER INFORMATION CONTACT: David D. Withnell (Legal Information -- Docket No. RM95-8-001) Office of the General Counsel Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20426 (202) 208-2063 Deborah B. Leahy (Legal Information -- Docket No. RM94-7-002) Office of the General Counsel Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20426 (202) 208-2039 Dan T. Hedberg (Technical Information -- Docket No. RM95-8-001) Office of Electric Power Regulation Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20426 (202) 208-0243 Joseph M. Power (Technical Information -- Docket No. RM94-7-002) Office of Electric Power Regulation Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20426 (202) 208-1242 SUPPLEMENTARY INFORMATION: In addition to publishing the full text of this document in the Federal Register, the Commission also provides all interested persons an opportunity to inspect or copy the contents of this document during normal business hours in the Public Reference Room at 888 First Street, N.E., Washington, D.C. 20426. The Commission Issuance Posting System (CIPS), an electronic bulletin board service, provides access to the texts of formal documents issued by the Commission. CIPS is available at no charge to the user and may be accessed using a personal computer with a modem by dialing 202-208-1397 if dialing locally or 1-800- -3- 856-3920 if dialing long distance. To access CIPS, set your communications software to 19200, 14400, 12000, 9600, 7200, 4800, 2400, or 1200 bps, full duplex, no parity, 8 data bits and 1 stop bit. The full text of this order will be available on CIPS in ASCII and WordPerfect 5.1 format. CIPS user assistance is available at 202-208-2474. CIPS is also available through the Fed World system. Telnet software is required. To access CIPS via the Internet, point your browser to the URL address: http://www.fedworld.gov and select the "Go to the FedWorld Telnet Site" button. when your Telnet software connects you, log onto the FedWorld system, scroll down and select FedWorld by typing: 1 and at the command line then typing: /go FERC. FedWorld may also be accessed by Telnet at the address fedworld.gov. Finally, the complete text on diskette in Wordperfect format may be purchased from the Commission's copy contractor, La Dorn Systems Corporation. La Dorn Systems Corporation is also located in the Public Reference Room at 888 First Street, N.E., Washington, D.C. 20426. TABLE OF CONTENTS I. INTRODUCTION AND SUMMARY .............................. 1 II. PUBLIC REPORTING BURDEN ............................... 22 III. BACKGROUND ............................................ 24 IV. DISCUSSION ............................................ 30 A. Scope of the Rule ................................ 30 1. Introduction ................................ 30 2. Functional Unbundling ....................... 31 3. Market-based Rates .......................... 34 a. Market-based Rates for New Generation .. 34 b. Market-based Rates for Existing Generation ............................. 39 4. Merger Policy ............................... 40 5. Contract Reform ............................. 41 6. Flow-based Contracting and Pricing .......... 70 B. Legal Authority .................................. 72 C. Comparability .................................... 106 1. Eligibility to Receive Non-discriminatory Open Access Transmission .................... 106 a. Unbundled Retail Transmission and "Sham Wholesale Transactions" ................ 107 b. Transmission Providers Taking Service Under Their Tariff ..................... 116 2. Service that Must be Provided by Transmission Provider .................................... 119 3. Who Must Provide Non-discriminatory Open Access Transmission ......................... 121 4. Reservation of Transmission Capacity by Transmission Customers ...................... 125 5. Reservation of Transmission Capacity for Future Use by Utility ....................... 125 - ii - 6. Capacity Reassignment ....................... 129 7. Information Provided to Transmission Customers ................................... 140 8. Consequences of Functional Unbundling ....... 141 a. Distribution Function .................. 141 b. Retail Transmission Service ............ 141 c. Transmission Provider .................. 144 1. Taking Service Under the Tariff ... 144 2. Accounting Treatment .............. 144 D. Ancillary Services ............................... 145 1. Specific Ancillary Services ................. 146 a. Scheduling, System Control and Dispatch Service ................................ 146 b. Reactive Supply and Voltage Control from Generation Sources Service ............. 147 c. Energy Imbalance Service ............... 152 (1) Description of Energy Imbalance ... 153 (2) Energy Imbalance Bandwidth ........ 158 2. Ancillary Services Obligations .............. 166 a. Obligation of a Control Area Utility ... 167 b. Obligation to Provide Dynamic Scheduling ............................. 169 c. Obligation As Agent .................... 172 3. Miscellaneous Ancillary Services Issues ..... 172 a. Transmission Provider as Ancillary Services Merchant ...................... 172 b. QF Receipt of Ancillary Services ....... 173 c. Pricing of Ancillary Services .......... 175 E. Real-Time Information Networks ................... 178 - iii - F. Coordination Arrangements: Power Pools, Public Utility Holding Companies, Bilateral Coordination Arrangements, and Independent System Operators ... 179 1. Tight Power Pools ........................... 180 2. Loose Pools ................................. 184 3. Public Utility Holding Companies ............ 190 4. Bilateral Coordination Arrangements ......... 197 G. Pro Forma Tariff ................................. 215 1. Tariff Provisions That Affect The Pricing Mechanism ................................... 216 a. Non-Price Terms and Conditions ......... 216 b. Network and Point-to-Point Customers' Uses of the System (so called "Headroom") ............................ 217 c. Load Ratio Sharing Allocation Mechanism for Network Service .................... 224 (1) Multiple Control Area Network Customers ......................... 225 (2) Twelve Monthly Coincident Peak v. Annual System Peak ................ 228 (3) Load and Generation "Behind the Meter" ............................ 232 (4) Existing Transmission Arrangements associated with Generating Capacity Entitlements (e.g., "preference power" customers of PMAs) ........ 243 d. Annual System Peak Pricing for Flexible Point-to-Point Service ................. 246 e. Opportunity Cost Pricing ............... 250 (1) Recovery of Opportunity Costs ..... 250 (2) Redispatch Costs .................. 256 f. Expansion Costs ........................ 261 g. Credit for Customers' Transmission - iv - Facilities ............................. 264 h. Ceiling Rate for Non-firm Point-to-Point Service ................................ 274 i. Discounts .............................. 275 j. Other Pricing Related Issues Not Specifically Addressed in the Final Rule ................................... 286 (1) Demand Charge Credits ............. 286 (2) In-Kind Transactions .............. 286 2. Priority For Obtaining Service .............. 288 a. Reservation Priority for Existing Firm Service Customers ...................... 288 b. Reservation Priority for Firm Point-to- Point and Network Service .............. 288 c. Reservation Priorities for Non-firm Service ................................ 290 3. Curtailment and Interruption Provisions ..... 291 a. Pro-rata Curtailment Provisions ........ 292 b. Curtailment and Interruption Provisions for Non-firm Service ................... 296 4. Reciprocity Provision ....................... 302 5. Liability and Indemnification ............... 354 6. Umbrella Service Agreements ................. 361 7. Other Tariff Provisions ..................... 363 a. Minimum and Maximum Service Periods .... 363 b. Amount of Designated Network Resources . 366 c. Eligibility Requirements ............... 369 d. Two-Year Notice of Termination Provision .............................. 370 e. Termination of Service for Failure to Pay Bill ............................... 370 - v - f. Definition of Native Load Customers .... 372 g. Off-System Sales ....................... 375 h. Requirements Agreements ................ 377 i. Use of Distribution Facilities ......... 380 j. Losses ................................. 380 k. Modification of Non-rate Terms and Conditions ............................. 381 l. Miscellaneous Tariff Modifications ..... 382 (1) Ancillary Services ................ 382 (2) Clarification of Accounting Issues. 382 (a) Transmission Provider's Use of Its System (Charging Yourself) .................... 383 (b) Facilities and System Impact Studies ...................... 385 (c) Ancillary Services ........... 385 (3) Miscellaneous Clarifications ...... 385 (a) Electronic Format ............ 385 (b) Administrative Changes ....... 386 8. Specific Tariff Provisions .................. 386 9. Miscellaneous Tariff Administrative Changes . 442 10. Pro Forma Tariff Compliance Filings ......... 443 H. Implementation ................................... 444 1. Group 1 Public Utilities .................... 444 2. Group 2 Public Utilities .................... 446 3. Clarification Regarding Terms and Conditions Reflecting Regional Practices ............... 447 4. Future Filings .............................. 448 - vi - 5. Waiver ...................................... 448 I. Federal and State Jurisdiction: Transmission/Local Distribution ..................................... 455 J. Stranded Costs ................................... 488 1. Justification for Allowing Recovery of Stranded Costs .............................. 501 2. Cajun Electric Power Cooperative, Inc. v. FERC ........................................ 557 3. Responsibility for Wholesale Stranded Costs (Whether to Adopt Direct Assignment to Departing Customers) ........................ 571 4. Recovery of Stranded Costs Associated With New Wholesale Requirements Contracts ........ 612 5. Recovery of Stranded Costs Associated With Existing Wholesale Requirements Contracts ... 622 6. Recovery of Stranded Costs Caused by Retail- Turned-Wholesale Customers .................. 645 7. Recovery of Stranded Costs Caused by Retail Wheeling .................................... 668 8. Evidentiary Demonstration Necessary -- Reasonable Expectation Standard ............. 699 9. Calculation of Recoverable Stranded Costs ... 711 10. Stranded Costs in the Context of Voluntary Restructuring ............................... 762 11. Accounting Treatment for Stranded Costs ..... 762 12. Definitions, Application, and Summary ....... 762 K. Other ............................................ 774 1. Information Reporting Requirements for Public Utilities ................................... 774 2. Small Utilities ............................. 777 3. Regional Transmission Groups ................ 780 4. Pacific Northwest ........................... 781 - vii - 5. Power Marketing Agencies .................... 781 a. Bonneville Power Administration (BPA) .. 781 b. Other Power Marketing Agencies ......... 782 6. Tennessee Valley Authority .................. 784 7. Hydroelectric Power ......................... 784 8. Residential Customers ....................... 785 9. Miscellaneous Issues ........................ 786 V. ENVIRONMENTAL STATEMENT ............................... 799 A. The Appropriate No-Action Alternative ............ 804 B. Challenges to Modeling Assumptions ............... 809 1. Appropriate Base Case ....................... 810 2. Challenge to the Use of Computer Modeling ... 816 3. Transmission Assumptions .................... 821 4. Plant Availabilities and Heat Rates ......... 826 5. Reserve Margins ............................. 830 6. Northeast MOU ............................... 833 7. Natural Gas Prices .......................... 834 8. Expanded Transmission Analysis .............. 838 C. Mitigation ....................................... 841 D. Emissions Standards Disparity .................... 874 E. Short-Term Consequences of the Rule .............. 888 G. Cost Benefit Analysis ............................ 893 H. Socioeconomic Impacts ............................ 900 I. Coastal Zone Management Act ...................... 907 VI. REGULATORY FLEXIBILITY ACT CERTIFICATION .............. 911 A. Docket No. RM95-8-000 (Open Access Final Rule) .... 914 - viii - 1. Public Utilities ............................. 914 2. Non-Public Utilities ......................... 917 B. Docket No. RM94-7-000 (Stranded Cost Final Rule) .. 918 1. Public Utilities ............................. 918 2. Non-Public Utilities ......................... 918 VII. INFORMATION COLLECTION STATEMENT ...................... 921 VIII.EFFECTIVE DATE ........................................ 922 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Before Commissioners: Elizabeth Anne Moler, Chair; Vicky A. Bailey, James J. Hoecker, William L. Massey, and Donald F. Santa, Jr. Promoting Wholesale Competition ) Docket No. RM95-8-001 Through Open Access ) Non-discriminatory Transmission ) Services by Public Utilities ) ) Recovery of Stranded Costs by ) Docket No. RM94-7-002 Public Utilities and Transmitting ) Utilities ) ORDER NO. 888-A (Issued March 4, 1997) I. INTRODUCTION AND SUMMARY On April 24, 1996, the Commission issued Final Rules (Order Nos. 888 and 889) intended to remedy undue discrimination in the provision of interstate transmission services by public utilities and to address the stranded costs that may result from the transition to more competitive electricity markets. 1/ At the heart of these rules is a requirement that prohibits owners and operators of monopoly transmission facilities from denying transmission access, or offering only inferior access, to other power suppliers in order to favor the monopolists' own generation and increase monopoly profits -- at the expense of the nation's electricity consumers and the economy as a whole. 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, clarified, 76 FERC  61,009 and 76 FERC  61,347 (1996). Order No. 889 is an accompanying rule and specific rehearing arguments on that rule will be addressed separately. Docket Nos. RM95-8-001 -10- and RM94-7-002 The electric utility industry today is not the industry of ten years ago, or even five years ago. While historically it was assumed that local utilities would be the only ones to generate and transmit power for their customers, today there is a broad array of potential competitors to supply power and widespread transmission facilities that can carry power vast distances. But competitors cannot reach customers if they cannot have fair access to the transmission wires necessary to reach those customers. It is against this industry backdrop that the Commission in Order No. 888 exercised its public interest responsibilities pursuant to sections 205 and 206 of the Federal Power Act (FPA), to reexamine undue discrimination in interstate transmission services and the effect of that discrimination on the electricity customers whom we are bound to protect under the FPA. We here reaffirm the legal and policy bases on which Order No. 888 is grounded. Utility practices that were acceptable in past years, if permitted to continue, will smother the fledgling competition in electricity markets and undermine the national policies reflected in the Energy Policy Act of 1992 to encourage the development of competitive markets. We firmly believe that our authorities under the FPA not only permit us to adapt to changing economic realities in the electric industry, but also require us to do so, as necessary to eliminate undue discrimination and protect electricity customers. The record supports our conclusion that, absent open access, undue Docket Nos. RM95-8-001 -11- and RM94-7-002 discrimination will continue to be a fact of life in today's and tomorrow's electric power markets. As recent events clearly demonstrate, unbundled electric transmission service will be the centerpiece of a freely traded commodity market in electricity in which wholesale customers can shop for competitively-priced power. The only way to effectuate competitive markets and remedy discrimination is through readily available, non-discriminatory transmission access. The Commission estimates the potential quantitative benefits from such access will be approximately $3.8 to $5.4 billion per year in cost savings, in addition to the non- quantifiable benefits that include better use of existing assets and institutions, new market mechanisms, technical innovation, and less rate distortion. Order No. 888 has two central components. The first requires all public utilities that own, operate or control interstate transmission facilities to offer network and point-to- point transmission services (and ancillary services) to all eligible buyers and sellers in wholesale bulk power markets, and to take transmission service for their own uses under the same rates, terms and conditions offered to others. In other words, it requires non-discriminatory (comparable) treatment for all eligible users of the monopolists' transmission facilities. The non-discriminatory services required by Order No. 888, known as open access services, are reflected in a pro forma open access tariff contained in the Rule. The Rule also requires functional Docket Nos. RM95-8-001 -12- and RM94-7-002 separation of the utilities' transmission and power marketing functions (also referred to as functional unbundling) and the adoption of an electric transmission system information network. The second central component of Order No. 888 was to address whether and how utilities will be able to recover costs that could become stranded when wholesale customers use the open access tariffs, or FPA section 211 tariffs, 2/ to leave their utilities' power supply systems and shop for power elsewhere. Because of competitive changes occurring at the retail level, as numerous states have begun retail transmission access programs, Order No. 888 also clarifies whether and when the Commission may address stranded costs caused by retail wheeling and the extent of the Commission's jurisdiction over unbundled retail transmission. The Commission further addresses the circumstances under which utilities and their wholesale customers may seek to modify contracts made under the old regulatory regime, taking into account the goals of reasonably accelerating customers' ability to benefit from competitively priced power and at the same time ensuring the financial stability of electric utilities during the transition to competition. Under section 211 of the FPA, the Commission, on a case-by- case basis upon application by an eligible customer, may order both public utilities and non-public utilities that own or operate transmission facilities used for the sale of electric energy at wholesale to provide transmission services to the applicant if it finds it is in the public interest to issue such order. Docket Nos. RM95-8-001 -13- and RM94-7-002 137 entities filed requests for rehearing and/or clarification of Order No. 888. While these parties raise a variety of arguments -- including legal, policy, and technical arguments -- the majority (including a majority of public utilities) agree that we need to harness the benefits that competitive electricity markets can bring to the nation. The disagreements primarily focus on the mechanics of how we should do this, who should pay the costs of the transition to competition, and how long the transition should take. First, parties disagree on what is necessary to remedy undue discrimination and to develop truly competitive wholesale markets. Many focus specifically on the tariff terms and conditions of good transmission access and seek changes in the Order No. 888 pro forma tariff. In response to these types of rehearing arguments, the Commission has fine-tuned or changed some of the pro forma tariff terms and conditions to better ensure that they do not permit discrimination and that they result in well-functioning markets. Other petitioners focus on additional structural changes which they believe are necessary, such as mandatory corporate restructuring (divestiture of generation assets) or mandatory creation of independent transmission system operators (ISOs). With regard to restructuring, the Commission continues to believe that functional unbundling of the utility's business, not corporate divestiture or mandatory ISOs, is sufficient to remedy undue discrimination at this time. Docket Nos. RM95-8-001 -14- and RM94-7-002 The most contentious arguments raised on rehearing involve how we deal with the transition costs associated with moving to competition. Some utilities have invested millions of dollars in facilities and purchased power contracts based on an explicit or implicit obligation to serve customers and the expectation that those customers would remain on their systems for the foreseeable future. These utilities face so-called "stranded costs" which, if not recovered from the customers that caused the costs to be incurred, could be shifted to other customers. There are two basic categories of rehearing arguments regarding stranded cost recovery. Most utilities want a guarantee from this Commission that they will recover all stranded costs, whether caused by losing retail customers or wholesale customers. Many customers, on the other hand, want to be able to abrogate existing power supply contracts so that they can immediately leave their current suppliers' systems and shop for cheaper power elsewhere, without paying the sunk costs that their suppliers incurred on their behalf. In response to these diverse arguments, the Commission has struck a reasonable balance that, for certain defined circumstances, permits utilities the opportunity to seek extra- contractual recovery of stranded costs from their departing customers and permits customers the opportunity to make a showing that their contracts should be shortened or terminated. Based on our experience in the natural gas area, we have learned that it is critical to address these issues early, but we also have Docket Nos. RM95-8-001 -15- and RM94-7-002 chosen an approach different from that taken in the gas area because of the different circumstances facing the electric industry. In balancing the wide array of interests reflected in the rehearing petitions, we have made a number of clarifications and granted rehearing on some issues, but we reaffirm the core elements and framework of Order No. 888. Since the time the final rules issued, as discussed in Section III, the pace of competitive change has continued to escalate in the industry at both the wholesale and retail levels as competitors, customers and state regulatory authorities aggressively seek ways to lower the price of electricity. We therefore believe it is all the more critical that we remedy undue discrimination in interstate transmission services now, and that we do so generically, if we are to fulfill our responsibilities under the FPA to protect consumers and provide a fair and orderly transition to new competitive markets. Finally, with respect to environmental issues associated with this rulemaking, certain parties on rehearing continue to challenge the adequacy of our Final Environmental Impact Statement (FEIS). The central issues are whether the Final Rule will increase emissions of nitrogen oxides (NOx) from certain fossil-fuel fired generators, which could affect air quality in downwind areas to which these emissions may be carried, and the Commission's authority to mitigate environmental consequences. Docket Nos. RM95-8-001 -16- and RM94-7-002 We deny rehearing on the environmental issues raised and affirm our conclusion that we have satisfied our obligations under NEPA. As discussed in detail in the Final Rule, this rulemaking is expected to slightly increase or slightly decrease total future NOx emissions, depending on whether competitive conditions in the electric industry favor the utilization of natural gas or coal as a fuel for the generation of electricity. We also examined mitigation options over the longer term, and found that the preferred approach for mitigating any adverse environmental consequences would be for the Environmental Protection Agency (EPA) and the states to address the problem through regulatory authorities available under the Clean Air Act. The petitions for rehearing have not persuaded us to change this approach. Indeed, we note that since the issuance of Order No. 888, the EPA has concluded that the Rule is unlikely to have any immediate significant adverse environmental impact and thus concurred that the Commission's analysis is adequate under NEPA. We further note that EPA has recently taken steps under the Clean Air Act to address NOx emissions as part of a comprehensive emissions control program, along the lines endorsed by the Commission in the EIS. In summary, the Commission believes that our authorities under the FPA not only permit us to adapt to changing economic realities in the electric industry, but also require us to do so to eliminate undue discrimination and protect electricity customers. The measures required in Order No. 888 are necessary Docket Nos. RM95-8-001 -17- and RM94-7-002 to remedy undue discrimination in interstate transmission services and provide an orderly and fair transition to competitive bulk power markets. To assist the reader, we provide below a section-by-section summary of key elements of this Order on Rehearing. Scope of the Rule In this section we discuss petitions to rehear our requirement that transmission and power sales services be contracted for separately (unbundled). We reaffirm that this requirement is a reasonable and workable means of assuring non- discriminatory open access transmission. In doing so we refuse invitations to require that utilities under our jurisdiction divest themselves of generation or transmission assets. We do, however, make an important clarification involving how we will deal with existing contracts that contain so-called Mobile-Sierra clauses (clauses under which one or both parties agreed not to seek modification of contract terms unless they could show that it is contrary to the public interest not to permit the modification). In Order No. 888 we concluded that contracts would not be abrogated by operation of the Rule. Instead, preexisting contracts would continue to be honored until such time as they were revised or terminated. We also found that those who were operating under pre-existing requirements contracts containing Mobile-Sierra clauses would nonetheless be allowed to seek reform of the contracts on a case-by-case basis. On rehearing we affirm Docket Nos. RM95-8-001 -18- and RM94-7-002 that public utilities will be allowed to file to amend their Mobile-Sierra contracts for the limited purpose of providing an opportunity to seek recovery of stranded costs, without having to make a public interest showing that such cost recovery should be permitted. However, these utilities will have the burden, on a case-by-case basis, of showing that they had a reasonable expectation of continuing to serve the departing customer after the contract term. We clarify that if the utilities under such contracts seek to modify provisions that do not relate to stranded costs, they will have the burden of showing that the provisions are contrary to the public interest. We here make clear that, in turn, customers will be allowed to file to amend their Mobile-Sierra contracts to modify any contract term or to terminate the contract, without having to make a showing that the contract terms are contrary to the public interest. Instead, customers seeking modifications must demonstrate that the provisions they wish modified are no longer "just and reasonable." We reaffirm our conclusion in the Final Rule that if a customer seeks to shorten or eliminate the term of its contract, however, any contract modification approved by the Commission will provide for appropriate stranded cost recovery by the customer's supplying utility. These various provisions meet the two-fold need to deal with stranded costs and the contracts under which those costs were incurred. However, as described in Order No. 888, the opportunity to reform Mobile-Sierra contracts extends only to a Docket Nos. RM95-8-001 -19- and RM94-7-002 limited set of contracts -- those entered into on or before July 11, 1994, for requirements power. Comparability In this section we deal with those requesting rehearing of our conclusions regarding what "comparable" service is, who is eligible for that service, and how it is to be implemented. We reaffirm our finding that, as a matter of law, we have jurisdiction over the rates, terms and conditions of unbundled transmission service provided to retail customers. We also clarify that we have authority to order "indirect" unbundled retail transmission services and that if such transmission is ordered by us in the future, or if it is provided voluntarily, otherwise eligible customers may obtain such service under the open access tariff. We expect public utilities to provide such service in the future and, if they do not, we will not hesitate to order it. We modify in two respects the definition of who is eligible for open access transmission service. First, we clarify that, with respect to service that this Commission is prohibited from ordering by section 212(h) of the Federal Power Act (retail wheeling directly to an ultimate consumer and "sham" wholesale wheeling), entities are eligible for such service under the tariff only if it is provided pursuant to a state requirement or is provided voluntarily. Second, we clarify that retail customers taking unbundled service pursuant to a state requirement (i.e., direct retail service) are eligible for such Docket Nos. RM95-8-001 -20- and RM94-7-002 service only from those transmission providers that the state orders to provide service. These changes are made to make clear that our rules cannot be used to circumvent the proscriptions placed on the Commission against ordering direct retail wheeling. Ancillary Services In this section we deal with petitions to rehear our definitions of ancillary services -- those services such as scheduling, voltage control, and supplemental reserve service that must or can attend the providing of transmission service -- as well as the provisions involving these services. We reaffirm that tariffs must separately state the charges for these services. We do modify some of the definitions of these services to conform to industry needs and practices. Most importantly, we make clear that the transmission provider's sale of ancillary services associated with providing basic transmission service is not a wholesale merchant function and thus does not violate the standards of conduct imposed with Order No. 889. Coordination Arrangements The requirement to provide non-discriminatory open access transmission applies to any agreement between utilities that contains transmission rates, terms or conditions. This includes pooling arrangements and agreements between companies contracting to provide each other mutually beneficial transmission services. In Order No. 888 we laid out rules under which the open access comparability requirements would apply to tight and loose power pools, public utility holding companies and bilateral Docket Nos. RM95-8-001 -21- and RM94-7-002 coordination agreements. We also set out principles that would govern our approval of independent system operator (ISO) agreements. In this section we affirm the rules governing coordination agreements. In doing so we clarify the definition of "loose pool." We also make clear that, unlike in other situations where we require utilities to provide not only the services they provide themselves but those they could provide themselves, we will require members of loose pools to offer to third parties only those transmission services that they provide themselves under their pool-wide agreements. We also reaffirm our strong commitment to the concept of ISOs and the ISO principles described in Order No. 888. In doing so we reject arguments that we should require that ISOs be formed. At the same time, we emphasize that while there is no "cookie-cutter" approach to forming an acceptable ISO, the requirement of fair and non-discriminatory rules of governance (Principle One) and the requirement that ISO employees have no financial interest in the economic interests of power marketers - - backed by strict conflict of interest provisions -- (Principle Two) are fundamental to our approving any ISO. Pro Forma Tariff Provisions The pro forma tariff is the basic mechanism implementing the requirements of comparable open access transmission. It provides the details of the transmission service obligations imposed on jurisdictional utilities by the Rule. On rehearing we affirm Docket Nos. RM95-8-001 -22- and RM94-7-002 most of the provisions set out in Order No. 888 for the pro forma tariff. We do make changes to conform the pro forma tariff to changes adopted under other sections (for example, the definition of "eligible customer"). The rehearing petitions raised many questions about how particular aspects of the tariff will work. For the most part, these questions cannot be answered generically, but must be resolved on a case-by-case basis in the context of specific fact situations. However, the petitions brought to light issues that require clarifications and in some cases revisions to the tariff. The most significant of these involve discounting practices, provisions governing priority of service and curtailment, and the reciprocity provision. Discounting practices. Originally, we provided different rules depending upon whether the transmission provider was offering a discount to itself or an affiliate or offering a discount to a non-affiliate. In response to the rehearing petitions, we are making three significant changes to the discounting requirements to better permit the ready identification of discriminatory discounting practices while also providing greater discount flexibility. First, any discount offered on transmission services (including supporting ancillary services) by a transmission provider or requested by any customer must now be made only over the OASIS. With this change, all will have the same, timely access to discounted services. In making this change, we clarify Docket Nos. RM95-8-001 -23- and RM94-7-002 that a transmission provider may limit its discounted service to particular time periods. Second, once the provider and customer agree on a discount, the details of the discounted service -- the price, points of receipt and delivery, and length of service -- must be immediately posted on the OASIS. Third, we revise our Rule respecting what other transmission paths must be offered at a discount. Originally, in Order No. 888, we required that when a discount was offered over one path, the transmission provider would have to provide that discount over all other unconstrained paths on its system. We will no longer require this. Instead, the discount will be limited to those unconstrained paths that go to the same point(s) of delivery as the discounted service being provided on the transmission provider's system. The discount will extend for the same time period and must be offered to all transmission service customers. Priority and Curtailment. We affirm the right of first refusal policy that reservation priority continues for firm service customers served under a contract of one year or more. We also affirm that curtailment must be made on a pro-rata basis and clarify that non-firm point-to-point service is subordinate to firm service. However, we clarify that the pro-rata curtailment requirement extends to only those transactions that alleviate the constraint. Docket Nos. RM95-8-001 -24- and RM94-7-002 Reciprocity. In Order No. 888 we conditioned the use of a public utility's open access service on the agreement that, in return, it is offered reciprocal service by non-public utilities that own or control transmission facilities. Such reciprocal service does not have to be through an open access tariff, i.e., a tariff available to all eligible customers, but may be limited to those public utilities from whom the non-public utility obtains open access service. We affirm the reciprocity condition. In doing so, however, we make several clarifications. First, a public utility is free to offer transmission service to a non-public utility without requiring reciprocal service in return. In other words, it may voluntarily waive the reciprocity condition. However, if it chooses to do so, transmission service must be provided through the pro forma tariff. Alternatively, bilateral agreements for transmission service provided by the public utility will not be permitted. Second, we clarify that under the reciprocity condition a non-public utility must agree to offer the Transmission Provider any transmission service the non-public utility provides or is capable of providing on its system. This means that the non- public utility undertaking reciprocity must have an OASIS and must operate under the standards of conduct imposed under Order No. 889 unless it is granted a waiver by the Commission or, where appropriate, by a regional transmission group (RTG) of which it is a member. We also clarify that a non-public utility cannot avoid its responsibilities by obtaining transmission service Docket Nos. RM95-8-001 -25- and RM94-7-002 through other transmission customers. Further, the seller as well as the buyer in the chain of a transaction involving a non- public utility will have to comply with the reciprocity condition. Third, we adhere to our decision not to treat generation and transmission (G&T) cooperatives and their member distribution cooperatives as a single unit. Thus, the reciprocity provision extends to the G&T Cooperative and not to its member distribution cooperatives. Fourth, we clarify the "safe harbor" provision under which a non-public utility may get a Commission decision that its transmission tariff suffices to meet reciprocity. A non-public utility may limit the use of any reciprocity tariff that it voluntarily files at the Commission to those transmission providers from whom the non-public utility obtains open access service. A non-public utility also may satisfy reciprocity through bilateral agreements with a public utility. As a related matter, if a public utility believes a non-public utility is violating the reciprocity condition, it may file with the Commission a petition to terminate its service to the non-public utility. Fifth, we clarify that non-public utilities may include stranded cost provisions in their reciprocity tariffs. Sixth, the order on rehearing removes the term "interstate" from the reciprocity provisions. This is to make clear that reciprocity applies even to those who do not own or control Docket Nos. RM95-8-001 -26- and RM94-7-002 interstate transmission facilities; i.e., foreign utilities and those located in the ERCOT region of Texas. As to local furnishing bonds held by some public utilities, we clarify that all costs associated with the loss of tax-exempt status of those bonds caused by providing open access transmission service are properly considered costs of providing that service. This includes costs of defeasing, redeeming, and refinancing those bonds. Other Clarifications. In this order on rehearing we take the opportunity to clarify various other tariff provisions. Among these: Transmission providers do not have to take service under the open access tariff for transmitting power purchased on behalf of their bundled retail customers. Also, the ability to reserve capacity to meet the reliability needs of a transmission provider's native load applies equally to present transmission and transmission that is built in the future. Implementation On rehearing, we make no substantive changes to the implementation provisions originally required under Order No. 888. For the most part, the implementation process has been completed. Utilities have made the requisite tariff and compliance filings and public and non-public utilities have, through other orders, been provided guidance as to obtaining waivers of Order No. 888 and Order No. 889 requirements. We emphasize that we do not require the abrogation of existing contracts. Rather, the Rule requires only that Docket Nos. RM95-8-001 -27- and RM94-7-002 transmission providers offer transmission under the open access tariff in addition to existing service obligations. Commitments made under existing contracts will continue. Of course, both transmission providers and their customers may seek to revise the terms and conditions of existing contracts by making the necessary filings, as appropriate, under Sections 205 or 206 of the Federal Power Act. State and Federal Jurisdiction On rehearing we reaffirm our decision that when transmission service is provided to serve retail customers apart from any contract for the retail sale of power, i.e., when it is provided on an unbundled basis, that transmission service is under our jurisdiction. In today's market, and increasingly in the future as more states adopt retail wheeling programs, retail transactions are, and will be, broken down into products that are sold separately -- transmission and generation -- and sold by different entities. The exercise of our jurisdiction over the rates, terms and conditions of unbundled retail transmission will, therefore, become more important. We also recognize that states have jurisdiction over facilities used for local distribution. On rehearing we also reaffirm the seven-factor test of Order No. 888 to distinguish transmission under our jurisdiction from state-jurisdictional local distribution. In doing so, we recognize that our test does not resolve all possible issues. There may be other factors that should be taken into account. Docket Nos. RM95-8-001 -28- and RM94-7-002 The test, therefore, is designed for flexibility to include unique local characteristics and usages. To that end, we will continue to defer to state findings on these matters. In addition, we clarify that states have the authority to determine the retail marketing areas of the electric utilities within their respective jurisdictions. We also recognize that states have the concomitant authority to determine the end user services these utilities provide. Stranded Costs On rehearing, we reaffirm our basic decisions surrounding the recovery of stranded costs. Utilities will be allowed the opportunity to seek to recover legitimate, prudent, and verifiable wholesale stranded costs. This opportunity is limited to costs associated with serving customers under wholesale requirements contracts executed on or before July 11, 1994 that do not contain explicit stranded cost provisions; and costs associated with serving retail-turned-wholesale customers. We clarify that we will consider on a case-by-case basis whether to treat a contract extended or renegotiated without a stranded cost provision as an existing contract for stranded cost purposes. In each case, the opportunity to seek stranded costs is limited to situations in which there is a direct nexus between the availability and use of a Commission-required transmission tariff and the stranding of the costs. The Rule does not allow Docket Nos. RM95-8-001 -29- and RM94-7-002 the recovery of costs that do not arise from the new, accelerated availability of non-discriminatory transmission access. The Commission also reaffirms its decision that stranded costs should be recovered from the customer that caused the costs to be incurred. The Commission is not requiring other remaining customers, or the utility, to shoulder a portion of its stranded costs that meet the requirements for recovery. The Commission, as described in Order No. 888, will be the primary forum for addressing the recovery of stranded costs caused by retail-turned-wholesale customers. With respect to such cases, we have made several changes. First, the Commission has reconsidered its decision respecting cases involving existing municipal utilities that annex retail customer service territories. Under Order No. 888, we found that in such cases the Commission should not be the primary forum for determining stranded cost recovery. On rehearing we now find that such cases should fall within our province. Second, we clarify that the opportunity for recovery of stranded costs associated with retail-turned-wholesale customers applies regardless of whether the customer or its new supplier is the one requesting and contracting for the transmission service. To this end, we have revised the definition of "wholesale stranded cost." With respect to the recovery of stranded costs caused by unbundled retail wheeling, we affirm that the only circumstance Docket Nos. RM95-8-001 -30- and RM94-7-002 in which we will entertain requests for these types of costs is when the state regulatory authority does not have authority under state law to address stranded costs when the retail wheeling is required. We clarify that if a state regulatory authority has in fact addressed such costs, regardless of whether it has allowed full recovery, partial recovery or no recovery, utilities may not apply to the Commission to recover stranded costs caused by the retail wheeling. Other In this section we resolve questions concerning our information reporting requirements, regional transmission groups, and the special situations posed by utilities in the Pacific Northwest and by federal power marketing and similar agencies. Here we make some minor clarifications but make no significant changes to Order No. 888. We are not persuaded that the information reporting requirements need to be changed at this time. Finally, we reject arguments that would have us fix generically any particular rate methodology for providing open access transmission service under the pro forma tariff. II. PUBLIC REPORTING BURDEN This order on rehearing issues a number of minor revisions to the Final Rule. We find, after reviewing these revisions, that they do not, on balance, increase the public reporting burden. Docket Nos. RM95-8-001 -31- and RM94-7-002 The Final Rule contained an estimated annual public reporting burden based on the requirements of the Open Access Final Rule and the Stranded Cost Final Rule. 3/ Using the burden estimate contained in the Final Rule as a starting point, we evaluated the public burden estimate contained in the Final Rule in light of the revisions contained in this order and assessed whether this estimate needed revision. We have concluded, given the minor nature of the revisions, and their offsetting nature, that our estimate of the public reporting burden of this order on rehearing remains unchanged from our estimate of the public reporting burden contained in the Final Rule. The Commission has conducted an internal review of this conclusion and has assured itself that there is specific, objective support for this information burden estimate. Moreover, the Commission has reviewed the collection of information required by the Final Rule, as revised by this order on rehearing, and has determined that the collection of information is necessary and conforms to the Commission's plan, as described in the Final Rule, for the collection, efficient management, and use of the required information. Persons wishing to comment on the collections of information required by the Final Rule, as modified by this order on rehearing, should direct their comments to the Desk Officer for 61 FR 21540 at 21543; FERC Stats. & Regs.  31,036 at 31,638 (1996). No comments were filed in objection to the public burden estimate contained in the Open Access Final Rule and the Stranded Cost Final Rule. Docket Nos. RM95-8-001 -32- and RM94-7-002 FERC, Office of Management and Budget, Room 3019 NEOB, Washington, D.C. 20503, phone 202-395-3087, facsimile: 202-395- 7285 or via the Internet at hillier__t@a1.eop.gov. Comments must be filed with the Office of Management and Budget within 30 days of publication of this document in the Federal Register. Three copies of any comments filed with the Office of Management and Budget also should be sent to the following address: Ms. Lois Cashell, Secretary, Federal Energy Regulatory Commission, Room 1A, 888 First Street, N.E., Washington, D.C. 20426. For further information, contact Michael Miller, 202-208-1415. III. BACKGROUND In the Final Rule, we detailed the events that led up to this rulemaking, including the significant technical, statutory and regulatory changes that have occurred in the electric industry since the FPA was enacted in 1935. 4/ In particular, we focused on the competitive influences of the Public Utility Regulatory Policies Act of 1978, the Congressional mandate in the Energy Policy Act of 1992 to encourage competition in electricity markets, and the need for reform in the industry if consumers are to achieve the benefits that greater competition can bring. In the ten months since the Final Rule issued, competitive changes have escalated at an even faster pace in virtually all areas of the electric industry. These changes are driven not only by the Commission's Final Rule, but also by state FERC Stats. & Regs. at 31,638-52; mimeo at 13-51. Docket Nos. RM95-8-001 -33- and RM94-7-002 restructuring initiatives and by continuing pressures from customers to take advantage of emerging competitive markets and the lower electricity rates they can bring. All of the existing 166 public utilities that own, control or operate interstate transmission facilities (listed as Group 1 and Group 2 utilities in the Final Rule) have filed the Order No. 888 pro forma open access tariff or requested a waiver of the requirement. Similarly, they either have adopted an electronic information network or requested a waiver of the requirement. Five non-public utilities have submitted reciprocal transmission tariffs and more than 20 have requested a waiver of the reciprocity condition in the pro forma tariff. 5/ Significant competitive changes also have accelerated with respect to power pooling, state restructuring initiatives, and Independent System Operators (ISOs). Under Order No. 888 and subsequent implementation orders, the Commission required the filing of revised pooling agreements and joint pool-wide transmission tariffs by December 31, 1996, in order to remedy undue discrimination in transmission services provided through interstate power pooling arrangements. Among the power pool filings were a New England (NEPOOL) comprehensive restructuring As a condition of using a public utility's open access tariff, any user, including non-public utilities, must offer reciprocal comparable transmission access to the public utility in return. Order No. 888 provides a voluntary mechanism whereby non-public utilities can obtain Commission confirmation that what they are offering meets the tariff reciprocity condition. Non-public utilities also may seek a waiver of the reciprocity condition. Docket Nos. RM95-8-001 -34- and RM94-7-002 proposal, a New York proposal, a Pennsylvania-New Jersey-Maryland (PJM) compliance filing and a Western Systems Power Pool filing. In response to the Commission's encouragement in Order No. 888 of ISOs as a possible means for accomplishing comparable access, a number of utilities and states are well underway in developing this new institution. The fundamental purpose of an ISO is to operate the transmission systems of public utilities in a manner that is independent of any business interest in sales or purchases of electric power by those utilities. The Commission has received several proposals for forming ISOs, one as part of the multi-docketed filing engendered by California's restructuring plan, and others relating to power pool filings. A number of regions are also developing ISO proposals. Some regions previously considering regional transmission groups (RTGs), whose primary purpose is regional planning of transmission facility construction and upgrades, have now broadened their discussions to include an ISO. Investor-owned utilities in California, at the order of both the state commission and the legislature, have filed proposals with the Commission that would transfer control of transmission facilities to an ISO in conjunction with the formation of a state-wide power exchange to facilitate both wholesale and retail access. While the case presents many complex issues for the Commission to resolve, the California proposal is fundamentally compatible with the pro-competitive open-access requirements of Order Nos. 888 and 889. The Commission's open-access policies Docket Nos. RM95-8-001 -35- and RM94-7-002 therefore have provided a framework for California, and other states, to explore customer choice initiatives. Other major regions of the country also are instituting ISOs. Member utilities of the PJM Power Pool filed competing ISO proposals with the Commission and are currently working to reconcile the differences between their proposals. The New York Power Pool recently filed a proposal to create an ISO and a power exchange for New York. The New England Power Pool is exploring a new industry structure for its region that centers on the creation of an ISO. Utilities and other market participants in the Electric Reliability Council of Texas have also formed an ISO. Discussions are underway among utilities from Virginia to Wisconsin in an attempt to create a Midwestern ISO. Members of the Mid-America Power Pool are discussing an ISO proposal. In the Pacific Northwest, utilities are involved in negotiations intended to lead to the formation of an independent grid operator (Indego). The combined available generation resources of the utilities in these groups is on the order of 428 GW out of a total of approximately 732 GW for total U.S. resources (as of the end of 1996). Thus, assuming these ISO arrangements come to fruition, about three-fifths of the industry may have independent system operators controlling their transmission systems. Moreover, every state but one has proposed or is considering or developing retail competition programs. For example, New Hampshire, Illinois and Massachusetts began pilot programs in the Docket Nos. RM95-8-001 -36- and RM94-7-002 past year, and retail transmission service for these pilot programs currently is being taken pursuant to tariffs approved by both the state commissions and this Commission. The Massachusetts Department of Public Utilities has sent a proposal to the state legislature calling for retail competition to begin in January 1998. The New York Public Service Commission has issued an order proposing that retail competition begin in early 1998. The New Jersey Board of Public Utilities has issued a proposal permitting customer choice beginning in October of 1998. The Vermont Public Service Board has sent a plan to the legislature recommending that full customer choice begin by the end of 1998. The Arizona Corporation Commission has adopted rules to phase in competition over four years, beginning in January 1999. Recently, the Maine Public Utilities Commission issued a final report and recommendation to the legislature for retail competition to begin in January 2000. In addition, Rhode Island and Pennsylvania both have new laws requiring customer choice. These are only a few of the many state initiatives that are under way that will dramatically alter the structure of the electric industry. Since Order No. 888 was issued, significant efforts also have been made to ensure that reliability of the transmission grid is maintained and that reliability criteria are compatible with competitive markets. The North American Electric Reliability Council (NERC) has continued its efforts to broaden its membership and to fashion reliability requirements to fit a Docket Nos. RM95-8-001 -37- and RM94-7-002 more competitive electric power industry. For example, the NERC Board of Directors voted to require mandatory compliance by all power market participants with its reliability standards. NERC is also establishing new entities called regional security coordinators to oversee the stability of grid operations and to direct the development of an extensive new communications network. Various NERC committees are considering ways to improve the tracking of power transactions, identify the network impacts of transactions, and reflect the actual flow of power over the network when making reservations for transmission service. These efforts are likely to intensify as the industry continues to adapt to competitive changes occurring in the marketplace. Thus, all segments of the electric industry have taken significant steps in the past year in response to the emerging wholesale competitive markets enabled by Order No. 888 as well as state retail competition initiatives. The competitive framework established by Order No. 888, whose centerpiece is non- discriminatory transmission services and a fair and orderly stranded cost recovery mechanism, is critical to the successful transition to, and full development of, the industry restructuring proposals that are well underway in all major regions of the country. Docket Nos. RM95-8-001 -38- and RM94-7-002 IV. DISCUSSION A. Scope of the Rule 1. Introduction Rehearing Requests Severability of Rules Several entities assert that the Commission should find that the requirements of open access transmission and stranded cost recovery are not severable. 6/ They argue that if one of these provisions is invalidated by a court or otherwise removed, the orders in their entirety should be withdrawn or stayed pending reconsideration by the Commission, and public utilities should be allowed to withdraw or file amended transmission tariffs. Commission Conclusion The Commission will not, at this time, make any determination whether or not the open access transmission, stranded cost recovery and OASIS provisions of Order Nos. 888 and 889 are severable. Accordingly, we make no finding whether, if one of these provisions is invalidated, Order Nos. 888 and 889 should be withdrawn or stayed in their entirety. We believe that our decisions in Order Nos. 888 and 889 will be upheld by the courts. Moreover, it would be premature to consider the appropriateness of a stay or withdrawal at this time. Circumstances at the time of any court order would dictate how we E.g., Nuclear Energy Institute, Southern, EEI. EEI and Nuclear Energy Institute also argue that Order No. 889 should not be severable. Docket Nos. RM95-8-001 -39- and RM94-7-002 should proceed and we would consider all such circumstances, and the entirety of our policy decisions, before determining how to respond to a court decision. 2. Functional Unbundling In the Final Rule, the Commission found that functional unbundling of wholesale generation and transmission services is necessary to implement non-discriminatory open access transmission. 7/ At the same time, the Commission recognized that additional safeguards were necessary to protect against market power abuses. Thus, the Commission adopted a code of conduct, discussed in detail in the final rule on OASIS, to ensure that the transmission owner's wholesale power marketing personnel and the transmission customer's power marketing personnel have comparable access to information about the transmission system. The Commission also noted that section 206 of the FPA is available if a public utility seeks to circumvent the functional unbundling requirements. As a further precaution against unduly discriminatory behavior, the Commission stated that it will continue to monitor electricity markets to ensure that functional unbundling adequately protects transmission customers. The Commission also indicated that it would continue to observe both the evolution of competitive power markets and the progress of the industry in adapting structurally to competitive markets. If it subsequently FERC Stats. & Regs. at 31,654-56; mimeo at 57-61. Docket Nos. RM95-8-001 -40- and RM94-7-002 becomes apparent that functional unbundling is inadequate or unworkable in assuring non-discriminatory open access transmission, the Commission indicated that it would reevaluate its position and decide whether other mechanisms, such as ISOs, should be required. The Commission concluded that functional unbundling, coupled with these safeguards, is a reasonable and workable means of assuring that non-discriminatory open access transmission occurs. In the absence of evidence that functional unbundling will not work, the Commission indicated that it was not prepared to adopt a more intrusive and potentially more costly mechanism -- corporate unbundling -- at this time. Rehearing Requests Several entities disagree with the Commission's decision to require functional unbundling of wholesale generation and transmission as a means of assuring non-discriminatory open access transmission. 8/ American Forest & Paper argues that utilities must be required to divest or spin-off their generating assets through operational unbundling or divestiture. It alleges that it was arbitrary and capricious, and not supported by evidence, for the Commission to rely on a monopolist's code of conduct to protect against monopoly abuses. Nucor asserts that a financial conflict of interest remains and that the Commission cannot monitor the exchanges of information between utility E.g., American Forest & Paper, Nucor, NY Municipal Utilities. Docket Nos. RM95-8-001 -41- and RM94-7-002 generation and transmission employees. It declares that a credible information disclosure requirement is needed that makes generation cost and production data visible to all participants on a same-time basis. NY Municipal Utilities also believes that the Commission did not go far enough and argues that the Commission should have required operational unbundling, at least for tight power pools. Commission Conclusion The Commission reaffirms its finding in the Final Rule that, based on the information available at this time, functional unbundling, along with the flexible safeguards discussed in the Final Rule, is a reasonable and workable means of assuring non- discriminatory open access transmission. We see no need to adopt a more intrusive and potentially more costly approach at this time based on speculative allegations that functional unbundling may not work and that more severe measures may be needed. Indeed, despite a number of opportunities to do so, no entity has submitted any evidence suggesting that this less intrusive approach would not work. We do emphasize, however, that we have not adopted a rigid approach, but have indicated a willingness to monitor the situation and, if events require, reevaluate our decision and decide whether another mechanism may be more appropriate. Until we see evidence that functional unbundling will not work, we will continue to require functional unbundling, with the safeguards enumerated in the Final Rule and in Order No. 889. Docket Nos. RM95-8-001 -42- and RM94-7-002 3. Market-based Rates a. Market-based Rates for New Generation In the Final Rule, the Commission codified its determination in Kansas City Power & Light Company (KCP&L) 9/ that the generation dominance standard for market-based sales from new capacity should be dropped. 10/ The Commission explained that it had yet to find an instance of generation dominance in long-run bulk power markets and no commenter had presented any evidence to that effect. However, the Commission emphasized that it will not ignore specific evidence presented by an intervenor that a seller requesting market-based rates for sales from new generation nevertheless possesses generation dominance. The Commission further clarified that dropping the generation dominance standard for new capacity does not affect the demonstration that an applicant must make in order to qualify for market-based rates for sales from its existing generating capacity. Rehearing Requests Several entities take issue with the Commission's determination to drop the generation dominance standard for market-based sales from new capacity. 11/ American Forest & Paper argues that the Commission should delay its decision until 67 FERC  61,183 at 61,557 (1994). FERC Stats. & Regs. at 31,656-57; mimeo at 63-66. E.g., American Forest & Paper, SC Public Service Authority, TDU Systems, LEPA, San Francisco. Docket Nos. RM95-8-001 -43- and RM94-7-002 effective competition has been demonstrated to exist in all markets. SC Public Service Authority maintains that the Commission must determine on a case-by-case basis whether public utilities have market power (for both existing and new capacity). It further argues that the Commission must develop an analysis of structural conditions to use in assessing the potential for market power consistent with that used by DOJ and FTC in merger proceedings and that reflects the conditions of the industry. SC Public Service Authority also asserts that the Commission must require as a condition of market rates for sales in the bulk power market, which it defines to be limited to sales to integrated utilities, that the selling utility file rate cases with the Commission and the applicable state commissions to avoid subsidization by captive consumers. TDU Systems alleges that the long-run bulk power market upon which the KCP&L decision was based is overly broad and ignores the distinction between firm power, which "entities subject to others' market power are most commonly in need of" and other bulk power services. TDU Systems take issue with the Commission's conclusion in KCP&L that large numbers of capacity offers from IPPs and QFs demonstrate that the market abounds with competitors. TDU Systems argues that the Commission's "assumption that large numbers of offers of power equate with large numbers of offers of firm power is questionable at best, Docket Nos. RM95-8-001 -44- and RM94-7-002 and very likely incorrect." 12/ Similarly, LEPA argues that the Commission ignored evidence submitted by LEPA in comments "that the transmission dominant utility still retained monopoly power over RQ [requirements] markets on which LEPA's members are dependent for their bulk power supply." Because the Commission ignored the RQ market and the evidence of concentration in that market, LEPA asserts that the Commission's decision is reversible error. LEPA further argues that the Commission ignored the undisputed testimony of LEPA's witness that reliability requirements constrain the geographic scope of the RQ market severely. San Francisco argues that the burden to demonstrate affirmatively the absence of capacity constraints as a precondition to receiving authority to charge market-based rates for sales from new capacity should be upon public utility applicants, who possess the information concerning capacity constraints. Commission Conclusion We reaffirm our decision to codify the determination in KCP&L that the generation dominance standard for market-based sales from new capacity should be dropped. Petitioners have not presented any evidence that demonstrates generation dominance in long-run bulk power markets and, as discussed in Order No. 888, we have found no such evidence of generation dominance in any of TDU Systems at 92. Docket Nos. RM95-8-001 -45- and RM94-7-002 the numerous market-based rate cases decided by the Commission since KCP&L. In addition, as described in Order No. 888, the Commission will consider evidence of generation dominance, including generation dominance that results from transmission constraints, when such evidence is presented by an intervenor in a market-based rate case in which a utility seeks market-based pricing associated with new capacity. American Forest & Paper's argument that the Commission should delay codification of KCP&L until effective competition has been demonstrated to exist in all markets ignores the fact that we have eliminated the generation dominance standard for market-based rates from new capacity only, and that the generation standard still applies to applications for market- based rates from existing generation. Other entities similarly argue that other markets in which utilities may sell power from new capacity may be highly concentrated with respect to generation, or that these utilities may otherwise be able to exert market power. Specifically, TDU Systems and LEPA express concern that the new policy may result in the exercise of market power over very specific bulk power products. To allay these concerns, we note that eliminating the generation dominance showing applies only to sales from new capacity. It does not apply to entire classes of service or to specific products. In addition, the policy eliminates the showing only as a matter of routine in each filing. We reemphasize that the Commission will consider specific evidence Docket Nos. RM95-8-001 -46- and RM94-7-002 of generation dominance associated with new capacity at the time the seller seeks market-based rates for the new capacity, including whether the addition of the new capacity, when combined with existing capacity, results in generation dominance. This clearly includes situations where existing sources of generation must be combined with new resources to produce a firm power supply. Where entry barriers are a concern, intervenors are free to raise the issue. SC Public Service Authority also raises a number of concerns relating to the ability of utilities to exercise market power if they are permitted to sell new capacity at market-based rates. These concerns generally include how the Commission determines product and geographic markets, and the standards used to determine whether sellers can exercise market power. In response to these concerns, as noted above public utility owners of new capacity must still seek case-by-case approval before they can sell power from new capacity at market-based rates and, as stated in the Final Rule, intervenors may present specific evidence that a seller requesting such market rates possesses generation dominance or otherwise has market power. 13/ These requirements We do not agree with entities that claim that our decision to rely on evidence raised by intervenors in particular cases with respect to transmission constraints improperly shifts the burden away from the utility, which has the greatest access to information concerning those constraints. Given that we have yet to see any evidence of generation dominance in long-term bulk power markets we do not believe that it is appropriate to burden all market-based rate applicants with significant information requirements as an (continued...) Docket Nos. RM95-8-001 -47- and RM94-7-002 include considerations of transmission market power, whether other barriers to entry exist and whether there is evidence of affiliate abuse or reciprocal dealing. b. Market-based Rates for Existing Generation In the Final Rule, the Commission found that there is not enough evidence on the record to make a generic determination about whether market power may exist for sales from existing generation. 14/ The Commission indicated that it would continue its case-by-case approach that allows market-based rates based on an analysis of generation market power in first tier and second tier markets. 15/ The Commission further indicated that while it will continue to apply the first-tier/second-tier analysis, it will allow applicants and intervenors to challenge the presumption implicit in the Commission's practice that the relevant geographic market is bounded by the second-tier utilities. Finally, the Commission stated that it would maintain its current practice of allowing market-based rates for existing (...continued) initial matter. However, if an intervenor raises a specific factual concern with respect to a transmission constraint that may result in the exercise of market power in a particular case, we will examine those facts in a paper or formal hearing. In that context, the utility would be required to come forward with information sufficient to permit a full examination of the effect of the constraint on the applicant's ability to exercise market power. FERC Stats. & Regs. at 31,660; mimeo at 73-75. See, e.g., Southwestern Public Service Company, 72 FERC  61,208 at 61,996 (1995), reh'g pending. Docket Nos. RM95-8-001 -48- and RM94-7-002 generation to go into effect not subject to refund. 16/ To the extent that either the applicant or an intervenor in individual cases offers specific evidence that the relevant geographic market ought to be defined differently than under the existing test, the Commission indicated that it will examine such arguments through formal or paper hearings. Rehearing Requests No rehearing requests were filed with respect to this matter. 4. Merger Policy In the Final Rule, the Commission explained that it had issued a Notice of Inquiry (NOI) on the Commission's merger policy in Docket No. RM96-6-000. 17/ The Commission indicated that it will review whether its criteria and policies for evaluating mergers need to be modified in light of the changing circumstances, including the Final Rule, that are occurring in the electric industry. The Commission concluded that it would review its merger policy in the ongoing NOI proceeding. 18/ Rehearing Requests No rehearing requests were filed with respect to this matter. The Final Rule contained a typographical error in which the word "not" was erroneously omitted. FERC Stats. & Regs.  35,531 (1996). FERC Stats. & Regs. at 31,661; mimeo at 77-78. Docket Nos. RM95-8-001 -49- and RM94-7-002 Commission Conclusion We note that on December 18, 1996, the Commission issued, in the NOI proceeding, a Policy Statement that updates and clarifies the Commission's procedures, criteria and policies concerning public utility mergers. 19/ 5. Contract Reform Requirements and Transmission Contracts In the Final Rule, the Commission concluded that it was not appropriate to order generic abrogation of existing requirements and transmission contracts, but concluded nonetheless that the modification of certain requirements contracts (those executed on or before July 11, 1994) on a case-by-case basis may be appropriate. 20/ The Commission further concluded that, even if customers under such requirements contracts are bound by so- called Mobile-Sierra clauses, they ought to have the opportunity to demonstrate that their contracts no longer are just and reasonable. The Commission found that it would be against the public interest to permit a Mobile-Sierra clause in an existing wholesale requirements contract 21/ to preclude the parties to Order No. 592, Policy Statement Establishing Factors the Commission will Consider in Evaluating Whether a Proposed Merger is Consistent with the Public Interest, 77 FERC  61,263 (1996). FERC Stats. & Regs. at 31,663-66; mimeo at 84-92. The Commission defined these as contracts executed on or before July 11, 1994. Docket Nos. RM95-8-001 -50- and RM94-7-002 such a contract from the opportunity to realize the benefits of the competitive wholesale power markets. Thus, it explained, a party to a requirements contract containing a Mobile-Sierra clause no longer will have the burden of establishing independently that it is in the public interest to permit the modification of such contract. The party, however, still will have the burden of establishing that such contract no longer is just and reasonable and therefore ought to be modified. The Commission explained that this finding complements the Commission's finding that, notwithstanding a Mobile-Sierra clause in an existing requirements contract, it is in the public interest to permit amendments to add stranded cost provisions to such contracts if the public utility proposing the amendment can meet the evidentiary requirements of the Final Rule. Accordingly, the Commission required that any contract modification approved under this Section must provide for the utility's recovery of any costs stranded consistent with the contract modification. Further, the Commission concluded that if a customer is permitted to argue for modification of existing contracts that are less favorable to it than other generation alternatives, then the utility should be able to seek modification of contracts that may be beneficial to the customer. Coordination Agreements The Commission concluded that to assure that non- discriminatory open access becomes a reality in the relatively near future, it was necessary to modify existing economy energy Docket Nos. RM95-8-001 -51- and RM94-7-002 coordination agreements. The Commission stated that it would condition future sales and purchase transactions under existing economy energy coordination agreements 22/ to require that the transmission service associated with those transactions be provided pursuant to the Final Rule's requirements of non- discriminatory open access, no later than December 31, 1996. The Commission also required that, for new economy energy coordination agreements 23/ where the transmission owner uses its transmission system to make economy energy sales or purchases, the transmission owner must take such service under its own transmission tariff as of the date trading begins under the agreement. 24/ Finally, the Commission concluded that it would not require the modification of non-economy energy coordination agreements. However, the Commission noted that this does not insulate such agreements from complaints that transmission service provided under such agreements should be provided pursuant to the Final Rule pro forma tariff. The Commission defined "existing" as those agreements executed prior to 60 days after publication of the Final Rule in the Federal Register. The Commission defined "new" as those agreements executed 60 days after publication of the Final Rule in the Federal Register. Accordingly, the Commission explained, transmission service needed for sales or purchases under all new economy energy coordination agreements will be pursuant to the Final Rule pro forma tariff. Docket Nos. RM95-8-001 -52- and RM94-7-002 Rehearing Requests Various utilities oppose the Commission's finding that it is in the public interest to permit the modification of existing requirements contracts that contain Mobile-Sierra clauses. On the other hand, a number of customers assert that the Commission did not go far enough and seek enhanced contract reformation rights. Utilities Against Contract Reformation Several utilities argue that the Commission's finding is not supported by substantial evidence. 25/ Utilities For Improved Transition asserts that the Commission cannot rely on economic theory as a substitute for substantial evidence. 26/ It argues that the record in this proceeding demonstrates that the marketplace is becoming increasingly competitive without mandatory tariffs, which is evidence of market health, not market problems. It further argues that even if undue discrimination is proven, the remedy is not needed because the record shows that existing programs are meeting the industry's needs. Southwestern argues that the Commission has improperly chosen to ignore the public interest standard and has failed to make the contract specific analysis here that it performed in Northeast Utils. Serv. Co., 66 FERC  61,332 (1994), aff'd, 55 Utilities For Improved Transition, Union Electric, PSE&G, Carolina P&L. Union Electric adds that there is no evidence that any existing economy energy coordination agreements are unduly discriminatory and require modification. Docket Nos. RM95-8-001 -53- and RM94-7-002 F.3d 686 (1st Cir. 1995). PSE&G and Carolina P&L also argue that the Commission failed to demonstrate the "unequivocal public necessity" for generically abrogating the Mobile-Sierra clauses and assert that the Commission has presented no evidence as to how the public interest will be served by abrogating these contracts. PSE&G and Carolina P&L further argue that the Commission cannot avoid making a public interest determination "by the simple expedient of asserting that the public interest requires it to ignore the Mobile-Sierra clauses that required that public-interest determination in the first place." 27/ Union Electric and PSE&G argue that the Commission, in justifying its public interest finding, inappropriately focused on the interests of the parties to the contract instead of on whether non-parties will be adversely affected by the existing contracts. Public Service Co of CO asserts that the Commission should clarify the definition of requirements contract to include long- term block purchases of electricity. It states that it purchases a large percentage of its system requirements under long-term block purchase agreements, and that under the Commission's abrogation policy in Order No. 888, its ability to abrogate these supply arrangements would be treated differently because its contracts do not meet the definition of a "wholesale requirements contract," as defined in new section 35.26(b)(1) of the PSE&G at 6. Docket Nos. RM95-8-001 -54- and RM94-7-002 Commission's Regulations. Public Service Co of CO further asserts that the Commission has not adequately explained why it is appropriate or in the public interest to allow partial requirements customers to abrogate their contracts, but not similarly to allow a public utility to abrogate its supply arrangements. 28/ PSE&G and Carolina argue that the availability of stranded cost recovery cannot support allowing customers to modify rates under Mobile-Sierra clauses that required that public-interest determination in the first place. PSE&G and Carolina P&L also argue that no Mobile-Sierra contracts entered into after October 24, 1992 (the date EPAct became law) should be subject to the Rule because since that date customers have been able to apply for an order under section 211 to have power transmitted to them from suppliers other than the utility to whom they are interconnected. PSE&G requests that the Commission clarify that the just and reasonable standard used in considering a contract abrogation claim will be limited to a determination of whether the rate is just and reasonable within the cost-based zone of reasonableness of the selling public utility. Such an analysis, PSE&G asserts, should not include a comparison to what other utilities offer to their customers. 29/ See also PSE&G. See also Carolina P&L. Docket Nos. RM95-8-001 -55- and RM94-7-002 Customers Seek Enhanced Contract Reformation Rights TAPS argues that the Commission should apply a just and reasonable standard to requests by all "victims" of undue discrimination to seek modifications of requirements or transmission contracts, whether they are subject to Mobile-Sierra or not. On the other hand, TAPS asserts that utilities should be bound to the bargain they extracted from transmission customers. Wisconsin Municipals request that the Commission clarify that parties may seek mandatory abrogation of preexisting transmission contracts or provisions and that the Commission will apply a rebuttable presumption that terms and conditions inferior to the pro forma tariff are unjust and unreasonable on their face. CCEM argues that requirements customers should receive blanket conversion rights. At a minimum, CCEM asserts, if a customer seeks conversion, the burden of proof in the proceeding should shift to the utility. CCEM also emphasizes that the question remains why conversion was deemed essential in natural gas markets, but not in the transition to competition in the electric industry. Blue Ridge argues: In neither the power supply nor transmission access case should a provider be allowed to modify existing power supply contracts under any but the Mobile Sierra public interest burden of proof. In both the power supply or transmission access cases, the Commission Docket Nos. RM95-8-001 -56- and RM94-7-002 should articulate the suggested standards for what constitutes a prima facia case. [30/] Commission Conclusion Before responding to the rehearing arguments raised, we wish to clarify our Mobile-Sierra findings. We explained in Order No. 888 that we were making two complementary public interest findings. First, as discussed further in Section IV.J, we found that it is in the public interest to permit public utilities to seek stranded cost amendments to existing requirements contracts with Mobile-Sierra clauses. Second, we found that a "party" to a requirements contract containing a Mobile-Sierra clause no longer will have the burden of establishing independently that it is in the public interest to permit the modification of such contract, but still will have the burden of establishing that such contract no longer is just and reasonable and therefore ought to be modified. We clarify that, in making this second finding, our reference to a "party" to a requirements contract containing a Mobile-Sierra clause was directed at modification of contract provisions by customers. 31/ Additionally, it applies to any Blue Ridge at 16. We note that the fact that a contract may bind a utility to a Mobile-Sierra public interest standard does not necessarily mean that the customer is also bound to that standard. Unless a customer specifically waives its section 206 just and reasonable rights, the Commission construes the issue in favor of the customer. See Papago Tribal Utility Authority v. FERC, 723 F.2d 950, 954 (D.C. Cir. 1983). Docket Nos. RM95-8-001 -57- and RM94-7-002 contract revisions sought, whether or not they relate to stranded costs. 32/ In response to the Mobile-Sierra rehearing arguments described above, as well as the Mobile-Sierra arguments described in Section IV.J concerning our determinations regarding stranded cost amendments to contracts, the Commission believes it is important to first address the general context in which our Mobile-Sierra determinations have been made. In Order No. 888, the Commission removed the single largest barrier to the development of competitive wholesale power markets by requiring non-discriminatory open access transmission as a remedy for undue discrimination. This action carries with it the regulatory public interest responsibility to address the difficult transition issues that arise in moving from a monopoly, cost- based electric utility industry to an industry that is driven by competition among wholesale power suppliers and increasing reliance on market-based generation rates. There are two predominant, overlapping transition issues that arise as a result of our actions in this rulemaking: first, how to deal with the uneconomic sunk costs incurred, and second, how to deal with the contracts that were entered into, under an In situations in which a customer institutes a section 206 proceeding to modify a contract that binds the utility to a Mobile-Sierra public interest standard, the utility may make whatever arguments it wants regarding any of the contract terms, including those unrelated to stranded costs, but will be bound to a Mobile-Sierra public interest standard for contract terms that do not relate to stranded costs. Docket Nos. RM95-8-001 -58- and RM94-7-002 industry regime that rested on a regulatory framework and set of expectations that are being fundamentally altered. To address these issues, the Commission has balanced a number of important interests in order to achieve what it believes will be a fair and orderly transition to competitive markets. These interests include the financial stability of the electric utility industry and permitting customers to obtain the benefits of competitive markets without undue disruption or unfairness to other customers or industry participants. As the above rehearing arguments demonstrate, there is no consensus on how the Commission should manage the transition. In fact, parties offer diverse and conflicting views as to what the Commission should do regarding existing contracts. Some would have us let all contracts run their course with no opportunity for customers to modify or terminate their contracts, no matter how long the contracts or how onerous their terms. Others advocate automatic generic abrogation of all contracts. Yet others want a guaranteed automatic right to renew a contract if it happens to contain favorable rates and terms. 33/ Rather than adopting one extreme position or the other, the Commission has taken a measured approach with regard to contract modification, including modification of contracts that contain Mobile-Sierra clauses. Our goal is to balance the desire to honor existing contractual arrangements with the need to provide Similarly, as discussed in Section IV.J, parties have taken extreme positions as to stranded cost recovery. Docket Nos. RM95-8-001 -59- and RM94-7-002 some means to accelerate the opportunity of parties to participate in competitive markets. To accomplish this balance, the Commission, first, has made Mobile-Sierra public interest findings (discussed further below) only as to a limited set of contracts: those wholesale requirements contracts executed on or before July 11, 1994, which is the date of our first stranded cost proposed rulemaking and which served to put the industry and customers on notice that future contracts should explicitly address the rights, obligations and expectations of parties, including stranded cost obligations. 34/ Second, with regard to contract modifications sought by utilities, as discussed in more detail in Section IV.J, utilities that seek to add stranded cost provisions have a high evidentiary burden to meet before they can add contract provisions that permit stranded cost recovery beyond the end of their contract terms; the burden is particularly high in the case of contracts with notice provisions. With regard to modifications of contract provisions that do not relate to stranded costs, a utility with a As to existing economy energy coordination agreements, the Commission concludes that the evidence also supports its decision to condition future sales and purchase transactions that may occur under the ongoing umbrella coordination agreements. Specifically, we are requiring that the transmission service associated with these future transactions be provided pursuant to the Final Rule pro forma tariff. See Public Service Electric & Gas Company, 78 FERC  61,119, slip op. at 4 and n.7 (1997). Docket Nos. RM95-8-001 -60- and RM94-7-002 Mobile-Sierra contract clause will have the burden of showing that the provisions are contrary to the public interest. 35/ Third, with regard to contract modifications sought by customers, a customer will have to show that the provisions it seeks to modify are no longer just and reasonable. 36/ If a customer seeks to shorten or eliminate the term of an existing contract, any contract modification approved by the Commission will take into account the issue of appropriate stranded cost recovery by the customer's supplying utility. In permitting customers the opportunity to seek these types of modifications, even for contracts that contain Mobile-Sierra clauses, the Commission has based its public interest findings on the unprecedented industry changes facing utilities and their customers. While, as we stated in the Final Rule, there is no market failure in the electric industry that would justify As discussed below, pre-July 11, 1994 contracts were entered into during an era in which transmission providers exerted monopoly control over access to their transmission facilities. The unequal bargaining power between utilities and captive customers is the basis for our determination that utilities that have pre-July 11 Mobile-Sierra requirements contracts will have to satisfy the public interest standard in order to effectuate any non-stranded cost change to the contract, but that customers to such contracts will be able to effectuate any change by satisfying a just and reasonable standard. We will not grant the request by PSE&G and Carolina P&L that the just and reasonable standard will be limited to a determination of whether the rate is just and reasonable within the cost-based zone of reasonableness of the selling utility and should not include a comparison to what other utilities offer their customers. Because stranded costs will be taken into account when customers seek contract termination or modification, it would not be appropriate to limit customers in the evidence they may present. Docket Nos. RM95-8-001 -61- and RM94-7-002 generic abrogation of existing contracts, nevertheless the industry is in the midst of fundamental change. We cannot conclude that it is in the public interest to require all customers to be held to requirements contracts that were executed under the prior industry regime, no matter what the circumstances of those contracts. In response to parties who challenge the Commission's finding that it would be against the public interest to deny customers an opportunity to seek modification of wholesale requirements contracts executed on or before July 11, 1994, 37/ these parties ignore the fact that these contracts were entered into during an era in which transmission providers exercised monopoly control over access to their transmission facilities. 38/ The majority of customers under these types of contracts were captive, i.e., they had no realistic choice but to purchase generation from their local utility because they had no transmission to reach another supplier. Many of these contracts We note that some of the very parties making this challenge either do not object to the Commission's Mobile-Sierra findings permitting utilities to add stranded cost amendments to their contracts, or ask the Commission to broaden even further the scope of extra-contractual stranded cost recovery under the rule. We also reject arguments that a remedy is not needed because existing programs, i.e., those prior to Order No. 888, are meeting the needs of the industry. This very rulemaking, with the substantial comments filed by entities pointing out the failures of the current system and the need for change, and the extensive restructurings and state-initiated open access programs occurring around the country, on their face, refute these arguments. Docket Nos. RM95-8-001 -62- and RM94-7-002 were the result of uneven bargaining power between customers and monopolist transmission providers. 39/ While monopolist transmission providers may not have exercised monopoly power in all situations, 40/ the unprecedented competitive changes that have occurred (and are continuing to occur) in the industry may render their contracts to be no longer in the public interest or just and reasonable. These changed circumstances, discussed at length in the Final Rule, and the further changes that will occur as a result of open access transmission, may affect whether such contracts continue to be just and reasonable or not unduly discriminatory both as to the direct customers of the contracts, as well as to indirect, third-party consumers as well. 41/ We therefore reject arguments that there is no "evidence" to support our finding that it is in the public interest to permit review of these contracts in light of the specific circumstances It is also clear from the number of entities filing comments on the NOPR and rehearing requests of the Final Rule that many entities believe that their contracts were the result of uneven bargaining power and that they should be provided the opportunity to seek to terminate their existing contracts. In an era that was not characterized by competition in the generation sector, the Commission's response was to ensure that the rates for such contracts were no higher than the seller's cost (including a reasonable return on equity). In this way, the Commission sought to limit the seller's ability to reap the benefits of the seller's monopoly position. See FPC v. Sierra Pacific Power Company, 350 U.S. 348, 355 (1956); Northeast Utilities Service Company, 66 FERC  61,332 (1994), aff'd, 55 F.3d 686, 691 (1st Cir. 1995); Mississippi Industries v. FERC, 808 F.2d 1525, 1553 (D.C. Cir. 1987). Docket Nos. RM95-8-001 -63- and RM94-7-002 surrounding the contracts and in light of dramatically changed industry circumstances. We emphasize, however, that our decision is to permit an opportunity for review and that we will require a case-by-case showing that any modifications should be permitted. 42/ As we explained in the Final Rule, this decision complements our decision that it is in the public interest to permit amendments to add stranded cost provisions to existing contracts if case-by-case evidentiary burdens are met. As we discuss further in our detailed stranded cost discussion in Section IV.J, we do not interpret the Mobile-Sierra public interest standard as practically insurmountable 43/ in the We will not exclude Mobile-Sierra contracts entered into after the effective date of EPAct, as argued by PSE&G and Carolina P&L. As we explained in the Final Rule, there are significant time delays associated with section 211 proceedings. Accordingly, the availability of a section 211 proceeding cannot substitute for readily available service under a filed non-discriminatory open access tariff. FERC Stats. & Regs. at 31,646; mimeo at 35. We do not believe that EPAct created the expectation of open access on such a broad scale that we can assume that parties no longer generally expected "business as usual" to continue, and we will not presume that the exercise of market power was not at work when Mobile-Sierra contracts were entered into after EPAct. We also note that these arguments are similar to those proffered by opponents of stranded cost recovery, who argue that after EPAct utilities had no reasonable expectation of continuing to serve customers beyond the terms of existing contracts. In this context as well, we will not presume that, after EPAct, utilities could have no reasonable expectation of continuing to serve a customer beyond the contract term. As the D.C. Circuit explained in Papago Tribal Utility Authority v. FERC, 723 F.2d 950 (D.C. Cir. 1983) (Papago), there are essentially three contractual arrangements for rate revision: (1) the parties agree that the utility may file new rates under section 205, subject to the just and (continued...) Docket Nos. RM95-8-001 -64- and RM94-7-002 extraordinary situation before us where historic statutory and regulatory changes have converged to fundamentally change the obligations of utilities and the markets in which both they and their customers will operate. The ability to meet our overarching public interest responsibilities and to protect consumers would be virtually precluded if we were to apply a practically insurmountable standard of review before taking into account these fundamental industry-wide changes. 44/ (...continued) reasonable standard of review; (2) the parties agree to eliminate the utility's right to file rates under section 205 and the Commission's right to change pre-existing rates under section 206's just and reasonable standard (leaving the Commission's indefeasible right to change pre-existing rates that are contrary to the public interest); and (3) the parties agree to eliminate the utility's right to file new rates under section 205, but leave unaffected the Commission's power to change pre-existing rates under section 206's just and reasonable standard of review. 723 F.2d at 953. The same contractual arrangements also would apply to non-rate terms and conditions. We here address those contractual arrangements that eliminate the rights of one or both parties to modify a contract under the just and reasonable standard. We note that the Commission always has the indefeasible right under section 206 to change rates, terms or conditions that are contrary to the public interest. 723 F.2d at 953-55; see also Florida Power & Light Company, 67 FERC  61,141 at 61,398 (1994) appeal dismissed, No. 94-1483 (D.C. Cir. July 27, 1995) (unpublished); Southern Company Services, Inc., 67 FERC  61,080 at 61,227-28 (1994); Mississippi Industries v. FERC, 808 F.2d 1525, 1552 n.112. We reject the arguments of PSE&G and Carolina P&L that we have failed to demonstrate the "unequivocal public necessity" for generically "abrogating" Mobile-Sierra clauses and that we have presented no evidence as to how the public interest will be served by abrogating these contracts. We have concluded that there is a public necessity to permit the opportunity to seek contract changes in light of fundamental industry changes. However, we have not (continued...) Docket Nos. RM95-8-001 -65- and RM94-7-002 With respect to Public Service Co of CO's argument, we disagree that the definition of a wholesale requirements contract should be modified to include a long-term block purchase of electricity. In the majority of circumstances, such long-term supply contracts are voluntary arrangements in which neither party had market power. It would be inappropriate to make generic Mobile-Sierra findings as to these types of contracts. Parties can avail themselves of the section 205 and 206 procedures already available to them if they want to seek modification of such contracts. Finally, we reject CCEM's argument that all customers should receive automatic conversion rights because customers were provided such a right in the restructuring of the natural gas industry. We have taken, as is within our discretion, a substantially different approach here from that taken when we restructured the natural gas industry. As we stated in the Final Rule, and as alluded to above, at the time the Commission addressed this situation in the natural gas industry it was faced with shrinking natural gas markets, statutory escalations in natural gas ceiling prices under the Natural Gas Policy Act, and increased production of gas. 45/ Moreover, the natural gas industry was plagued with escalating take-or-pay liabilities. There was a market failure in the natural gas industry that (...continued) abrogated any contracts by this Rule. FERC Stats. & Regs. at 31,664; mimeo at 84. Docket Nos. RM95-8-001 -66- and RM94-7-002 required the extraordinary measure of generically allowing all customers to break their contracts with pipelines. In contrast, market circumstances in the electric industry today do not compel generic abrogation of contracts. The more moderate approach we have taken will permit us to take into account the fundamental industry changes that have occurred (and will continue to occur), to balance the interests of all affected parties, and to help avoid drastic shocks to industry participants. Right of First Refusal In the Final Rule, the Commission concluded that all firm transmission customers (requirements and transmission-only), upon the expiration of their contracts or at the time their contracts become subject to renewal or rollover, should have the right to continue to take transmission service from their existing transmission provider. 46/ If not enough capacity is available to meet all requests for service, the right of first refusal gives the existing customer who had contractually been using the capacity on a long-term, firm basis the option of keeping the capacity. However, the limitations imposed by the Commission are that the underlying contract must have been for a term of one- year or more and the existing customer must agree to match the rate offered by another potential customer, up to the transmission provider's maximum filed transmission rate at that time, and to accept a contract term at least as long as that FERC Stats. & Regs. at 31,665; mimeo at 88. Docket Nos. RM95-8-001 -67- and RM94-7-002 offered by the potential customer. 47/ Moreover, the Commission indicated that this right of first refusal is an ongoing right that may be exercised at the end of all firm contract terms (including all future unbundled transmission contracts). Requests for Rehearing On rehearing, most petitioners agree with or do not contest the notion of providing existing transmission customers with a right of first refusal, but many have requested modification or clarification of the Commission-imposed limitations on such a right. A variety of transmission customers assert that the Commission's right of first refusal provision fails to adequately protect existing transmission customers' rights to continued service and seek changes to the Commission's provision. On the other hand, a number of utilities believe that the Commission should provide additional restrictions on the right of first refusal. The Commission explained that this right of first refusal exists whether or not the customer buys power from the historical utility supplier or another power supplier. If the customer chooses a new power supplier and this substantially changes the location or direction of its power flows, the customer's right to continue taking transmission service from its existing transmission provider may be affected by transmission constraints associated with the change. Docket Nos. RM95-8-001 -68- and RM94-7-002 Customers' Positions APPA argues that (1) existing customers should only have to agree to service that matches the term of any power supply contract for which it will use the transmission arrangement or, in the absence of a generation contract, one year, and (2) the pricing provision should be changed to reflect the current just and reasonable rate, as approved by the Commission, for similar transmission service. NRECA also argues that the term and pricing provisions of section 2.2 need to be changed. With respect to the term of the contract the customer should be required to match, NRECA asserts that it should be one year, which corresponds to the definition of long-term firm service in the tariff. With respect to the rate, NRECA requests that the Commission cap the obligation to match the price offered by another customer at the maximum transmission rate the incumbent customer is obligated to pay to the transmission provider at the close of the prior contract term. TDU Systems argue that the right of first refusal provision fails to take into consideration amounts that TDUs have contributed to the development of the transmission systems through prior transmission rates. TDU Systems are concerned about the possibility of an increase in the price of transmission capped only by the cost of increasing the capacity of the provider's transmission system. Docket Nos. RM95-8-001 -69- and RM94-7-002 TAPS requests that the Commission clarify that the transmission provider may only charge its then effective rates for existing, non-constrained transmission capacity because to allow opportunity or expansion costs would perpetually put the existing transmission customers on the margin at the end of their contract terms subjecting them to higher rates than the transmission provider. 48/ Blue Ridge raises a possible discrepancy between the language in the tariff and the language in the preamble. It asserts that section 2.2 "requires the existing customer to 'pay the current just and reasonable rate, as approved by the Commission,' while the Regulatory Preamble requires the customer to 'match the rate offered by another potential customer, up to the transmission provider's maximum filed transmission rate at that time.' Order No. 888, mimeo at 88." Tallahassee asks the Commission to clarify that the right of first refusal to presently bundled transmission capacity accrues to the power customer paying the bundled rate and not to the intermediary acting on behalf of the customer. AEC & SMEPA maintain that the price and term limitations of section 2.2 would place TDUs at a competitive disadvantage vis-a- vis the transmission provider by subjecting TDUs to incremental costs, including the costs of system upgrades, if other new customers are vying to use the transmission system. They state See also AEC & SMEPA. Docket Nos. RM95-8-001 -70- and RM94-7-002 that the Commission must provide existing transmission customers the same rights as the transmission provider's other native load customers. Utilities' Positions PSNM argues that imposing a right of first refusal is inconsistent with the Commission's finding that contracts should not be abrogated. In effect, it argues that imposition of the right of first refusal abrogates existing contracts executed with the expectation that capacity could be recalled for the utility's own use upon expiration of the contracts. PSNM explains that it has a constrained transmission system and has been balancing specific contract durations against projected future native loads so that required capacity may be made available for use by third parties in the short-term, but not be committed to those parties at the time it is needed to be recalled. Moreover, PSNM asserts that Order No. 888 is not supported by the right of first refusal process of Order No. 636 because the Commission does not have abandonment authority under the FPA and its authority to require continuation of service is not well-defined and is controversial. 49/ Utilities For Improved Transition and Florida Power Corp All transmission contracts with public utility transmitters can only be terminated by a filing with the Commission under FPA section 205. Thus, the Commission has interpreted its section 205 authority as permitting it to suspend termination of service for 5 months beyond the expiration of a contract's term if such action is necessary to protect ratepayers. See, e.g., Kentucky Utilities Company, 67 FERC  61,189 at 61,573 (1994). (While the termination procedures for power sales contracts executed after July 9, (continued...) Docket Nos. RM95-8-001 -71- and RM94-7-002 argue that section 2.2 of the pro forma tariff should be modified by "restricting rollover rights to the same points of receipt and delivery as the terminating service and by providing the customer notice of a competing application and 90 days in which to file its own application for service for a term at least as long as the competing application." (Florida Power Corp at 11-13; Utilities For Improved Transition at 50-53). Similarly, EEI argues that to obtain a priority for continuation of service, customers must be seeking service that is substantially similar to or a continuation of the service they already receive and must be subject to a time limit on the reservation priority. CSW Operating Companies assert that it is unclear how the right of first refusal provision will be implemented. State Commission Position VT DPS states that the right of first refusal provision offers inadequate protection: "While it is true that the existing customer could secure a five year transmission arrangement under a new contract, its right to continuous service is placed in jeopardy if it does not match the six year offer of the competing bidder." VT DPS argues that the Commission's bare bones provision opens the opportunity for competitive mischief by the transmission provider. VT DPS proposes that "the existing customer should be able to renew its contract by matching the (...continued) 1996 were modified in Order No. 888, there were no changes regarding termination procedures for transmission contracts.). Docket Nos. RM95-8-001 -72- and RM94-7-002 highest transmission price offered in the marketplace (up to the tariff maximum rate) and by offering to extend its contract for seven years or the prevailing length of firm transmission contracts in the marketplace, whichever is shorter." (VT DPS at 17-21). Commission Conclusion In this order, the Commission reaffirms its decision to give a reservation priority to existing and future firm transmission customers served under a contract of one year or more, and also addresses petitioner arguments regarding the Commission-imposed limitations associated with the exercise of that priority. Rationale Our policy rationale for giving an existing firm transmission customer (requirements and transmission-only), 50/ served under a contract of one year or more, a reservation priority (right of first refusal) when its contract expires is that it provides a mechanism for allocating transmission capacity when there is insufficient capacity to accommodate all requestors. If there are capacity limitations and both customers (existing and potential) are willing to pay for firm transmission service of the same duration, the right of first refusal provides a tie-breaking mechanism that gives priority to existing We clarify that we did not intend the term "all firm transmission customers" to include only requirements and transmission-only customers, but intended that it include all bundled firm customers as well. Docket Nos. RM95-8-001 -73- and RM94-7-002 customers so that they may continue to receive transmission service. 51/ Contract Term Limitation We reject arguments to modify the requirement in section 2.2 that existing long-term firm transmission customers seeking to exercise their right of first refusal must agree to a contract term at least as long as that sought by a potential customer. The objective of a right of first refusal is to allow an existing firm transmission customer to continue to receive transmission service under terms that are just, reasonable, not unduly discriminatory, or preferential. Absent the requirement that the customer match the contract term of a competing request, utilities could be forced to enter into shorter-term arrangements that could be detrimental from both an operational standpoint (system planning) and a financial standpoint. Rate Limitation We also reject the proposition that either existing wholesale customers or transmission providers providing service to retail native load customers should be insulated from the possibility of having to pay an increased rate for transmission in the future. The fact that existing customers historically have been served under a particular rate design does not serve to We reject Tallahassee's argument that the right of first refusal should accrue to the power customer paying the bundled rate and not to any intermediary acting on its behalf. Our right of first refusal mechanism is simply a tie-breaker that gives priority to existing firm transmission customers. Docket Nos. RM95-8-001 -74- and RM94-7-002 "grandfather" that rate methodology in perpetuity. Because the purpose of the right of first refusal provision is to be a tie- breaker, the competing requests should be substantially the same in all respects. 52/ In response to Blue Ridge's concern regarding a discrepancy between the language in section 2.2 of the tariff and the preamble, we clarify that existing customers who exercise their right of first refusal will be required to pay the just and reasonable rate, as approved by the Commission at the time that their contract ends. 53/ Mechanics of the Right of First Refusal Process CSW Operating Companies asked the Commission to clarify the mechanics of exercising the right of first refusal. We have determined not to specify in this order the mechanics by which the right of first refusal mechanism will be exercised for existing firm transmission arrangements. Instead, we intend to address such issues on a case-by-case basis, if and when a The proposal to restrict the right of first refusal provision to exactly the same points of receipt and delivery as the terminating service would competitively disadvantage existing customers seeking new sources of generation. However, as we stated in Order No. 888, if the customer chooses a new power supplier and this substantially changes the location or direction of the power flows it imposes on the transmission provider's system, the customer's right to continue taking transmission service from its existing transmission provider may be affected by transmission constraints associated with the change. FERC Stats. & Regs. at 31,666 n.176; mimeo at 89 n.176. As Order No. 888 indicates, they may be required to pay the transmission provider's maximum transmission rate. Docket Nos. RM95-8-001 -75- and RM94-7-002 dispute arises. However, we encourage utilities and their customers to include specific procedures for exercising the right of first refusal in future transmission service agreements executed under the pro forma tariff. And of course, utilities are free to make section 205 filings to propose additions to the pro forma tariff to generically specify procedures for dealing with the issues. Existing Contracts By providing existing customers a right of first refusal, we are not, as PSNM claims, abrogating contracts. Moreover, PSNM's concern that the right of first refusal will prohibit utilities from "recalling" existing capacity to meet native load growth that was anticipated at the time existing third-party transmission contracts were executed can be addressed in the context of a specific filing by a utility demonstrating that it had no reasonable expectation of continuing to provide transmission service to the wholesale transmission customer at the end of its contract. For future transmission contracts, Order No. 888 permits utilities to reserve existing transmission capacity to serve the needs (current and reasonably forecasted) of its existing native load (retail) customers. Moreover, if a utility provides firm transmission service to a third party for a time until native load needs the capacity, it should specify in the contract that the right of first refusal does not apply to that firm service due to a reasonably forecasted need at the time the contract is executed. Docket Nos. RM95-8-001 -76- and RM94-7-002 Informational Filings With respect to all existing requirements contracts and tariffs that provide for bundled rates, the Commission, in the Final Rule, required all public utilities to make informational filings setting forth the unbundled power and transmission rates reflected in those contracts and tariffs. 54/ Requests for Rehearing Utilities For Improved Transition and VEPCO ask the Commission to clarify whether the unbundled transmission rate should be the current transmission tariff rate (bundled rate likely not to include the current price for transmission service) or an approximation of the rate at the time the contract was executed (may be impossible to determine). Commission Conclusion We previously addressed the determination of the unbundled transmission rate in informational filings in an order issued October 16, 1996. 55/ In that order, we noted that Order No. 888 does not prescribe any specific method for calculating separately-stated transmission and generation rates and public utilities have used different methods in their informational filings. Because of the general lack of controversy over the informational filings and the fact that they are for informational purposes as a benefit to existing customers, the FERC Stats. & Regs. at 31,665-66; mimeo at 89-90. 77 FERC  61,025. Docket Nos. RM95-8-001 -77- and RM94-7-002 Commission accepted the vast majority of the informational filings. The Commission added, however, that it did not consider the informational rates binding for any future transactions. Accordingly, we need not now prescribe a specific method to calculate the unbundled transmission rate included in informational filings. Existing Contracts In the Final Rule, the Commission explained that because it was not abrogating existing requirements and transmission contracts generically and because the functional unbundling requirement applies only to new wholesale services, the terms and conditions of the Final Rule pro forma tariff do not apply to service under existing requirements contracts. 56/ Rehearing Requests San Francisco asks that the Commission clarify that nothing in Order No. 888 is intended to affect prices, or price-setting methodologies, in existing contracts. Commission Conclusion By order issued July 2, 1996, we clarified that the filing of an open access compliance tariff on or before July 9, 1996 does not supersede an existing transmission agreement that has been accepted by the Commission unless specifically permitted in the agreement on file. If a utility seeks to modify or terminate an existing transmission agreement, it must separately file to modify or terminate such contracts under appropriate procedures under section 205 or 206 of the FERC Stats. & Regs. at 31,665; mimeo at 87-88. Docket Nos. RM95-8-001 -78- and RM94-7-002 Federal Power Act, consistent with the terms of its contract. [57/] Thus, nothing in Order No. 888 affects prices or price-setting methodologies in existing contracts, unless specifically permitted in the contract on file. 6. Flow-based Contracting and Pricing In Order No. 888, the Commission explained that it would not, at that time, require that flow-based pricing and contracting be used in the electric industry. 58/ It recognized that there may be difficulties in using a traditional contract path approach in a non-discriminatory open access transmission environment. At the same time, however, the Commission noted that contract path pricing and contracting is the longstanding approach used in the electric industry and it is the approach familiar to all participants in the industry. Thus, the Commission was concerned that to require a dramatic overhaul of the traditional approach -- such as a shift to some form of flow- based pricing and contracting -- could severely slow, if not derail for some time, the move to open access and more competitive wholesale bulk power markets. In addition, the Commission indicated its belief that it would be premature to impose generically a new pricing regime without the benefit of any experience with such pricing. Accordingly, the Commission welcomed new and innovative proposals, but determined not to 76 FERC  61,009 at 61,028 (1996). FERC Stats. & Regs. at 31,668; mimeo at 96-98. Docket Nos. RM95-8-001 -79- and RM94-7-002 impose some form of flow-based pricing or contracting in the Final Rule. Rehearing Requests American Forest & Paper argues that contract path pricing should be prohibited. American Forest & Paper asserts that QFs and other independents are being forced by contract path wheeling utilities to indemnify them from liability for third-party claims of inadvertent flow costs resulting from the transaction, while paying postage stamp rates for the entire amount of contracted transmission. American Forest & Paper supports an average postage stamp rate by region, with the utilities within the region agreeing on a way to divide up the rate appropriately. Commission Conclusion As the Commission explained in the Final Rule, we are concerned that a dramatic overhaul of the traditional contract path approach could slow or derail the move to open access and, in any event, is premature without the benefit of any experience with alternative pricing regimes. The Commission, however, welcomes new and innovative proposals from the industry. American Forest & Paper has not presented a case-specific proposal of any detail that would provide the Commission and interested parties the opportunity to test the appropriateness of a change from the contract path approach. Until the Commission has such an opportunity, we are not prepared to change generically the traditional contract path approach with which the electric industry is so familiar. Docket Nos. RM95-8-001 -80- and RM94-7-002 Moreover, American Forest & Paper's proposal to prohibit contract path pricing and mandate regional postage-stamp rates would be inconsistent with the rate flexibility that the Commission provided in the Transmission Pricing Policy Statement and embraced in the Final Rule. B. Legal Authority In the Final Rule, the Commission responded to commenters challenging the Commission's authority to require open access and reaffirmed its conclusion in the NOPR that it has the authority under the FPA to order wholesale transmission services in interstate commerce to remedy undue discrimination by public utilities. 59/ Rehearing Requests Authority to Order Open Access Tariffs Union Electric challenges the Commission's authority to require wheeling based on arguments that: (1) the Rule overlooks the fact that the AGD case 60/ pertained to voluntary actions by the pipelines and the Commission's imposition of open access requirements as a condition on permitting the desired authorizations; (2) the Commission incorrectly treats the Otter Tail case; 61/ (3) the legislative histories of the NGA and FPA FERC Stats. & Regs. at 31,668-79 and 31,686-87; mimeo at 98- 129 and 148-51. Associated Gas Distributors v. FERC, 824 F.2d 981, 998 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988) (AGD). Otter Tail Power Company v. FPC, 410 U.S. 366 (1974) (Otter (continued...) Docket Nos. RM95-8-001 -81- and RM94-7-002 are different and the legislative history of the FPA does not support the Commission's authority to order wheeling; (4) the Commission made prior contrary statements to the U.S. Supreme Court [in its opposition to the grant of certiorari to review the AGD decision] about the nature of Commission authority to order open access and judicial construction of that authority in AGD and Otter Tail;" (5) as a matter of statutory construction, the Commission cannot rely on sections 205 and 206, which are silent as to wheeling, when sections 211 and 212 contain express wheeling provisions; (6) the four relevant cases recognized by the Commission indicate that the Commission may not directly or indirectly order a public utility to wheel or transmit energy for another entity under sections 205 and 206, notwithstanding the Commission's circumscribed ability to order wheeling under sections 211 and 212; (7) prior to the issuance of the Final Rule the Commission, with a full appreciation of the legislative history behind Part II, consistently held that it lacks the authority to order wheeling under FPA Part II; (8) the Rule fails to assign "considerable importance" to the Commission's "longstanding interpretation of the statute in accordance with its literal language;" and (9) in legislative hearings preceding enactment of EPAct, the Office of the General Counsel acknowledged the limitations on the Commission's wheeling power. (...continued) Tail). Docket Nos. RM95-8-001 -82- and RM94-7-002 Carolina P&L also challenges the Commission's authority to order open access tariffs, arguing that: (1) Otter Tail specifically states: "So far as wheeling is concerned, there is no authority granted the commission under Part II of the Federal Power Act to order it, . . ."; (2) the Richmond and FPL cases 62/ prohibit the Commission from doing indirectly what it cannot do directly; (3) the AGD case does not support the Commission's authority to order open access through the filing of generic tariffs -- in AGD the Commission's authority was based on voluntary actions by the affected pipelines and there are substantial differences between the NGA and the FPA; (4) the legislative history of EPAct indicates that the Commission does not have the authority to mandate open access and can only order open access if section 211 procedures are followed -- citing NYSEG and FPL; and (5) section 211 limits the Commission's authority to order open access on a generic basis -- where a specific statute addresses an issue, a more general statute should not be read in a manner that conflicts with the specific statute. PA Com argues that the Commission's reliance on AGD "impermissibly expands the limited holding of AGD" and the Commission improperly relied on sections 205 and 206 of the FPA Richmond Power & Light Company v. FERC, 574 F.2d 610 (D.C. Cir. 1978) (Richmond) and Florida Power & Light Company v. FERC, 660 F.2d 668 (5th Cir. 1981), cert. denied sub nom. Fort Pierce Utilities Authority v. FERC, 459 U.S. 1156 (1983) (FPL). Docket Nos. RM95-8-001 -83- and RM94-7-002 to require open access generically -- the Commission only has case-by-case jurisdiction. VA Com declares that the plain meaning of the FPA and cases interpreting sections 206 and 211 show that the Commission does not have the authority to order industry-wide open access. FL Com and El Paso argue that the Commission only has limited authority to order wheeling and that the Commission has not made the required findings under section 211. 63/ Group Two Section 205 Filings Union Electric argues that the requirement that Group 2 Public Utilities make section 205 filings is contrary to the voluntary filing scheme inherent in section 205. Commission Conclusion Overview The fundamental legal question before us is the scope of the authority granted to the Commission in 1935 to remedy undue discrimination in interstate transmission services and whether that authority permits us sufficient flexibility to define undue discrimination in light of dramatically changed industry circumstances, in order to provide electricity customers the benefits of more competitively priced power. In the NOPR and We note that Indianapolis P&L also has made legal arguments regarding our authority to order wheeling under Order No. 888. However, it did so in a request for rehearing of a denial of its request for waiver of the Order No. 888 requirements, not in its request for rehearing of Order No. 888. Accordingly, we will address its arguments when we act on its request for rehearing of its waiver denial. Docket Nos. RM95-8-001 -84- and RM94-7-002 Order No. 888, the Commission comprehensively examined case law and legislative history relevant to our authority to order open access transmission services as a remedy for undue discrimination. 64/ We also responded at length in Order No. 888 to arguments that questioned our authority to take this step. 65/ On rehearing, as described above, only a few parties continue to question the Commission's authority. As a general matter their rehearings do not raise any arguments, cases, or legislative history not previously considered, and they do not convince us that our action in Order No. 888 is not within our authority under sections 205 and 206 of the FPA. We therefore reaffirm our determination that we have not only the legal authority, but the responsibility, to order the filing of non- discriminatory open access tariffs if we find such order necessary to remedy undue discrimination or anticompetitive effects. There are several broad points we wish to emphasize in response to the rehearings that have been filed: First, there is no dispute that the FPA does not explicitly give this Commission authority to order, sua sponte, open access transmission services by public utilities. However, the fact remains that the FPA does explicitly require this Commission to FERC Stats. & Regs. at 31,668-73; mimeo at 98-112. Notice of Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking, FERC Stats. & Regs.  32,514 at 33,053-56 (1995). FERC Stats. & Regs. at 31,673-79; mimeo at 112-129. Docket Nos. RM95-8-001 -85- and RM94-7-002 remedy undue discrimination by public utilities. 66/ The finding of the D.C. Circuit in the AGD case, with regard to sections 4 and 5 of the NGA (which parallel sections 205 and 206 of the FPA), are equally applicable here: the Act "fairly bristles" with concerns regarding undue discrimination and it would turn statutory construction on its head to let the failure to grant a general power prevail over the affirmative grant of a specific one. 67/ Second, there also is no dispute that before Congress enacted the FPA in 1935, it rejected provisions that would have explicitly granted the Commission authority to order transmission to any person if the Commission found it "necessary or desirable in the public interest." However, the fact that Congress rejected an extremely broad common carrier provision does not limit the remedies available to the Commission to enforce the undue discrimination provisions in the FPA. 68/ Third, entities on rehearing understandably have focused on statements in case law that indicate limits on the Commission's wheeling authority. They particularly focus on certain statements by the Supreme Court in Otter Tail. The Commission in Order No. 888 fully addressed and considered all relevant case law of which we are aware, including statements in Otter Tail and See FERC Stats. & Regs. at 31,669-70; mimeo at 101-03. 824 F.2d at 998. See FERC Stats. & Regs. at 31,676-78; mimeo at 120-27. Docket Nos. RM95-8-001 -86- and RM94-7-002 other court cases indicating limitations on our authority. 69/ We do not dispute these statements and we recognize limitations on our authorities. However, the fact remains that none of the cases cited, including Otter Tail, involved the issue of whether this Commission can order transmission as a remedy for undue discrimination and none addressed industry-wide circumstances such as those before us in Order No. 888. Fourth, while Congress in 1978 gave the Commission certain case-by-case authority to order transmission access by both public utilities and non-public utilities, and broadened this case-by-case authority in 1992, Congress also specifically provided in section 212(e) of the FPA that the case-by-case authorities were not to be construed as limiting or impairing any authority of the Commission under any other provision of law. 70/ Indeed, the legislative history of EPAct shows that when Congress amended the section 211-212 wheeling provisions and the section 212(e) savings clause in 1992, 71/ it was well aware of arguments regarding the scope of the Commission's wheeling authority as a remedy for undue discrimination under section 206. Whereas See FERC Stats. & Regs. at 31,668-73; mimeo at 98-110. See FERC Stats. & Regs. at 31,686-87; mimeo at 148-49. The savings clause in section 212(e) originally provided that no provision of section 210 or 211 shall be treated as "limiting, impairing, or otherwise affecting any authority of the Commission under any other provision of law." In 1992, the 212(e) savings clause was amended to provide that sections 210, 211 and 214 "shall not be construed as limiting or impairing any authority of the Commission under any other provision of law." Docket Nos. RM95-8-001 -87- and RM94-7-002 Congress in 1992 decided to add a flat prohibition on the Commission ordering direct retail wheeling under any provision of the FPA, it did not add a prohibition on the Commission ordering wholesale wheeling to remedy undue discrimination under section 206. It instead retained and modified the savings clause. The issue before us, therefore, hinges on the scope of authority given to this Commission to remedy undue discrimination, not on the scope of authority given to us in 1978 and 1992. The Commission is significantly influenced by the decision and case law discussion by the D.C. Circuit in the AGD case. This court opinion contains the most recent and comprehensive discussion of the Commission's legal authority to remedy undue discrimination under NGA provisions that mirror those in the FPA, including the relevant case law concerning the Commission's authority to order transmission under the FPA. 72/ The rehearing arguments do not, and we believe cannot, reconcile the AGD court's discussion and findings with a conclusion that the Commission cannot under any circumstances (as these parties advocate) order wheeling under sections 205 and 206 to remedy undue discrimination. In sum, we believe that the essential question of the Commission's legal authority to impose the requirements of Order No. 888 turns on the flexibility of the Commission's remedial authority under sections 205 and 206 of the FPA to remedy undue AGD, 824 F.2d at 996-999. See also FERC Stats. & Regs. at 31,668-73, 31,676-78; mimeo at 98-110 and 120-27. Docket Nos. RM95-8-001 -88- and RM94-7-002 discrimination. As was true with respect to the natural gas industry, we acknowledge that Commission precedent for many years nurtured the expectation that we would not, under our authority under the FPA, preclude utilities from using their monopoly power over the nation's transmission systems to secure their monopoly position as power suppliers. However, as described at length in Order No. 888, these policies arose in the context of practical, economic, and regulatory circumstances that gave rise to vertically integrated monopolies and little, if any, competition among power suppliers. In this kind of regime, the interests of customers were most effectively served by the kind of cost-based regulatory regime that has prevailed until very recently. The evolution of third-party generation, facilitated by PURPA and significant technological advances, dramatically altered the economics of power production. The enactment of EPAct recognized these changes and established a national policy intended to favor the development of a competitive generation market, so that the efficiencies of the new marketplace will be available to customers in the form of lower costs for electricity. Utility practices that may have been acceptable a few years ago would, if permitted to continue, smother the fledgling competitive wholesale markets and undermine the efforts of customers to seek lower-price electricity. We firmly believe that our authorities under the FPA not only permit us to adapt to changing economic realities in the electric industry, but also require us to do so, Docket Nos. RM95-8-001 -89- and RM94-7-002 if that is necessary to eliminate undue discrimination and protect electricity customers. Specific Arguments 73/ The Factual Circumstances Underlying AGD Do Not Mandate A Different Conclusion In This Proceeding Both Union Electric and Carolina P&L argue that the Commission cannot rely on AGD in support of its actions in the electric industry, and they attempt to distinguish the legal basis on which the Commission acted in requiring open access transportation for gas pipelines. Specifically, they argue that AGD (Order No. 436) pertained to voluntary actions by gas pipelines and that the Commission's imposition of open access requirements was a condition of certificate authorizations to transport gas, whereas the Commission's action in Order No. 888 is a direct mandate. 74/ We believe this is a distinction without a difference. While it is true that the Commission required open access as a condition of granting blanket authorizations for pipelines and authorizations for pipelines authorizing pipelines to transport natural gas, 75/ the critical point is that in both Order No. 436 and Order No. 888 the Commission's actions hinged as a legal matter on the parallel We do not repeat our lengthy legal analyses in Order No. 888, but discuss only those arguments that warrant further discussion. See Union Electric and Carolina P&L. These authorizations are issued under section 7 of the Natural Gas Act and section 311 of the Natural Gas Policy Act. Docket Nos. RM95-8-001 -90- and RM94-7-002 provisions of the NGA (sections 4 and 5) and the FPA (sections 205 and 206) that prohibit undue discrimination. Whether persons are seeking to transport natural gas or wheel electric power in interstate commerce, by law they must not unduly discriminate or grant undue preference. 76/ In AGD, the court upheld the Commission's reliance upon sections 4 and 5 of the NGA to impose an open-access commitment on any pipeline that secured a blanket certificate to provide gas transportation under section 7 of the NGA or provided transportation under section 311 of the NGPA. 77/ Order No. 436 was not a simple order that relied on the "voluntary actions" of affected pipelines. As the court in AGD understood: The Order envisages a complete restructuring of the natural gas industry. It may well come to rank with the three great regulatory milestones of the industry. . . . At stake is the role of interstate natural gas pipelines. Although they are obviously transporters of gas, they have until recently operated primarily as gas merchants. They buy gas from producers at the wellhead and resell it, mainly to local distribution companies ("LDCs") but also to relatively large end users. The Commission has concluded that a prevailing pipeline practice -- particularly their general refusal to transport gas for third parties where to do so would displace their own sales -- has While there is a difference in the statutes in that natural gas transporters must obtain a certificate from the Commission before they can transport gas, there is no difference in the statutory standard applied to the interstate service. 824 F.2d at 997-98. The court also noted the Commission's reliance on section 16 of the NGA. Docket Nos. RM95-8-001 -91- and RM94-7-002 caused serious market distortions. It has found this practice "unduly discriminatory" within the meaning of  5 of the NGA. Order 436 is its response. The essence of Order No. 436 is a tendency, in the industry metaphor, to "unbundle" the pipelines' transportation and merchant roles. If it is effective, the pipelines will transport the gas with which their own sales compete; competition from other gas sellers (producers or traders) will give consumers the benefit of a competitive wellhead market. [78/] Indeed, since Order No. 436 issued, virtually all jurisdictional natural gas pipelines became "open access" transporters of natural gas. In analyzing the Commission's authority to remedy undue discrimination, the court never made the distinctions now being put forth by Union Electric and Carolina P&L. Rather, the court specifically focused on the Commission's authority under section 5 of the NGA and upheld the Commission's authority to remedy undue discrimination in the transportation of natural gas by requiring pipelines transporting natural gas to do so on a non- discriminatory basis. 79/ Similarly, the Commission in Order No. 888 found undue discrimination in the transmission of electric energy and required, pursuant to section 206 of the FPA (the FPA 824 F.2d at 993-94. For example, as the AGD court explained with regard to its discussion of Maryland People's Counsel v. FERC, 761 F.2d 780 (D.C. Cir. 1985), "we made it clear that blanket- certificate transportation, unconstrained by any nondiscriminatory access provision, might well require remedial action under  5." 824 F.2d at 1000. Docket Nos. RM95-8-001 -92- and RM94-7-002 provision that parallels section 5 of the NGA), that if public utilities transmit electric energy in interstate commerce, they must do so on a non-discriminatory basis (i.e., offer non- discriminatory open access transmission). Moreover, while the Commission may have imposed a "condition" on pipelines obtaining blanket certificates or providing section 311 transportation in Order No. 436, this does not detract from the court's core finding in AGD that the Commission had the authority under section 5 of the NGA to remedy undue discrimination by requiring open access transportation. 80/ The Commission chose in Order No. 436 to impose its open access remedy as a condition to pipelines obtaining a blanket certificate to transport natural gas, but its authority was rooted in the undue discrimination provisions of section 5. Additionally, the practical result of the conditioning was that all jurisdictional pipelines would have to provide open access transportation, a result that was clearly anticipated by the AGD court. 81/ Thus, there is no distinction in the result intended, We disagree with Union Electric that anything in the Commission's brief to the Supreme Court, opposing certiorari of AGD, contradicts our conclusion. We recognize, as the Commission explained in that brief, that there is no equivalent to section 7 of the NGA in the FPA. While this puts Order No. 888 on a somewhat different factual basis from AGD, it has no material effect on whether we have the authority to remedy undue discrimination by requiring non- discriminatory open access transmission. See 824 F.2d at 993-94 ("The Order envisages a complete restructuring of the natural gas industry. It may well come to rank with the three great regulatory milestones of the (continued...) Docket Nos. RM95-8-001 -93- and RM94-7-002 or the result achieved, in either industry; in both cases, the intent was to remedy undue discrimination pursuant to the statutes governing each industry, and in both cases the result was that all transporters/transmitters must agree to open access non-discriminatory services if they seek to continue owning, controlling or operating monopoly interstate transportation facilities. Legislative History Behind The FPA and EPAct Does Not Preclude Our Action We disagree with the arguments that the legislative history behind Part II of the FPA establishes that the Commission cannot under any circumstance order wheeling under FPA sections 205 and 206. 82/ We examined the legislative history of sections 205 and 206 at length in the NOPR and Order No. 888 and concluded that it supports our authority to order open access transmission as a remedy for undue discrimination. 83/ We also have examined the (...continued) industry. . . ."). Parties have raised the legislative history of sections 205 and 206, as well as the legislative history of the EPAct amendments to sections 211 and 212. FERC Stats. & Regs. at 31,676-78; mimeo at 120-27. Notice of Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking, FERC Stats. & Regs.  32,514 at 33,053-56 (1995). Union Electric points to a statement in the Commission's 1987 brief to the U.S. Supreme Court, opposing certiorari of the AGD case; in that brief the Commission pointed out that the Supreme Court had noted, in Otter Tail, that the legislative histories of the FPA and NGA are "materially different." As we explained in Order No. 888, we have thoroughly reexamined the legislative histories of the NGA and FPA with respect to this issue and now conclude (continued...) Docket Nos. RM95-8-001 -94- and RM94-7-002 legislative history of the EPAct amendments to sections 211 and 212 and conclude that Congress in EPAct did not resolve the issue of our authority under sections 205 and 206 and left untouched whatever pre-existing authorities we had under these sections. The parties have raised nothing new on rehearing to persuade us that our interpretation is wrong. However, there are several arguments that we believe warrant further discussion. Parties on rehearing argue that the existence of sections 211 and 212 limit the Commission's wheeling authority and, in effect, remove our authority under section 206 to order any transmission as a remedy for undue discrimination. 84/ We disagree. In enacting EPAct, Congress did not resolve the extent of our wheeling authority outside the context of sections 211 and 212. 85/ As we explained above, while Congress in 1978 gave the (...continued) that there is no material difference as to this issue in the legislative histories of the two statutes. Further, such a difference, whether or not it exists, was not crucial to the fundamental holdings of the AGD court and does not preclude that decision from applying equally in the electric industry. See FERC Stats. & Regs. at 31,676-78; mimeo at 121-26. We also note that in its brief to the Supreme Court the Commission explicitly stated that neither Otter Tail nor any of the other electric cases cited "presented the question whether the Commission could order wheeling to remedy undue discrimination or anticompetitive behavior. . . ." FERC Brief at 25 (footnote omitted). See discussion supra concerning AGD court's understanding that Order No. 436 was not a simple order that relied on voluntary actions of affected pipelines. Contrary to certain assertions, in Order No. 888 we viewed the statute as a whole and determined that section 211 in no way limited the broad authority Congress gave us to eradicate undue discrimination in the electric power (continued...) Docket Nos. RM95-8-001 -95- and RM94-7-002 Commission certain case-by-case authority to order transmission access, it also specifically provided in section 212(e) of the FPA that the case-by-case authorities were not to be construed as limiting or impairing any authority of the Commission under any other provision of law. Congress retained a similar savings clause when it amended sections 211 and 212 in 1992. Moreover, the legislative history of EPAct shows that when Congress amended sections 211 and 212, it was well aware of arguments regarding the scope of the Commission's remedial authority under section 206. 86/ Whereas Congress added an amendment prohibiting the Commission from ordering direct retail wheeling under any provision of the FPA, it chose not to add a prohibition on the Commission ordering wholesale wheeling as a remedy for undue discrimination under sections 205 and 206. 87/ We are not persuaded that this conclusion is wrong based on rehearing arguments that we ignored other legislative history of (...continued) industry. See note 71 and related discussion, supra. In response to Carolina P&L's argument that Congress gave the Commission a specific remedy under section 211 and the Commission should not presume that it has additional remedies in such a circumstance, we do not believe that section 211 can credibly be viewed either as a partial substitute for, or as superseding, the section 205-206 undue discrimination remedial authority that is fundamental to the Federal Power Act. Indeed, section 211 is not written in terms of providing remedial authority to address undue discrimination but rather provides for case-by-case transmission service on request if the service is in the public interest and meets the other criteria in sections 211 and 212. Docket Nos. RM95-8-001 -96- and RM94-7-002 EPAct. Carolina P&L argues that we ignored various statements of Senator Wallop following the enactment of EPAct, which it alleges are counter to our claim of authority to order open access transmission as a remedy for undue discrimination. The utility is simply in error that we ignored these statements. We explicitly mentioned Senator Wallop's statements in Order No. 888 and gave our rationale for why section 211 does not limit our authority to remedy undue discrimination. 88/ However, we believe it is important to elaborate on the context in which those statements were made and our interpretation of those statements. The primary focus of Senator Wallop's statements is on the transmission authority given by the EPAct amendments to sections 211 and 212. These statements emphasize restrictions on our section 211 wheeling authority, including the fact that section 211 does not give the Commission authority to order transmission access on its own motion or to order open access transmission. 89/ We do not quarrel with these statements because sections 211 and 212 clearly do place restrictions on our authority to order access under those provisions. The statements also discuss the differences between the House introduced amendments to sections 211 and 212 (which would have provided broader and in some FERC Stat. & Regs. at 31,686-87; mimeo at 148-51. Most of the statements talk in terms of "The Conference Report provides. . . ." and thus are referring only to the section 211 and 212 provisions. See, e.g., 138 Cong. Rec. 517616 (Oct. 8, 1992). Docket Nos. RM95-8-001 -97- and RM94-7-002 instances mandatory access authority) and the amendments that finally passed (which were more limited). We also do not disagree that changes were made to the bill that originally was introduced. At issue here, however, is not whether there are restrictions on our section 211 authority, but rather whether we have authority outside the context of section 211 to order transmission as a remedy for undue discrimination. The only statement among Senator Wallop's remarks that addresses this specific issue is one in which he says, "In my opinion, neither the amendments made by this Act nor existing law give the FERC any authority to mandate open access transmission tariffs for electrical utilities." (emphasis added). We do not view one senator's opinion as in any way dispositive of the issue. As discussed supra, when Congress enacted the 1992 section 211 amendments it was well aware of the outstanding legal issue of the Commission's authority to order access as a remedy for undue discrimination under section 206. It chose not to clarify this issue by prohibiting the Commission from ordering access, but instead retained the savings clause in section 212(e). The issue of our legal authority thus turns on the undue discrimination authority given to us in 1935, and the legislative history of sections 205 and 206. We discussed this at length in Order No. 888. 90/ On rehearing, several entities emphasize the Otter Tail case and the legislative history referred to in that FERC Stats. & Regs. at 31,676-78; mimeo at 120-27. Docket Nos. RM95-8-001 -98- and RM94-7-002 case. In particular, Union Electric recites Justice Stewart's discussion of the legislative history in his partial dissent in Otter Tail. We do not interpret that discussion to suggest that we do not have the authority to remedy undue discrimination by requiring open access transmission under any circumstance. As we explained in Order No. 888: In the FPA, while Congress elected not to impose common carrier status on the electric power industry, it tempered that determination by explicitly providing the Commission with the authority to eradicate undue discrimination -- one of the goals of common carriage regulation. By providing this broad authority to the Commission, it assured itself that in preserving "the voluntary action of the utilities" it was not allowing this voluntary action to be unfettered. It would be far-reaching indeed to conclude that Otter Tail, which was a civil antitrust suit that raised issues entirely unrelated to our authority under section 206, is an impediment to achieving one of the primary goals of the FPA -- eradicating undue discrimination in transmission in interstate commerce in the electric power industry. [91/] In response to Union Electric's arguments that Congress explicitly rejected common carrier provisions in 1935, we do not disagree with Union Electric's statement that "the mandatory wheeling language was not dropped inadvertently." 92/ The point that we made in Order No. 888 (quoting AGD) in this regard was that FERC Stats. & Regs. at 31,670; mimeo at 103. Union Electric at 26. Docket Nos. RM95-8-001 -99- and RM94-7-002 (1) "Congress declined itself to impose common carrier status" (emphasis added) and (2) there is no "support for the idea that the Commission could under no circumstances whatsoever impose obligations encompassing the core of a common carriage duty." [93/] Nowhere did we ever suggest that the mandatory wheeling language was dropped inadvertently; we simply distinguish a general common carrier obligation imposed "in the public interest" from an obligation to provide transmission service deemed necessary to eliminate undue discrimination. Finally, we fully agree with Union Electric's statement that [a]lthough this "first Federal effort" occurred in 1935, the resulting FPA Sections 205 and 206 have not been modified in any relevant respect since that time. Therefore, the range of authority conveyed to the Commission in such sections remains the same today as it did then. [94/] We never suggested otherwise and our conclusion in Order No. 888 is not based on a finding to the contrary. Case Law Does Not Prohibit Our Ordering Wheeling Under Sections 205 And 206 Of The FPA Union Electric, discussing the very cases cited by the Commission in Order No. 888, asserts that "the Commission fails to recognize their dispositive results prohibiting it from ordering wheeling under the Sections 205 and 206 of the FPA." 95/ We thoroughly examined all of the case law cited by Union FERC Stats. & Regs. at 31,677; mimeo at 122. Union Electric at 27. Union Electric at 30. Docket Nos. RM95-8-001 -100- and RM94-7-002 Electric, as evidenced by our discussions in the NOPR and Order No. 888, and disagree that any of those cases prohibit the Commission from ordering wheeling under sections 205 and 206 of the FPA to remedy undue discrimination. Indeed, the AGD court reached the same conclusion. 96/ Union Electric further cites to a variety of FPC cases that it claims demonstrate that the Final Rule exceeds the Commission's statutory authority. 97/ It appears to have proffered every negative Commission statement it could find with respect to our authority to order wheeling under Part II of the FPA. As in the Commission cases cited, we recognize that our authority to order transmission service is not unbounded; if we order transmission, it must be within the scope of authority available to us under the FPA. However, the fact is that none of the cases cited as establishing limits on the Commission's authority addresses the issue before us now, i.e., the Commission's authority to order transmission as a remedy for undue discrimination. Simply stated, the Commission has never before been faced with generic findings of undue discrimination in the provision of interstate electric transmission services, The only relevant case the AGD court did not discuss was NYSEG. As we explained in Order No. 888, presumably this was because the case did not concern whether the Commission could order wheeling as a remedy for undue discrimination. FERC Stats. & Regs. at 31,672 n.217; mimeo at 108 n.217. Union Electric at 33-37. Docket Nos. RM95-8-001 -101- and RM94-7-002 and the extent of its authority to remedy that undue discrimination. Docket Nos. RM95-8-001 -102- and RM94-7-002 The Commission's General Counsel Never Asserted, Or Even Suggested, That The Commission Does Not Have The Authority To Order Wheeling As A Remedy For Undue Discrimination Union Electric spends several pages of its rehearing request asserting that the Commission's own General Counsel has acknowledged the limitations on the Commission's authority to order wheeling. 98/ In particular, it points to a statement by a Commission OGC witness that "'if Congress intends for the Commission to be able to deal with transmission on its own motion and thereby go further than simply dealing with industry proposals,' Congress would need 'to include an affirmative statement somewhere in the Act that the Commission could require wheeling on its own motion.'" 99/ This same statement was previously raised by EEI and previously addressed in Order No. 888. We do not disagree that this statement was made. However, it must be read in the context of the witness' entire testimony in which the witness stated four times the view that the case law supports the argument that the Commission has authority to order wheeling as a remedy for undue discrimination. 100/ Indeed, Union Electric at 37-40. Union Electric at 38-39. Hearings on H.R. 1301, H.R. 1543, and H.R. 2224 before the Subcommittee on Energy and Power of the House Committee on Energy and Commerce, 102d Cong., 1st Sess. (May 1,2 and June 26, 1991), Statement of Cynthia A. Marlette, Associate General Counsel, Federal Energy Regulatory Commission, Report No. 102-60 at 60 ("However, as discussed below, there are strong legal arguments that the Commission's obligation to protect against undue discrimination carries with it the (continued...) Docket Nos. RM95-8-001 -103- and RM94-7-002 contrary to Union Electric's assertion, the extensive legal analysis set forth by the Commission's witness supports the position relied upon in this proceeding. 101/ Thus, viewed in the context of the witness' entire testimony, Union Electric's arguments to the contrary are unavailing. Moreover, nowhere did the witness ever suggest, as asserted by Union Electric, that FPA sections 205 and 206 could only be used "to eliminate unduly discriminatory terms in a wheeling arrangement voluntarily filed with the Commission." 102/ (...continued) authority to impose transmission requirements as a remedy for undue preference or discrimination." "As discussed below, although the case law in this area has been uncertain, in OGC's opinion there is a strong legal argument that the Commission can require transmission as a remedy for undue preference or undue discrimination."); at 69-70 ("The weight of the limited case law, particularly the AGD opinion, supports authority to order wheeling as a remedy for undue discrimination where substantial evidence exists."); at 106 ("I believe that we have substantial authority under the existing case law to mandate access where necessary to remedy anticompetitive effects."). The statement quoted was preceded by a legal analysis of the Commission's authorities under then existing law, including section 206, and a statement that an examination of the Commission's full authorities might further open up the industry. Further, it was made in the context of case-by- case industry proposals and the Commission's inability to require case-by-case wheeling on its own motion. It did not address section 206 authority to remedy undue discrimination. Union Electric at 39. We note that Union Electric did not cite to any page or particular language to support its assertion. Docket Nos. RM95-8-001 -104- and RM94-7-002 The Commission Has The Authority To Order Public Utilities To Make Rate Filings In This Proceeding We reject Union Electric's argument that our requirement that Group 2 Public Utilities make section 205 filings is contrary to the voluntary filing scheme inherent in section 205. It is true that the Commission ordinarily cannot require a utility to make a section 205 filing. However, in this situation the section 205 filing was required as a remedy under section 206 of the FPA to establish rates for non-discriminatory open access transmission. Acting pursuant to section 206 of the FPA, we found that undue discrimination exists in the wholesale transmission of electric power and ordered the filing of non- discriminatory open access transmission tariffs to remedy this discrimination. Section 206 further requires that upon such a finding the Commission "shall determine the just and reasonable rate, charge, classification, rule, regulation, practice, or contract to be thereafter observed and in force. . . ." Thus, we had the authority to set the rates that would be observed and in force following the effectiveness of open access transmission and initially proposed to set rates for each public utility. However, rather than take this intrusive approach, which necessarily would have required a number of generic assumptions and resulted in less than public utility-specific rates, upon issuance of the Final Rule, we chose to permit these public utilities to make section 205 filings to propose their own rates for the services provided in the pro forma tariff. Docket Nos. RM95-8-001 -105- and RM94-7-002 The Commission's Prior Failure To Order Wheeling As A Remedy For Undue Discrimination Is Not Dispositive After discussing several cases that it asserts address the Commission's authority to remedy undue discrimination, Carolina P&L declares that "[p]erhaps the strongest evidence that the Commission lacks the power to compel wheeling under FPA section 206 is the fact that the Commission has never previously exercised this alleged power, despite numerous opportunities to do so." 103/ However, the court in AGD succinctly dismissed a similar argument: It is finally argued that the Commission's not having imposed any requirements like those of Order No. 436 in the period from enactment in 1938 until the present demonstrates the lack of any power to do so. . . . But as our introductory review of the economic background sought to illustrate, the Commission here deals with conditions that are altogether new. Thus no inference may be drawn from prior non-use. [104/] Undue Discrimination/Anticompetitive Effects 105/ A number of utilities and state commissions argue that the Commission lacks evidence to support a finding of undue discrimination. 106/ Carolina P&L at 35-36. 824 F.2d at 1001. In this regard, we acknowledge that our view of what constitutes undue discrimination has evolved significantly in light of the dramatic economic changes in the industry, as described briefly above and more fully in Order No. 888. FERC Stats. & Regs. at 31,682-84; mimeo at 136-42. E.g., El Paso, Union Electric, Carolina P&L, VA Com, FL Com, (continued...) Docket Nos. RM95-8-001 -106- and RM94-7-002 VA Com argues that the Commission failed to make a legally supportable finding of industry-wide undue discrimination: "FERC apparently drew a conclusion that there was undue discrimination in the NOPR without support and later accepted customers' allegations, without further inquiry, and relied on them in making its finding of industry-wide undue discrimination." (VA Com at 2-3). PA Com and Carolina P&L assert that allegations of undue discrimination do not form a sufficient basis to compel a generic rulemaking. Not coming forward with specific accusations and the identity of specific accusers, PA Com asserts, is unconstitutional as a deprivation of due process. With regard to specific allegations of undue discrimination, SoCal Edison argues that the Commission inappropriately relied upon allegations involving SoCal Edison as evidence of undue discrimination. SoCal Edison asks that the Commission declare that it is not making a factual determination as to any particular allegation especially since prior to 1994 the Commission defined discrimination differently. Dalton similarly argues that the Commission has no basis for finding that Georgia Power Company is engaged in unlawful undue discrimination as to new or roll-over transmission services in the operation of the Integrated Transmission System in Georgia (ITS) under the ITS agreement. Moreover, Dalton argues, even if it is found that GPC (...continued) PA Com. Docket Nos. RM95-8-001 -107- and RM94-7-002 acted in unduly discriminatory manner, it is not practical or lawful to order open access tariff for new and roll-over services. Finally, Carolina P&L argues that the comparability standard does not eliminate the "requirement" that parties must be similarly situated before discrimination is present, and that the Commission has not provided factual support for its implicit finding that public utilities and their native load customers are similarly situated to third parties. It cites City of Vernon v. FERC, 845 F.2d 1042 at 1045-46 (D.C. Cir. 1988), in support. Commission Conclusion As an initial matter, the Commission grants SoCal Edison's request for clarification that in Order No. 888 we did not make a factual determination as to any particular allegation of past discrimination described in the Final Rule. 107/ However, we reject arguments that the Commission cannot rely in part on the array of allegations and circumstances raised by customers in individual cases over the years and brought forth in response to the NOPR. The specific allegations are illustrative. However, they present examples of the types of discriminatory incentives and behavior inherent in ownership of monopoly transmission In response to PA Com's and Carolina P&L's assertions that not coming forward with specific accusations and identities of specific accusers is unconstitutional and a deprivation of due process, we emphasize that the Commission has not denied due process to anyone. The Final Rule does not, nor is it intended to, make specific findings as to any particular utility or any particular allegation raised. Docket Nos. RM95-8-001 -108- and RM94-7-002 facilities, and also present credible examples of the types of discriminatory behavior in which public utilities could engage in the future. We also reject arguments that customers and the Commission must litigate and make specific findings of discrimination against each public utility before we can take any action to preclude discriminatory behavior that will harm competition and, ultimately, electricity consumers. This is particularly true where the discriminatory behavior clearly is in the economic self-interest of a monopoly transmission owner facing the markedly increased competitive pressures that are driving today's electric utility industry. As we recognized in Order No. 888, [t]he inherent characteristics of monopolists make it inevitable that they will act in their own self-interest to the detriment of others by refusing transmission and/or providing inferior transmission to competitors in the bulk power markets to favor their own generation, and it is our duty to eradicate unduly discriminatory practices. As the AGD court stated: "Agencies do not need to conduct experiments in order to rely on the prediction that an unsupported stone will fall." [108/] We believe that the same general discriminatory circumstances that faced us when we required open access transportation in the natural gas industry 109/ are also before us today in the electric industry. First, it is uncontested that market power continues to exist in the ownership and operation of FERC Stats. & Regs. at 331,682; mimeo at 136-37. See AGD, 824 F.2d at 999-1000. Docket Nos. RM95-8-001 -109- and RM94-7-002 the monopoly-owned facilities that comprise the nation's interstate transmission grid. Second, utilities, as a general matter, did not in the past offer comparable transmission services to competitors or to customers. Open access services simply were not made available by utilities until the late 1980s when the Commission began to impose open access as a condition of approval of market-based rates and utility mergers in order to mitigate market power and remedy anticompetitive effects. Rather, the vast majority of utilities historically have declined to transport electric energy that would compete with their own sales or have offered access that is inferior to what they use for their own sales. Third, discrimination in transmission services, when viewed in light of utilities' own uses of their transmission systems compared to what they offer third parties, has denied and will continue to deny customers access to electricity at the lowest reasonable rates. The entities on rehearing have raised nothing to persuade us that it is in the interests of consumers to maintain the self-evident incentives for transmission owners to exercise their monopoly power over transmission to discriminate in favor of their own generation sales -- incentives that will only increase in the future as competitive pressures continue to escalate. The Commission addressed the same argument as that being made by Carolina P&L, that the Commission has not made the requisite finding that third-party transmission customers are similarly situated to public utilities and their native load Docket Nos. RM95-8-001 -110- and RM94-7-002 customers, in 1994 in the NEPOOL and AEP cases. 110/ In these cases, we recognized that the traditional focus of our undue discrimination analysis had been whether factual differences justify different rates, terms and conditions for similarly situated customers, but concluded that due to changing conditions in the electric utility industry, it was necessary to reevaluate our traditional analysis. As we stated in NEPOOL, the focal point of undue discrimination claims has shifted from claims of undue discrimination in rates and services which the utility offers different customers to claims of undue discrimination in rates and services which the utility offers when compared to its own use of the transmission system. 111/ "In this context, framing the analysis in terms of how a public utility treats similarly situated customers is not applicable or instructive." 112/ The Commission concluded that it therefore must reexamine its application of the standard for undue discrimination claims under sections 205 and 206 of the FPA. The Commission further elaborated on its re-examination of undue discrimination in AEP. The Commission cited its NEPOOL discussion and set for hearing the different uses that AEP made of its transmission system and whether there were any operational New England Power Pool, 67 FERC  61,402 (1994) (NEPOOL); American Electric Power Service Corporation, 64 FERC  61,279 (1993), reh'g granted, 67 FERC  61,168, clarified, 67 FERC  61,317 (1994) (AEP). 67 FERC  61,042 at 61,132. Id. Docket Nos. RM95-8-001 -111- and RM94-7-002 differences between any particular use that AEP made of the system and the use third parties might need, and, in particular, the degree of flexibility AEP accorded itself in using its transmission system for different purposes. The Commission subsequently set the same issue for hearing in several other cases. 113/ In the NOPR, however, the Commission concluded that based on what it had learned in the ongoing cases, it would address this issue generically in this rulemaking. We announced in the NOPR our belief that all utilities use their own systems in two basic ways: to provide themselves point-to-point transmission service that supports coordination sales, and to provide themselves network transmission service that supports the economic dispatch of their own generation units and purchased power resources (integrating their resources to meet their internal load). Third parties may need one or both of these basic uses in order to obtain competitively priced generation or to have the opportunity to be competitive sellers of power, and the Commission proposed that all public utilities must offer both services on a non-discriminatory open access basis. 114/ We affirmed this determination in the Final Rule. We concluded that a public utility must offer transmission services that it is reasonably capable of providing, not just those Commonwealth Edison Co., 70 FERC  61,204 (1995); Wisconsin Electric Power Co., 70 FERC  61,074 (1995); and Wisconsin Public Service Corp., 70 FERC  61,075 (1995). FERC Stats. & Regs.  32,524 at 33,079. Docket Nos. RM95-8-001 -112- and RM94-7-002 services that it is currently providing to itself or others. Because a public utility that is reasonably capable of providing transmission services may provide itself such services at any time it finds those services desirable, it is irrelevant that it may not be using or providing that service today. 115/ Thus, based on the analysis in this record, the Commission has determined that undue discrimination in the provision of transmission services in today's industry does not turn on whether utilities and their native load customers are similarly situated to third parties, but instead turns on whether the utility is providing comparable service, that is, service that it is reasonably capable of providing to other users of the interstate transmission system. In short, the Commission is not bound to a static application of its undue discrimination analysis under the FPA and, indeed, has a public interest responsibility to reexamine undue discrimination in light of changed circumstances in the industry. 116/ That is what we began in NEPOOL and AEP and have completed in this rulemaking. The traditional "similarly FERC Stats. & Regs. at 31,690; mimeo at 160. There is no "requirement" in the FPA that the Commission apply a "similarly situated" test. Carolina P&L's reliance on City of Vernon is misplaced. That case involved a claim of discrimination in the type of service offered to a wholesale customer versus that offered to retail customers, and the Commission's application of the "similarly situated" and "same service" test. Contrary to Carolina P&L's implication, the case does not hold that the Commission is bound to apply a "similarly situated" test in analyzing undue discrimination claims under the FPA. Docket Nos. RM95-8-001 -113- and RM94-7-002 situated" test, while applicable to discrimination among third- party customers, simply is not applicable when analyzing discrimination between third-party transmission customers and transmission owners. Under Carolina P&L's theory, presumably the only customers that could be shown to be similarly situated would be those who own monopoly transmission facilities and have native load (i.e., captive) customers. This would preserve customer captivity, perpetuate monopoly power and profits, and deny the lowest reasonable rates to consumers. We therefore reject Carolina P&L's arguments. Moreover, the fact that public utilities and their native load customers have been treated differently from third-party transmission customers because they are not among those traditionally considered to be "similarly situated" is precisely the target at which Order No. 888 takes aim. Historically, competitively-priced power was not broadly available to wholesale customers because the industry was dominated by vertically integrated IOUs 117/ and, to the extent cheaper generation alternatives were available in the marketplace, transmission owners either took the cheaper power for their own uses or purchased and re-sold it at a profit. 118/ Prior to EPAct, most I.e., investor-owned utilities that owned generation, transmission and distribution facilities and most of whom had captive customers. Very simply, the transmission owner was able to prevent third parties from achieving the maximum savings possible in the generation market by withholding or delaying (continued...) Docket Nos. RM95-8-001 -114- and RM94-7-002 power customers took power from the vertically integrated utilities that provided their transmission service. Transmission-only transactions played a secondary role in bulk power markets, facilitating certain economy transactions and coordination and pooling arrangements that improved utility operational efficiencies, largely as a complement to bundled bulk power transactions. Given the predominantly vertically- integrated industry and efficiencies that could be gained through encouragement of coordination and pooling transactions, the Commission was willing to accept utility practices that provided third parties with transmission services that were distinctly inferior to the utility's own uses of the transmission system. In the future, however, unbundled transmission service will be the centerpiece of a freely traded commodity market in electricity, in which all wholesale customers can shop for power. In a market characterized by a significant increase in non- vertically integrated power suppliers and competitively priced power that is now meaningfully available, it is no longer in the interest of wholesale customers for the Commission to tolerate the types of practices that were previously accepted. We cannot allow what have become unduly discriminatory practices to erect barriers between customers and the rapidly emerging competitive electricity marketplace. Accordingly, a primary goal of Order (...continued) transmission service. Alternatively, the transmission owner could purchase the power and resell it to the third party at a rate that reflected a mark-up from the first power sale. Docket Nos. RM95-8-001 -115- and RM94-7-002 No. 888 is to provide that in the future transmission providers and third-party transmission customers are "similarly situated" in the quality of transmission service available to them. C. Comparability 1. Eligibility to Receive Non-discriminatory Open Access Transmission In the Final Rule, the Commission modified the definition of "eligible customer" and, among other things, clarified that any entity engaged in wholesale purchases or sales of electric energy, not just those "generating" electric power, is eligible. 119/ The Commission also clarified that entities that would violate section 212(h) of the FPA (prohibition on Commission- mandated wheeling directly to an ultimate consumer and sham wholesale transactions) are not eligible. Further, the Commission clarified that foreign entities that otherwise meet the eligibility criteria may obtain transmission services. The Commission also provided for service to retail customers in circumstances that do not violate FPA section 212(h). Persons that would be eligible section 211 applicants also would be eligible under the open access tariff. FERC Stats. & Regs. at 31,688-90; mimeo at 154-58. Docket Nos. RM95-8-001 -116- and RM94-7-002 a. Unbundled Retail Transmission and "Sham Wholesale Transactions" Rehearing Requests Several entities assert that there is an inconsistency between tariff language and preamble language and argue that section 1.11 of the tariff should be made consistent with the preamble to ensure that, absent a state-approved program, retail wheeling is not available under the tariff, no matter which party requests service. 120/ They maintain that the limitation in section 1.11 that the transmission provider only must provide retail transmission service voluntarily or under a state-approved program appears to apply only when a retail customer is the purchaser, not when the transmission purchaser is an electric utility. They suggest the following language to remedy the problem: "however, such entity is not eligible for transmission service that would be prohibited by Sections 212(h)(1) and/or 212(h)(2) of the Federal Power Act, unless such service is provided pursuant to a state retail access program or pursuant to a voluntary offer of unbundled retail transmission service by the Transmission Provider." (PSE&G at 22; Carolina P&L at 8-9). Detroit Edison argues that the Commission should modify the definition to exclude any reference to transmission service provided to retail customers so as to avoid confusion and possible forum shopping. At the least, Detroit Edison argues, the Commission should modify the language to state that E.g., SoCal Edison, PSE&G, Carolina P&L. Docket Nos. RM95-8-001 -117- and RM94-7-002 transmission service is available to an ultimate consumer to the extent, and only to the extent, that the service is authorized by a lawful state retail access program or pursuant to a voluntary offer of unbundled retail transmission service by the transmission provider. NYSEG asserts that the Commission did not apply the section 212(h) limitation to service to retail customers under the tariff. NYSEG requests that the Commission clarify that it will not require retail wheeling beyond the scope of state-mandated retail access programs or beyond the terms of a transmission provider's voluntary offer of retail wheeling service. Oklahoma G&E asks the Commission to clarify that the term eligible customer differentiates between a customer eligible to receive transmission service and a customer whose transaction is a sham or would result in mandatory retail wheeling and would therefore be prohibited by section 212(h). NYSEG further asserts that the right of first refusal provision would permit a retail customer receiving wheeling service to continue to take that service upon expiration of its contract, which could require the transmission provider, in violation of section 212(h), to continue retail wheeling beyond the scope of its voluntary offer of service or beyond the scope of a state-mandated retail access program. SoCal Edison argues that the Commission cannot compel a utility to supply retail transmission service if the utility Docket Nos. RM95-8-001 -118- and RM94-7-002 challenges the authority of the state to require retail wheeling and section 1.11 should be revised to reflect this. IL Com declares that it "does not recognize FERC's claim of jurisdiction over retail transmission service provided directly to a retail customer and disputes that unbundled retail wheeling directly to a retail customer is a service provided in interstate commerce." (IL Com at 35). Thus, "if FERC's proposed 'deference' to states is to be given any effect, states must be allowed to determine whether the retail transmission component of the retail wheeling program will be provided pursuant to the utility's existing filed wholesale tariff or whether the retail transmission will be provided pursuant to a 'separate retail transmission tariff' that is different from the wholesale tariff." (IL Com at 36). IL Com concludes that it is inappropriate (and illegal if FERC is overturned on its retail transmission jurisdiction assertion) to include retail customers taking final delivery of unbundled power for their own end uses under retail wheeling programs as eligible customers. PA Com argues that it is relevant whether a customer is receiving retail or wholesale service and redefining transmission and local distribution service does not automatically convey jurisdiction to the Commission. CCEM asks that the Commission clarify that a retail customer eligible to seek transmission service should be able to seek transmission service not only from the transmission provider, but from any other transmission provider. CCEM also asks that the Docket Nos. RM95-8-001 -119- and RM94-7-002 Commission add the word "ultimate" before the word transmission provider in section 1.11 of the tariff. EEI asks the Commission to "clarify that the transmission service provider should be allowed to supplement the terms and conditions of the pro forma tariff with additional provisions that specifically relate to the totality of the transmission service being provided, including the use of distribution facilities and any other transmission facilities not currently included in wholesale rates." (EEI at 24 (emphasis in original)). 121/ Union Electric argues that a literal reading of the eligibility definition could require retail wheeling by utilities in states other than those required to participate in a particular retail wheeling program. Commission Conclusion The Commission agrees with those entities that argue that section 1.11 of the pro forma tariff does not explicitly prohibit "sham wholesale transactions" that could currently be arranged under the tariff by a utility applying for service and designating the retail customer as a point of delivery. We therefore have modified section 1.11 to clarify that, with respect to service that we are prohibited from ordering by section 212(h) of the FPA (whether direct retail wheeling or "sham" wholesale wheeling), otherwise eligible entities may See also CSW Operating Companies. Docket Nos. RM95-8-001 -120- and RM94-7-002 obtain such service under the tariff only if it is pursuant to a state requirement that such service be provided or pursuant to a voluntary offer of such service. We also have modified the language to clarify that eligibility for unbundled direct retail service required by a state applies only to service from transmission providers that the state orders to provide the service. The modified language states: Eligible Customer: (i) Any electric utility (including the Transmission Provider and any power marketer), Federal power marketing agency, or any person generating electric energy for sale for resale is an eligible customer under the tariff. Electric energy sold or produced by such entity may be electric energy produced in the United States, Canada, or Mexico. However, with respect to transmission service that the Commission is prohibited from ordering by Section 212(h) of the Federal Power Act, such entity is eligible only if the service is provided pursuant to a state requirement that the Transmission Provider offer the unbundled transmission service, or pursuant to a voluntary offer of such service by the Transmission Provider. (ii) Any retail customer taking unbundled transmission service pursuant to a state requirement that the Transmission Provider offer the transmission service, or pursuant to a voluntary offer of such service by the Transmission Provider, is an eligible customer under the tariff. Regarding SoCal Edison's argument, the Commission stated in the Final Rule: Moreover, we are mindful of the fact that we are precluded under section 212(h) from ordering or conditioning an order on a requirement to provide wheeling directly to an ultimate consumer or sham wholesale wheeling. We therefore clarify that our decision to eliminate the wholesale customer Docket Nos. RM95-8-001 -121- and RM94-7-002 eligibility requirement does not constitute a requirement that a utility provide retail transmission service. Rather, we make clear that if a utility chooses, or a state lawfully requires, unbundled retail transmission service, such service should occur under this tariff unless we specifically approve other terms. [122/] Therefore, the Commission is not compelling a utility to provide unbundled retail transmission service. 123/ Rather, the Commission requires that should such service be provided, either pursuant to state mandate or voluntarily, it must be provided pursuant to the pro forma tariff unless the Commission approves alternative terms and conditions. However, in light of CCEM's request that we clarify that a retail customer eligible to seek transmission service under the tariff should be able to seek service not only from the transmission provider, but also from any other transmission provider, and in light of Union Electric's concerns regarding retail service eligibility, we believe certain clarifications of our jurisdiction and of the statements made in Order No. 888 are necessary. The statements cited above that were made in Order FERC Stats. & Regs. at 31,689-90; mimeo at 158. We also disagree with NYSEG's assertion that the right of first refusal provision would permit a retail customer receiving wheeling service to continue to receive service after the expiration of its contract and could require the transmission provider to continue wheeling beyond the scope of its voluntary offer of service or beyond the scope of a state-mandated retail access program. Section 212(h) of the FPA would override any provision, including the right of first refusal provision, that may be included in the pro forma tariff. Docket Nos. RM95-8-001 -122- and RM94-7-002 No. 888 and the eligible customer tariff definition in (ii) above refer to direct retail transmission, i.e., the transmission of electric energy "directly" to an ultimate consumer. The Commission is prohibited by section 212(h)(1) of the FPA from ordering this type of retail transmission and that is why customers are eligible for such transmission under the tariff only if the transmission is pursuant to a state order or is provided voluntarily. However, on its face, section 212(h) does not prohibit the Commission from ordering public utilities to provide "indirect" unbundled retail transmission in interstate commerce, i.e., the transmission necessary to transmit unbundled electric energy to a utility that ultimately will deliver the energy to a customer that is purchasing the unbundled energy at retail either pursuant to a state retail access order or pursuant to voluntary delivery by the local utility. We clarify that we believe we have the jurisdiction under the FPA to order indirect retail transmission to an ultimate consumer and that if the Commission under sections 205, 206 or 211 of the FPA orders such transmission, entities that otherwise qualify as eligible customers under the tariff will take transmission service for such indirect retail wheeling pursuant to the pro forma tariff. We note that the Commission may order such transmission on a case-by-case basis or may determine to do so generically in the future. We expect public utilities to provide such indirect retail access under the pro forma tariff and, if they do not, we will not hesitate to order them to do so. Docket Nos. RM95-8-001 -123- and RM94-7-002 In response to IL Com's argument that it does not recognize this Commission's claim of jurisdiction over the rates, terms and conditions of unbundled retail transmission that is provided directly to an ultimate consumer, the Commission reaffirms its legal conclusion set forth in the Final Rule. 124/ As to its claim that we should give deference to the state as to whether such service could be taken under the wholesale tariff or a separate retail tariff on file with the Commission, we reaffirm our conclusion to address this on a case-by-case basis. Since the Final Rule issued, the Commission has addressed this in several orders. In New England Power Company, the Commission stated: 125/ As we explained in the Open Access Rule and in the New Hampshire Interim Order, we generally expect retail transmission customers to take service under the same Commission tariff that applies to wholesale customers. While we generally will defer to state requests for a separate retail tariff to accommodate the design and special needs of a state retail access program, the Massachusetts Commission has made no such request in this case. 15/ 15/ See Open Access Rule, FERC Stats. & Regs. at 31,784; New Hampshire Interim Order, 75 FERC at 61,687 & n.3 (both noting that such a separate retail tariff must be FERC Stats. & Regs. at 31,780 and Appendix G (31,966-81); mimeo at 428 and Appendix G. 75 FERC  61,356 at 62,141, order on reh'g, 77 FERC  61,135 (1996). In the order on rehearing, the Commission permitted a separate retail tariff to remain in effect for the duration of the retail electric pilot programs established in Massachusetts by Massachusetts Electric Company. Docket Nos. RM95-8-001 -124- and RM94-7-002 consistent with the Commission's open access policies and comparability principles). . . . Subsequently, in New England Power Company, 76 FERC  61,008 (1996), the Commission granted a limited waiver of the Open Access Rule requirements for the New Hampshire retail electric competition pilot project. Specifically, the Commission waived the requirement for individual service agreements, and the requirement for customer deposits. The Commission further announced that: other public utilities that provide unbundled retail service under a pro forma tariff do not need to apply to retail customers the tariff provisions regarding individual service agreements or customer deposits, unless a state retail program so requires. [126/] Concerning EEI's request for clarification, the Commission stated in the Final Rule: all tariffs need not be "cookie-cutter" copies of the Final Rule tariff. Thus, under our new procedure, ultimately a tariff may go beyond the minimum elements in the Final Rule pro forma tariff or may account for regional, local, or system-specific factors. The tariffs that go into effect 60 days after publication of this Rule in the Federal Register will be identical to the Final Rule pro forma tariff; however, public utilities then will be free to file under section 205 to revise the tariffs, and customers will be free to pursue changes under section 206. [127/] 76 FERC at 61,024. FERC Stats. & Regs. at 31,770 n. 514; mimeo at 399 n. 514. Docket Nos. RM95-8-001 -125- and RM94-7-002 Utilities are free to include customer-specific terms and conditions or terms and conditions limited to certain customers (e.g., a distribution charge) in the customer's service agreement and/or the network customer's network operating agreement. b. Transmission Providers Taking Service Under Their Tariff Rehearing Requests TAPS states that section 1.11 does not seem to require a transmission provider to take service for its purchases, but the preamble does (citing mimeo at 57, 191, 266 and regulatory text in section 35.28(c)(2)). It argues that transmission providers should be required to treat their own usage of the transmission system to serve retail customers under the network service provisions of the tariff. TAPS argues that this result could be achieved through an ISO or by requiring transmission providers to abide by all non-price terms of Parts I and III of the tariff. TAPS also argues that the rates charged network customers must be developed on the same basis as the transmission component of retail rates. It states that the transmission provider's purchases would then be made under Part III of the tariff to the extent they are made for serving retail customers. It further asserts that the Commission's authority and obligation to consider transmission owners' service to retail load in establishing wholesale transmission rates has been long established. At the least, TAPS argues that the Commission Docket Nos. RM95-8-001 -126- and RM94-7-002 should require that a transmission provider take its wholesale purchases under some tariff. Similarly, Coalition for Economic Competition asks the Commission to clarify that the requirement to use the pro forma tariff for wholesale purchases and to functionally unbundle wholesale purchases and sales does not apply to purchases made solely to serve retail customers on a bundled basis. It asserts that there is conflicting language in Order No. 888 (citing mimeo at 191) and Order No. 889 (citing mimeo at 12) and the pro forma tariff. Coalition for Economic Competition asserts that the Commission does not have jurisdiction over transmission that is part of a bundled retail sale. Commission Conclusion Several parties have noted on rehearing that there is conflicting language among the Final Rule, Order No. 889 and the pro forma tariff as to whether and to what extent the transmission provider must take service for "wholesale purchases" under its own tariff. As discussed below, we clarify that a transmission provider does not have to "take service" under its own tariff for the transmission of power that is purchased on behalf of bundled retail customers. In a situation in which a transmission provider purchases power on behalf of its retail native load customers, the Commission does not have jurisdiction over the transmission of the purchased power to the bundled retail customers insofar as the transmission takes place over such transmission provider's Docket Nos. RM95-8-001 -127- and RM94-7-002 facilities, 128/ and therefore the pro forma tariff does not have to be used for such transmission. Moreover, we recognize that purchases made collectively on behalf of native load 129/ cannot necessarily be identified as going to any particular customer. However, the Commission does have jurisdiction over transmission service associated with sales to any person for resale, and such transmission must be taken under the transmission provider's pro forma tariff. 130/ Order No. 888, relying on the principle of comparability, established the terms and conditions for network service provided to network customers under the pro forma tariff. Network customers may include the transmission provider itself as well as any other entity receiving Network Integration Service. If the transmission provider purchases energy from another power supplier in order to make sales to its wholesale native load customers, it must take the transmission service necessary to To the extent the transmission takes place on the interstate facilities of other public utilities, we would have jurisdiction over such transmission. Native load means "[t]he wholesale and retail power customers of the Transmission Provider on whose behalf the Transmission Provider, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate the Transmission Provider's system to meet the reliable electric needs of such customers." Section 1.19 of the pro forma tariff. All transmission in interstate commerce by a public utility in conjunction with a sale for resale of electric energy is jurisdictional and must be taken under a FERC-jurisdictional tariff. The same is true for all unbundled transmission in interstate commerce to wholesale customers, as well as to unbundled retail customers. Docket Nos. RM95-8-001 -128- and RM94-7-002 transmit the power from its point(s) of receipt to its point(s) of delivery under the same terms and conditions as other Network Customers. 131/ As we explained in AES Power, Inc., network customers are entitled to make economy energy purchases from non- designated network resources at no additional charge on a basis comparable to the economy energy purchases made by the transmission provider on behalf of its bundled retail customer. 132/ This applies to the transmission provider as a network transmission customer under its own tariff as well as to other network transmission customers that make economy energy purchases on behalf of their customers. Thus, insofar as all wholesale transmission customer usage is concerned, third-party network customers are treated the same as the transmission owner. 2. Service that Must be Provided by Transmission Provider In the Final Rule, the Commission found that a public utility must offer transmission services that it is reasonably capable of providing, not just those services that it is currently providing to itself or others. 133/ The Commission explained that because a public utility that is reasonably Under the Order No. 888 pro forma tariff, third-party wholesale customers have the ability to obtain the identical service the transmission provider provides itself when it engages in a sale of electric energy for resale. This may include network or point-to-point service. / 69 FERC  61,145 at 62,300 (1994) (proposed order), 74 FERC  61,220 (1996) (final order). FERC Stats. & Regs. at 31,690; mimeo at 160. Docket Nos. RM95-8-001 -129- and RM94-7-002 capable of providing transmission services may provide itself such services at any time it finds those services desirable, it is irrelevant that it may not be using or providing that service today. However, the Commission explained that if a customer seeks a customized service not offered in an open access tariff, a customer may, barring successful negotiation for such service, file a section 211 application. Rehearing Requests Cleveland requests that the Commission make explicit that comparability will be evaluated not only by reference to a transmission provider's wholesale services, but also by comparison to the terms, conditions, and prices applicable to its retail services, whether bundled or unbundled. Cleveland asserts that this is needed so that TDUs are not at a competitive disadvantage in competing with the transmission provider for retail customers. It maintains that this is consistent with the Transmission Pricing Policy and established precedent. Commission Conclusion No clarification is necessary. In determining what transmission services a utility must offer for wholesale sales of electric energy in interstate commerce, the Final Rule explicitly states that "a public utility must offer transmission services that it is reasonably capable of providing, not just those services that it is currently providing to itself or others." Docket Nos. RM95-8-001 -130- and RM94-7-002 134/ Further, the Final Rule requires that network service customers receive service comparable to the service provided to the transmission provider's native load. Because the Rule applies to retail transmission that is voluntarily offered or pursuant to a state retail access program, the requirements to offer services that the utility is reasonably capable of providing and services comparable to those provided to native load would also apply to retail service in these limited retail circumstances. 3. Who Must Provide Non-discriminatory Open Access Transmission In the Final Rule, the Commission explained that its authority under sections 205 and 206 of the FPA permits it to require only public utilities to file open access tariffs as a remedy for undue discrimination. 135/ The Commission further explained that it has no authority under those sections of the FPA to require non-public utilities to file tariffs with the Commission. The Commission also discussed three mechanisms that would help alleviate the problems associated with not being able to require non-public utilities to provide open access: (1) broad application of section 211; (2) the reciprocity requirement set forth in the Final Rule; and (3) the formation of RTGs. FERC Stats. & Regs. at 31,690; mimeo at 160. FERC Stats. & Regs. at 31,691-92; mimeo at 162-65. Docket Nos. RM95-8-001 -131- and RM94-7-002 The Commission also indicated that it will not allow public utilities that jointly own interstate transmission facilities with non-jurisdictional entities to escape the requirements of open access. Thus, the Commission required each public utility that owns interstate transmission facilities jointly with a non- jurisdictional entity to offer service over its share of the joint facilities, even if the joint ownership contract prohibits service to third parties. The Commission required the public utilities, in a section 206 compliance filing, to file with the Commission, by December 31, 1996, a proposed revision (mutually agreeable or unilateral) to their contracts with non- jurisdictional owners. Rehearing Requests Jointly-Owned Facilities Union Electric argues that the Final Rule improperly requires a public utility to unilaterally file a modification to agreements that a non-jurisdictional entity opposes, which amounts to a litigation coercion provision. Union Electric notes that it has been told by Associated Electric Cooperative, Inc. that it will oppose any modifications to Union Electric's agreements. Union Electric further states that these facilities are not commonly owned, but rather each party wholly owns its segment of the facilities. Dalton asserts that Georgia Power Company cannot comply with the requirement to offer service over its share of joint facilities because the ITS is not owned by members as tenants in Docket Nos. RM95-8-001 -132- and RM94-7-002 common, but instead each member owns specific segments of the transmission grid. Dalton further argues that it is unjust and unreasonable to require Georgia Power Company to give access to the ITS to new and roll-over transmission customers under the Order No. 888 tariff that are unwilling to accept an investment responsibility and an obligation to make balancing payments. Associated EC argues that the Commission may modify non- jurisdictional contracts only under section 211 of the FPA; the Commission cannot simply modify the contract with respect to the public utility. NE Public Power District states that it is party to an agreement with a public utility involving jointly constructed transmission facilities that prohibits use of the transmission capacity by a non-party. It asserts that "[t]he District's contractual rights under its contract constitute valuable property, and the summary annulment of those rights constitutes a violation of Due Process." (NE Public Power District at 18-20). Moreover, it argues that blanket invalidation of the terms and conditions of the contracts is contrary to the Sierra-Mobile doctrine. Commission Conclusion We reject those arguments that maintain that the Commission cannot properly require a public utility to file unilaterally a modification to agreements concerning joint transmission facilities that a non-jurisdictional entity opposes. It is without question that the Commission has the exclusive authority Docket Nos. RM95-8-001 -133- and RM94-7-002 to regulate public utilities engaged in the sale for resale and/or transmission of electric energy in interstate commerce to assure that rates, terms and conditions are just and reasonable and not unduly discriminatory. The fact that a public utility may jointly own, with a non-jurisdictional entity, transmission facilities through which it engages in sales for resale and/or transmission of electric energy in interstate commerce does not alter the Commission's authority to regulate that public utility. 136/ If the Commission finds that a matter needs to be remedied, it may issue an order directed at the public utility. The fact that such an order may affect a non-jurisdictional joint owner does not undermine the validity of the Commission's order. 137/ Otherwise, a public utility could simply enter into joint agreements with non-jurisdictional utilities to the frustration of the Commission's mandate to protect consumers from undue discrimination. 138/ Nor does the exercise of the Commission's powers under the FPA to remedy undue discrimination by public utilities constitute a violation of due process vis-a-vis the non-jurisdictional See Policy Statement Regarding Regional Transmission Groups, 64 FERC  61,139 at 61,993 (1993); Midwest Power Systems, Inc., 69 FERC  61,025 at 61,104-05 (1994). Nor does the form of ownership of the joint facilities have any bearing on the Commission's jurisdiction over public utilities. Though the non-jurisdictional entity would not become subject to Commission regulation. Cf. H.K. Porter Co., Inc. v. Central Vermont Railway, Inc., 366 U.S. 272, 273-75 (1961). Docket Nos. RM95-8-001 -134- and RM94-7-002 entity. When the contract was entered into and filed with the Commission it was with the explicit knowledge that the Commission could regulate the rates, terms and conditions of the contract with respect to the jurisdictional services provided thereunder by the public utility. If and when a public utility unilaterally files either to amend or terminate the agreement, the non- jurisdictional party is free to raise any arguments it wishes to support its position that no changes are necessary to ensure that the contract is just and reasonable and not unduly discriminatory or preferential. 4. Reservation of Transmission Capacity by Transmission Customers In the Final Rule, the Commission concluded that firm transmission customers, including network customers, should not lose their rights to firm capacity simply because they do not use that capacity for certain periods of time. 139/ Rehearing Requests No rehearing requests addressed this matter. 5. Reservation of Transmission Capacity for Future Use by Utility In the Final Rule, the Commission concluded that public utilities may reserve existing transmission capacity needed for native load growth and network transmission customer load growth reasonably forecasted within the utility's current planning FERC Stats. & Regs. at 31,693; mimeo at 168-70. Docket Nos. RM95-8-001 -135- and RM94-7-002 horizon. 140/ However, the Commission determined that any such capacity that a public utility reserves for future growth, but is not currently needed, must be posted on the OASIS and made available to others through the capacity reassignment requirements, until such time as it is actually needed and used. Rehearing Requests CCEM argues that it is discriminatory to allow public utilities and network transmission customers to reserve existing transmission capacity for their native load growth because it (1) limits the determination of ATC, (2) is likely to increase the cost of transmission for other customers, and (3) is inconsistent with a capacity reservation-based system. CCEM argues, however, that if the reservation feature is retained, franchise utilities that reserve capacity must pay the full reservation charges, with no cost shifting to other customers. CCEM further recommends that all reservation payments should be credited directly to firm transmission services and the planning horizon should be limited to a reasonable time into the future. American Forest & Paper argues that to achieve comparability, utilities must not be permitted to withhold capacity from the market for the benefit of native load. American Forest & Paper further argues that the Commission must establish mechanisms for evaluating the reasonableness of the utilities' requirements and projections, otherwise they have an FERC Stats. & Regs. at 31,694; mimeo at 172. Docket Nos. RM95-8-001 -136- and RM94-7-002 incentive to over-forecast and to extend their planning horizons. American Forest & Paper suggests that requiring utilities to establish separate entities to purchase transmission on behalf of their native load would help solve this problem. VA Com requests that the Commission clarify what will happen if a utility's forecast of load growth is too low. It argues that native load should not have to bear the burden of any forecast errors and that utilities should be required to reserve sufficient capacity to serve the current and projected needs of native load customers. VA Com would also have the definition of native load in section 1.19 of the tariff expanded to include existing distribution cooperatives and others who currently provide service to end users. With respect to reservation priority, VA Com states that the Commission should establish the following reservation priority: native load customers, firm contract customers, and non-firm customers. Finally, VA Com asserts that the calculation of ATC must not include any capacity that may be needed by native load customers. Commission Conclusion We will deny the requests of CCEM and American Forest and Paper. We continue to believe that public utilities should be allowed to reserve existing transmission capacity needed for native load growth and network customer load growth reasonably forecasted within the utility's current planning horizon. We note that network service is founded on the notion that the transmission provider has a duty to plan and construct the Docket Nos. RM95-8-001 -137- and RM94-7-002 transmission system to meet the present and future needs of its native load and, by comparability, its third-party network customers. In return, the native load and third-party network customers must pay all of the system's fixed costs that are not covered by the proceeds of point-to-point service. This means that native load and third-party network customers bear ultimate responsibility for the costs of both the capacity that they use and any capacity that is not reserved by point-to-point customers. In this regard, native load and third-party network customers face a payment risk that point-to-point customers generally do not face. For these reasons, we do not believe that it is appropriate to require native load and network customers to assume any additional cost responsibility for the capacity that is reserved for their future use. In response to CCEM's concerns, we recognize that offering load-based network service and reservation-based point-to-point service in one tariff may have disadvantages in that it may result in less than optimal use of the system if a utility overestimates it load. However, by requiring that available capacity reserved for native load be posted on OASIS and be available to others except when actually needed to serve native load, we believe Order No. 888 substantially relieves the incentive to over-reserve for native load and goes a long way toward assuring full and efficient use of the system. With regard to the concern raised by VA Com, the transmission provider has an ongoing duty to plan and construct Docket Nos. RM95-8-001 -138- and RM94-7-002 its system in a prudent manner in order to meet all of its firm service obligations. We also reiterate that public utilities may reserve existing transmission capacity needed for native load growth and network transmission customer load growth reasonably forecasted within the utility's current planning horizon. [141/] There is a risk of under- or over-projecting the transmission needs of native load and network customers, and the native load and network customers' cost responsibilities reflect this additional risk. In response to VA Com's request, we note that nothing in our regulations prohibits a state commission from overseeing a utility's retail native load growth projections. Finally, concerns regarding the accuracy of load growth projections for native load and network customers may be raised when a transmission service agreement is filed with the Commission or in a separate section 206 proceeding. 6. Capacity Reassignment In the Final Rule, the Commission concluded that a public utility's tariff must explicitly permit the voluntary reassignment of all or part of a holder's firm transmission capacity rights to any eligible customer. 142/ FERC Stats. & Regs. at 31,694; mimeo at 172. / FERC Stats. & Regs. at 31,696; mimeo at 178-79. Docket Nos. RM95-8-001 -139- and RM94-7-002 (1) Reassignable Transmission Services The Commission concluded that point-to-point transmission service should be reassignable, but that network transmission service is not reassignable. 143/ (2) Terms and Conditions of Reassignments a. General In effecting a reassignment, the Commission found that the assignor may deal directly with an assignee without involvement of the transmission provider. 144/ Alternatively, the Commission explained that the assignor may request the transmission provider to effect a reassignment on its behalf, in which case the transmission provider must post the available capacity on its OASIS and assure that any revenues associated with the reassignment are credited to the assignor. The Commission further found that, among other things, any assignment must be posted on the transmission provider's OASIS within a reasonable time after its effective date. b. Contractual Obligations The Commission concluded that while assignors and assignees may contract directly with each other, the assignor will remain obligated to the transmission provider and the assignee will be / FERC Stats. & Regs. at 31,696; mimeo at 179. / FERC Stats. & Regs. at 31,696-97; mimeo at 179-80. Docket Nos. RM95-8-001 -140- and RM94-7-002 liable solely to the assignor. 145/ The Commission, however, did permit mutually agreeable alternatives to this approach. c. Price Cap The Commission concluded that the rate for any capacity reassignment must be capped by the highest of: (1) the original transmission rate charged to the purchaser (assignor), (2) the transmission provider's maximum stated firm transmission rate in effect at the time of the reassignment, or (3) the assignor's own opportunity costs capped at the cost of expansion (Price Cap). 146/ Rehearing Requests Scheduling Transmission Service by Assignees CCEM requests that the Commission clarify that an assignee of transmission capacity, or its agent, is permitted to schedule transmission service directly with the transmission provider. Network Transmission Service American Forest & Paper declares that the Commission erred in finding that network service is not reassignable. American Forest & Paper argues that there is no technical reason for the Commission's position. According to American Forest & Paper, the Commission merely perpetuates the myth that in point-to-point transmission the contract actually determines the path of the flow of electrons. In fact, American Forest & Paper argues, the / FERC Stats. & Regs. at 31,697; mimeo at 180-81. / FERC Stats. & Regs. at 31,697; mimeo at 181. Docket Nos. RM95-8-001 -141- and RM94-7-002 only issue is arriving at a nondiscriminatory and equitable price. VT DPS argues that there is no reason network capacity rights cannot be defined during the period of a reassignment as VT DPS suggested in its comments: Section 2.6 of the NorAm NIS Rate Schedule (Appendix B to the Initial NOPR comments of VDPS) is a provision which allows the reassignment of network service. Reassignment under the NorAm tariff would work this way: During the period of the assignment, both the original and replacement customers' network service entitlements are defined as specified contract quantities, the sum of which is equal to the original customer's highest coincident peak load during the 12 months preceding the assignment. During the period of the assignment, that contract quantity, not the actual use of the system by the original and replacement shipper, will be used to determine the two customers' load ratio share responsibility. The original and replacement customers are free to divide responsibility for interim contract demand between them as they see fit. [147/] PA Coops argue that the Commission failed to explain why network customers have no capacity rights and points to a statement in Order No. 888 that network customers "should not lose their rights to firm capacity" as being inconsistent with the Commission's conclusion with respect to the reassignment of network service. AMP-Ohio asserts that absent an ongoing pass-through to network customers of the revenue credits associated with sales of VT DPS at 47-48; see also Valero at 29-31. Docket Nos. RM95-8-001 -142- and RM94-7-002 point-to-point service, the Commission should permit the reassignment of unused transmission capacity by network customers. TDU Systems argue that the Commission should permit the assignment of a network customer's right to network transmission service for certain specific purposes. In particular, TDU Systems state that the Commission should permit assignment to allow a customer to coordinate, jointly operate, or pool its system with the systems of other local and regional network customers. TDU Systems argue that this provides an opportunity to maximize efficiencies without presenting the complication that the Commission has perceived with respect to the reassignment of point-to-point transmission capacity. Price Cap EEI asserts that the Commission's price cap creates several problems: (1) non-comparable treatment because transmission providers must credit revenues, but resellers can keep the revenues; (2) allowing sale at a price higher than paid could encourage speculation and hoarding; and (3) the transmitting utility's maximum stated rate should not include the utility's opportunity costs. CCEM argues that transmission customers that are not transmission providers or affiliates of transmission providers should be freed from the price cap. CCEM claims that in a secondary market at market-based prices, opportunity costs can be communicated and lost opportunity costs averted. Docket Nos. RM95-8-001 -143- and RM94-7-002 NRECA believes that the price cap provision that permits an assignor to assign capacity at its own opportunity costs (capped at the cost of expansion) may provide firm point-to-point customers a strong economic incentive to buy up substantial firm capacity for speculative purposes and argues that this provision should be eliminated. NRECA also argues that this provision presents difficult rate substantiation questions when the assignor is not a public utility. Further, NRECA and SoCal Edison note that section 23.1 of the tariff does not include the cap at the cost of expansion. Calculation of Assignor's Opportunity Costs SoCal Edison asserts that the Commission must indicate how an assignor should calculate its own opportunity costs with respect to determining the price cap and should indicate that an assignor must abide by the same standard for recovering opportunity costs as the transmission provider. Carolina P&L also asserts that assignors must be held to the same standard as transmission providers when calculating opportunity costs. Carolina P&L further explains that if the opportunity costs are based on the cost of foregone transactions, the assignor should be required to post the price on OASIS. Carolina P&L also asks that the Commission clarify how an assignor is to calculate its own opportunity costs. In particular, Carolina P&L asks if an assignor is limited to recovering the opportunity costs to which it is subject under the transmission provider's tariff or can the assignor forfeit the Docket Nos. RM95-8-001 -144- and RM94-7-002 transaction underlying the transmission service and call the resulting difference an opportunity cost? Resellers into the Secondary Market CCEM argues that the Commission should free resellers, "who but-for the resell would not be public utilities," from regulation as public utilities or should minimize the regulatory burden on them. 148/ It further asserts that resellers that are not transmission providers should be treated like unaffiliated power marketers and granted waivers from public utility regulations. Participation in the Secondary Market CCEM argues that those customers that are permitted to continue to take service under existing agreements "should be excluded from participating in the secondary market until such time as they agree to comply with the pro forma tariff." (CCEM (889 rehearing request) at 7). Commission Conclusion Scheduling Transmission Service by Assignee The pro forma tariff does not prohibit the assignee of transmission capacity from scheduling transmission service with the transmission provider. In fact, the tariff provides that "the Assignee will be subject to all terms and conditions of this Tariff" (tariff section 23.1), which would include the scheduling provision of tariff sections 13.8 and 14.6. CCEM makes this argument in its rehearing request of Order No. 889. Docket Nos. RM95-8-001 -145- and RM94-7-002 Network Transmission Service We reaffirm our conclusion that network transmission service is not reassignable in the secondary market. 149/. Parties have raised no new arguments that would persuade us otherwise. PA Coops are nevertheless correct in noting that network customers do have rights to firm capacity. However, a network customer s rights (as well as the transmission provider s planning responsibilities) are defined only in terms of the capacity needed to integrate the network customer's designated resources and its designated loads. These are usage- or load-based rights that are not fixed; they vary as the customer s load varies. Thus, the network customer's capacity rights are not well enough defined to be generally reassignable in the secondary market. 150/ VT DPS proposes a formula for defining a network customer's entitlement that would be operative during the period of an assignment. However, the proposed definition is simply an artifice derived from the load ratio share calculation. The formula does not result in a reassignable capacity right. AMP-Ohio's suggestion regarding the proper treatment of the revenue credits associated with point-to-point service raises a While portions of network transmission service are not reassignable, we would permit the reassignment of a particular network transmission service in its entirety. / We note that the question of how network service may be converted into a service that is reassignable is at issue in the Capacity Reservation Tariff NOPR proceeding in Docket No. RM96-11-000. Docket Nos. RM95-8-001 -146- and RM94-7-002 rate issue that should be addressed in a ratemaking proceeding. However, we note that the proper treatment of such credits does not turn on the assignability of network service. Finally, TDU Systems' recommendation that network service be reassignable only for pooling and coordination purposes is without merit. If customers wish to avail themselves of network service in order to realize benefits associated with joint or coordinated operations with other systems, they can jointly request network service from the transmission provider. To allow customers to opt into and out of network service arrangements under the guise of capacity reassignment would be an abuse of the terms and conditions of the service, which, among other things, requires the transmission provider to plan for the long-term needs of network customers. Price Cap We will also reaffirm our conclusions regarding the price cap applicable to capacity reassignment. We continue to believe that customers must be given limited pricing flexibility in order to achieve the full efficiency and risk management benefits of capacity reassignment. Contrary to the assertions of EEI and NRECA, we are not persuaded that allowing the customer to reassign capacity at a rate higher than it paid, as a result of charging its own opportunity costs, will lead to speculation and hoarding. As a condition of the open access tariff, the Commission will require customers reassigning transmission capacity to fully develop Docket Nos. RM95-8-001 -147- and RM94-7-002 their method for calculating opportunity costs and provide all information necessary to their customers in order to verify such costs. Further, we reiterate that the potential for hoarding can be mitigated by (1) allowing the transmission provider to sell any reserved but unscheduled point-to-point transmission capacity on a non-firm basis, and (2) having a price cap, which allows the reseller to charge no more than a cost-based rate, including its own opportunity cost for reassigned capacity. Therefore, the reseller will find that reassigning transmission capacity to others with higher valued uses will be in its economic self interest. In addition, any hoarding of capacity that has anticompetitive effects can be addressed under section 206. We deny CCEM's request to remove the price cap for transmission customers that are not transmission providers or affiliates of transmission providers. As we stated in the Final Rule, we are unable to conclude that competition in the market for reassigned transmission capacity is sufficient to prevent assignors from exerting market power. Thus, we believe the opportunity cost cap should be retained. 151/ Finally, in response to EEI's request, we clarify that "the transmission provider's maximum stated firm transmission rate in effect at the time of the reassignment" does not include the We note that if the assignor is a public utility it will in any event have to file a rate schedule for the re-sale (reassignment) of unbundled transmission. Docket Nos. RM95-8-001 -148- and RM94-7-002 transmission provider's opportunity costs. 152/ Also, as suggested by NRECA and others, section 23.1 of the pro forma tariff will be revised to indicate that the assignor's opportunity costs are capped at the transmission provider's cost of expansion. Calculation of Assignor's Opportunity Costs In response to the requests of SoCal Edison and Carolina P&L, we clarify that the assignor's opportunity costs should be measured in a manner that is analogous to that used to measure the transmission provider's opportunity costs. That is, an assignor's opportunity costs include: (1) increased costs associated with changes in power purchases or in the dispatch of generating units necessary to accommodate a reassignment, and (2) decreased revenues that arise from the assignor having to reduce sales of power in order to effect the reassignment. 153/ Regarding the calculation of opportunity costs, we intend to hold assignors to the same general standard as transmission providers. Thus, consistent with our treatment of transmission providers, we will not require assignors to post their opportunity costs on the OASIS or to make the costs routinely We also reject as unsupported EEI's comparability argument that transmission providers must treat any transmission service revenues as a revenue credit, but the reseller may keep any transmission resale revenues. In response to Carolina P&L's request, we clarify that the assignor is not limited to recovering the opportunity costs to which it is subject under the transmission provider's tariff, i.e., the transmission provider's opportunity costs. Docket Nos. RM95-8-001 -149- and RM94-7-002 available to the public. We will, however, require assignors to describe to their assignees their derivation of opportunity costs in sufficient detail to satisfy the assignees that the price charged does not exceed the higher of (i) the original rate paid by the reseller, (ii) the transmission provider's maximum rate on file at the time of the assignment, or (iii) the reseller's opportunity cost, as set forth in section 23.1 of the tariff. Resellers into the Secondary Market The issues raised by CCEM with respect to the regulation of resellers into the secondary market are fact specific and, accordingly, we will address such issues on a case-by-case basis. Participation in the Secondary Market We reject CCEM's argument that those customers that are permitted by Order No. 888 to continue to take service under existing agreements should be denied access to the secondary market until they agree to comply with the pro forma tariff. CCEM's approach would undermine our determination not to generically abrogate existing agreements, and would slow the growth of the secondary market by limiting the number of eligible participants. 7. Information Provided to Transmission Customers In the Final Rule, the Commission concluded that all necessary transmission information, as detailed in the OASIS Final Rule, must be posted on an OASIS. 154/ FERC Stats. & Regs. at 31,698; mimeo at 183-84. Docket Nos. RM95-8-001 -150- and RM94-7-002 Rehearing Requests No requests for rehearing addressed this matter. 8. Consequences of Functional Unbundling a. Distribution Function In the Final Rule, the Commission concluded that the additional step of functionally unbundling the distribution function from the transmission function is not necessary at this time to ensure non-discriminatory open access transmission. 155/ Rehearing Requests No requests for rehearing addressed this matter. b. Retail Transmission Service In the Final Rule, the Commission explained that although the unbundling of retail transmission and generation, as well as wholesale transmission and generation, would be helpful in achieving comparability, it did not believe it was necessary. 156/ The Commission further explained that the matter raises numerous difficult jurisdictional issues that are more appropriately considered when the Commission reviews unbundled retail transmission tariffs that may come before the Commission in the context of a state retail wheeling program. Rehearing Requests CCEM argues that all transmission must be unbundled, including currently bundled retail transmission service, because FERC Stats. & Regs. at 31,699; mimeo at 186. FERC Stats. & Regs. at 31,699-700; mimeo at 188. Docket Nos. RM95-8-001 -151- and RM94-7-002 failure to do so is inconsistent with the Commission's assertion of jurisdiction over the rates, terms, and conditions of unbundled interstate transmission to retail customers and authority to address retail stranded costs through its jurisdiction over such costs. CCEM notes that the Commission found it necessary in Order No. 636 to unbundle the pipeline's direct retail sales to achieve comparability (CCEM cites FPC v. Conway Corp., 426 U.S. 271, 273 (1976) and Mississippi River Transmission Corp. v. FERC, 969 F.2d 1215 (D.C. Cir. 1992) for the proposition that the Commission has jurisdiction over all interstate transmission). NY Municipal Utilities and American Forest & Paper also argue that the Commission erred in not requiring the unbundling of the transmission component of retail sales. American Forest & Paper believes that such unbundling will facilitate competition by making the generation price transparent to all participants. Commission Conclusion We disagree with those entities that argue that the Commission erred in not requiring the unbundling of all transmission service, including the unbundling of transmission from retail service. As we explained in the Final Rule: when transmission is sold at retail as part and parcel of the delivered product called electric energy, the transaction is a sale of electric energy at retail. Under the FPA, the Commission's jurisdiction over sales of electric energy extends only to wholesale sales. However, when a retail transaction is broken into two products that are sold separately (perhaps by two different Docket Nos. RM95-8-001 -152- and RM94-7-002 suppliers: an electric energy supplier and a transmission supplier), we believe the jurisdictional lines change. In this situation, the state clearly retains jurisdiction over the sale of the power. However, the unbundled transmission service involves only the provision of "transmission in interstate commerce" which, under the FPA, is exclusively within the jurisdiction of the Commission. Therefore, when a bundled retail sale is unbundled and becomes separate transmission and power sales transactions, the resulting transmission transaction falls within the Federal sphere of regulation. [157/] Nor is our decision not to unbundle transmission from retail generation service inconsistent with our assertion of jurisdiction over unbundled interstate transmission to retail customers. As we explained in the Final Rule and described further above, we have exclusive jurisdiction under the FPA over "transmission in interstate commerce" by public utilities, which includes the unbundled interstate transmission component of a previously bundled retail transaction. 158/ Our assertion of jurisdiction in such a situation arises only if the retail transmission in interstate commerce by a public utility occurs voluntarily or as a result of a state retail program. c. Transmission Provider 1. Taking Service Under the Tariff FERC Stats. & Regs. at 31,781; mimeo at 430-31 (emphasis in original). As discussed in Section IV.I., infra, we believe this jurisdictional determination is supported by the statute and the case law, including the D.C. Circuit's recent decision in United Distribution Companies v. FERC, 88 F.3d 1105 (1996). FERC Stats. & Regs. at 31,781; mimeo at 431. Docket Nos. RM95-8-001 -153- and RM94-7-002 In the Final Rule, the Commission concluded that public utilities must take all transmission services for wholesale sales under new requirements contracts and new coordination contracts under the same tariff used by others (eligible customers). 159/ For sales and purchases under existing bilateral economy energy coordination agreements, the Commission gave an extension until December 31, 1996 for public utilities to take transmission service under the same tariff used by others. The Commission also gave an extension of time to December 31, 1996 for certain existing power pooling and other multi-lateral coordination agreements to comply with this requirement. 160/ Rehearing Requests This issue is discussed above in Section IV.C.1.b. 2. Accounting Treatment In the Final Rule, the Commission directed utilities to account for all uses of the transmission system and to demonstrate that all customers (including the transmission FERC Stats. & Regs. at 31,700-01; mimeo at 191. See also discussion infra at Section IV.G. Section 1.11 (and Section 13.3). By notice issued September 27, 1996 in Docket Nos. RM95-8- 000 and RM94-7-001, the Commission revised the compliance dates. It required joint pool-wide section 206 compliance tariffs to be filed no later than December 31, 1996, and pool members to begin taking service under the tariffs 60 days after the section 206 filing. It also gave members of public utility holding companies an extension of time to take service under their system-wide tariff until no later than March 1, 1997. Docket Nos. RM95-8-001 -154- and RM94-7-002 provider's native load) bear the cost responsibility associated with their respective uses. 161/ Rehearing Requests No requests for rehearing addressed this matter. D. Ancillary Services In the Final Rule, the Commission concluded that the following six ancillary services must be included in an open access transmission tariff: (1) Scheduling, System Control and Dispatch Service; (2) Reactive Supply and Voltage Control from Generation Sources Service; (3) Regulation and Frequency Response Service; (4) Energy Imbalance Service; (5) Operating Reserve - Spinning Reserve Service; and (6) Operating Reserve - Supplemental Reserve Service. 162/ The Commission adopted NERC's recommendations for ancillary service definitions and descriptions with modifications. 163/ The Commission determined that the transmission provider must provide and the transmission customer must purchase from the transmission provider the first two services, subject to conditions set out in the Rule. The transmission provider must offer the remaining four services to the transmission customer FERC Stats. & Regs. at 31,703; mimeo at 198. FERC Stats. & Regs. at 31,703-04; mimeo at 199. In comments on the proposed rule, NERC identified additional interconnected operations services that it indicated may be necessary for reliability. As discussed in the Final Rule, we do not require the transmission provider to be the default provider of these other services. Docket Nos. RM95-8-001 -155- and RM94-7-002 serving load in the transmission provider's control area. The transmission customer that is serving load in the transmission provider's control area must acquire these four services from the transmission provider or a third party, or self provide. 1. Specific Ancillary Services a. Scheduling, System Control and Dispatch Service In the Final Rule, the Commission concluded that Scheduling, System Control and Dispatch Service is necessary to the provision of basic transmission service within every control area. 164/ The Commission further stated that this service can be provided only by the operator of the control area in which the transmission facilities used are located. Rehearing Requests Wisconsin Municipals asks that the Commission eliminate Schedule 1 (Scheduling, System Control and Dispatch Service) as an ancillary service and require transmission providers to include these costs in the transmission revenue requirement so the transmission provider cannot recover these costs twice. Alternatively, Wisconsin Municipals asks that, if customers do their own scheduling through an electronic data link, the charge for scheduling and dispatch be waived. FERC Stats. & Regs. at 31,716; mimeo at 238. Docket Nos. RM95-8-001 -156- and RM94-7-002 Commission Conclusion We disagree with Wisconsin Municipals that we should eliminate this ancillary service and include its costs with the transmission revenue requirement. Scheduling requires action by both the customer who provides information about a transaction and the control area that evaluates and accepts (schedules) the transaction. If a transmission provider allows a transmission customer to supply its schedules through an electronic data link, it is merely offering an alternate method of providing the transaction information required. The control area must still decide whether it can schedule a transaction. Further, scheduling a transaction is only one aspect of Scheduling, System Control and Dispatch Service. A control area must also dispatch generating resources to maintain generation/load balance and maintain security during the transaction. Only the control area operator can perform these functions. A transmission provider must unbundle the cost of these functions, including scheduling, from its base transmission rate. This requirement to unbundle ancillary services costs from the base transmission rate ensures that double recovery of scheduling costs will not occur. b. Reactive Supply and Voltage Control from Generation Sources Service In the Final Rule, the Commission concluded that Reactive Supply and Voltage Control from Generation Sources Service is necessary to the provision of basic transmission service within Docket Nos. RM95-8-001 -157- and RM94-7-002 every control area. 165/ Although a customer is required to take this ancillary service from the transmission provider or control area operator, the Commission stated that a customer may reduce the charge for this service to the extent it can reduce its requirement for reactive power supply. Rehearing Requests NRECA and TDU Systems ask that Schedule 2 of the tariff, Reactive Supply and Voltage Control from Generation Sources Service, be modified to reflect that generation facilities outside a control area can provide reactive power. They argue that parties other than the transmission provider and the transmission customer are able to supply reactive power. Similarly, Santa Clara and Redding ask the Commission to revise Schedule 2 to require the transmission provider to offer this service, but to allow the transmission customer to arrange for this service through a purchase from the transmission provider, self-provision, or purchases from third parties. 166/ Blue Ridge also argues that the Commission should permit self-supply or other local supply when it is feasible and economic to do so. APPA, Santa Clara, Redding and Cajun point out an inconsistency between Schedule 2 and the preamble. They assert that Schedule 2 of the tariff should be revised to reflect the preamble language that allows a transmission customer to supply FERC Stats. & Regs. at 31,716-17; mimeo at 239. See also Cajun. Cajun notes that it does and could continue to provide at least a portion of reactive power. Docket Nos. RM95-8-001 -158- and RM94-7-002 at least a portion of its reactive power service. California DWR says that it is capable of providing Reactive Supply and Voltage Control from Generation Sources Service and that mandating that it purchase this ancillary service makes no sense. California DWR asks the Commission to clarify that it is not required to purchase this ancillary service. TAPS asks the Commission to make clear that (1) customer-owned generation facilities that are available to supply reactive power to the transmission provider's transmission system receive a credit, (2) the extent of customer-supplied reactive power may be sufficient to eliminate the need for a separate reactive power charge paid to the transmission provider, and (3) customer-owned generation outside the control area may be eligible for a credit if it is located nearby where it can provide reactive support for the transmission provider's transmission system. 167/ TAPS further asserts that reactive supply service should be viewed not on a transaction basis but on a gridwide or regionwide basis. Under this approach, according to TAPS, payments would be based on whether the user supplies more than it uses or uses more than it supplies. Commission Conclusion Control area operators use sources of reactive support to control voltage and maintain a stable power supply system. Because of the limited ability to transmit reactive power, these See also APPA. Docket Nos. RM95-8-001 -159- and RM94-7-002 facilities must be available at or near the point of need. Therefore, reactive power support, and hence the facilities able to provide (or absorb) reactive power, must be distributed throughout the transmission system for the reliable operation of the power system. Over- or under-supply of reactive power at other points in the network do not contribute to a stable system and could harm the reliability of the system. Although we agree with NRECA and TDU Systems that generation resources just outside the boundaries of a control area may provide some reactive support within the control area, the control area operator must be able to control the dispatch of reactive power from these generating resources. Accordingly, we will modify Schedule 2 to refer to generating facilities that are under the control of the control area operator instead of in the control area. The transmission customer's service agreement should specify the generating resources made available by the transmission customer that provide reactive support. As noted in the Final Rule, a transmission customer can reduce (but not eliminate completely) the reactive supply and voltage control needs and costs that its transaction imposes on the transmission provider's system. For example, a customer who controls generating units equipped with automatic voltage control equipment may be able to use those units to help control the voltage locally and reduce the reactive power requirement of the Docket Nos. RM95-8-001 -160- and RM94-7-002 transaction. 168/ However, if these units are not always available or are not subject to the direction of the control area operator, their occasional use may not reduce the investment required by the control area operator in reactive power facilities. It merely reduces temporarily the cost of operating these facilities. Consistent with this understanding, we will modify Schedule 2 of the tariff to allow a transmission customer to supply at least part of the reactive power service it requires. We will continue to require reactive power service to be provided by and purchased from the transmission provider. However, a transmission customer may satisfy part of its obligation through self-provision or purchases from generating facilities under the control of the control area operator. The transmission customer's service agreement should specify all reactive supply arrangements. We deny the California DWR and TAPS request that customer-owned generation facilities that are available to supply reactive power should automatically receive a credit. However, as the Final Rule states, a customer may reduce the charge for this service to the extent it can reduce its requirement for reactive power supply. We do not believe a transmission customer can satisfy all of its reactive requirements or allow the transmission provider to avoid investment in reactive power The location and operating capabilities of the generator will affect its ability to reduce reactive power requirements. Docket Nos. RM95-8-001 -161- and RM94-7-002 related facilities. Concerning the other request of TAPS, we will not require that the supply of reactive power be on a gridwide or regionwide basis. Because reactive power must be supplied near the point of need, we are not persuaded that gridwide supply is feasible. c. Energy Imbalance Service In the Final Rule, the Commission concluded that Energy Imbalance Service must be offered for transmission within and into the transmission provider's control area to serve load in the area. 169/ However, the Commission noted, a transmission customer can reduce or eliminate the need for energy imbalance service in several ways. Energy Imbalance Service is provided when the transmission provider makes up for any difference that occurs over a single hour between the scheduled and the actual delivery of energy to a load located within its control area. For minor hourly differences between the scheduled and delivered energy, the transmission customer is allowed to make up the difference within 30 days (or other reasonable period generally accepted in the region) by adjusting its energy deliveries to eliminate the imbalance. A minor difference is one for which the actual energy delivery differs from the scheduled energy by less than 1.5 percent, except that any hourly difference less than one megawatt-hour is also considered minor. Thus, the Final Rule FERC Stats. & Regs. at 31,717; mimeo at 240. Docket Nos. RM95-8-001 -162- and RM94-7-002 established an hourly energy deviation band of +/- 1.5 percent (with a minimum of 1 MW) for energy imbalance. The transmission customer must compensate the transmission provider for an imbalance that falls outside the hourly deviation band and for accumulated minor imbalances that are not made up within 30 days. (1) Description of Energy Imbalance Rehearing Requests North Jersey asserts that the definitions of Energy Imbalance Service and Backup Supply Service are conflicting and need clarification. North Jersey proposes that Energy Imbalance Service be clarified to state that a transmission provider will be required to supply power to a customer "within the dispatch period of the transmission provider's tariff." It states that this assures power when a customer is unable to change its nominations to match its generation capabilities. On the other hand, North Jersey states that Backup Supply Service should be the supply of power for a period longer than the tariff dispatch period. NIMO asserts that the Commission should recognize that there is another type of Energy Imbalance Service. If a generator is located in one control area, but transfers the power to load in another control area, there is a potential mismatch between the amount of power scheduled for delivery by the generator and the amount it actually provides to the operator of the control area where it is located. Docket Nos. RM95-8-001 -163- and RM94-7-002 Nebraska Public Power District (NPPD) states that allowing third parties to provide Energy Imbalance Service and Regulation and Frequency Response Service could jeopardize system reliability. It argues that the transmission provider must have the right to approve the third party provider of these services and the right to physically meter the loads located out of the transmission provider's control area or otherwise monitor these services to be assured that they are provided satisfactorily. NCMPA argues that because of the potential for abuse, the Commission should grant an exemption from an energy imbalance charge if the source of the energy shortfall is a generating resource that has been turned over to the transmission provider's dispatching control for meeting control area requirements. Commission Conclusion We clarify that Energy Imbalance Service is used to supply energy for mismatches between scheduled deliveries and actual loads that may occur over an hour. We do not intend it to be used as a substitute for operating reserves when there is an outage of generation supply or transmission. The Final Rule states that if a customer uses either type of operating reserve, it must expeditiously replace the reserve with backup power to reestablish required minimum reserve levels. 170/ Order No. 888 imposes no obligation on the transmission provider to furnish replacement power on a long-term basis if the customer loses its source of supply. Docket Nos. RM95-8-001 -164- and RM94-7-002 Order No. 888 specifies that there is no obligation on the transmission provider to provide power to the customer for a "time longer than specified in the tariff" for the customer's own backup supply to be made available. 171/ The order also states that "any arrangements for the supply of such service [i.e., Backup Supply Service] by the transmission provider should be specified in the customer's service agreement." 172/ We revise the first statement to clarify that the transmission customer's service agreement, not the tariff, should specify any arrangements for backup service by the transmission provider, including the time within which backup power supply will be made available. The time should correspond to the time necessary to restore operating reserves that is generally accepted in the region and consistently followed by the transmission provider. NIMO asserts that two types of energy imbalance can occur if the generator and the load are in different control areas. These are (1) a mismatch between the energy scheduled to be received in the load's control area and the actual hourly energy consumed by the load, and (2) a mismatch between energy scheduled for delivery from the generator's control area and the amount of energy actually generated in the hour. The Energy Imbalance Service in the Final Rule applies to the first case only. Although we agree that the second type of mismatch can occur, we FERC Stats. & Regs. at 31,711; mimeo at 222. FERC Stats. & Regs. at 31,711; mimeo at 223. Docket Nos. RM95-8-001 -165- and RM94-7-002 will not designate as Energy Imbalance Service a mismatch between energy scheduled and energy generated. Energy Imbalance Service in this Rule applies only to the obligation of the transmission provider to correct the first type of energy mismatch, one caused by load variations. In general, the amount of energy taken by load in an hour is variable and not subject to the control of either a wholesale seller or a wholesale requirements buyer. The Energy Imbalance Service that we require as our ancillary service has a bandwidth appropriate for load variations and should have a price for exceeding the bandwidth that is appropriate for excessive load variations. Although NIMO states correctly that, where two control areas are involved, there can also be a mismatch between energy scheduled and energy generated, NIMO has not explained why this mismatch should have the same bandwidth and price as our Energy Imbalance Service. Indeed, we believe it should not. A generator should be able to deliver its scheduled hourly energy with precision. If we were to allow the generator to deviate from its schedule by 1.5 percent without penalty, as long as it returned the energy in kind at another time, this would discourage good generator operating practice. A generation supplier could intentionally generate less power when its generating cost is high and make it up when its cost is lower if the second type of mismatch is included in our Energy Imbalance Service. Instead, a generator will have an interconnection agreement with its transmission provider or control area Docket Nos. RM95-8-001 -166- and RM94-7-002 operator, and we expect that this agreement will specify the requirements for the generator to meet its schedule, and for any consequence for persistent failure to meet its schedule. This agreement will be tailored to the parties' specific standards and circumstances, and, although such arrangements must not be unduly preferential or discriminatory (e.g., must be comparable for all wholesale sellers, including the transmission provider's own wholesale sales), we prefer not to set these standards generically for all parties. 173/ We disagree with NCMPA's argument regarding an exemption from Energy Imbalance Service when the control area operator controls the generating resource. As discussed above and in the Final Rule, energy imbalance results from a mismatch between a scheduled receipt and actual load in the control area of the transmission provider. Energy imbalance can occur if the actual load differs from the scheduled receipt regardless of who controls the generating resource. As specified in the Final Rule, to ensure the reliability of the power system, a transmission customer is obligated to obtain Energy Imbalance Service and Regulation and Frequency Response Many provisions regarding the reliable operation and performance of both generation and load will be included in supply interconnection agreements and transmission customer service agreements. The fact that we have designated six services as necessary to prevent undue discrimination in transmission service should not be interpreted as our having set out a complete set of interconnected operations services and conditions necessary for reliable and orderly bulk power system management. Docket Nos. RM95-8-001 -167- and RM94-7-002 Service for its transactions. We clarify for NPPD that the transmission customer may not decline the transmission provider's offer of these ancillary services unless it demonstrates to the transmission provider that it has acquired the services from another source. This demonstration must show that the customer's alternative arrangement for ancillary services is adequate and consistent with Good Utility Practice. The transmission customer's service agreement should specify any alternative arrangements for the provision of these (or any other) ancillary services. (2) Energy Imbalance Bandwidth As explained above, Schedule 4 (Energy Imbalance Service) of the tariff allows the transmission provider to charge a transmission customer serving load in its control area for taking an amount of energy in any hour that is 1.5 percent more or less than the amount of energy scheduled for that hour. In the pro forma tariff, the minimum amount of energy that can be assessed a charge in an hour is one megawatt-hour. Rehearing Requests Several entities argue that this energy imbalance bandwidth is too narrow and should be increased. 174/ APPA asserts that the narrow bandwidth imposes obligations on the transmission customer that the transmission provider does not impose on E.g., APPA, NRECA, Blue Ridge, Cooperative Power, Wabash, TDU Systems, Redding, TAPS. Docket Nos. RM95-8-001 -168- and RM94-7-002 itself. 175/ TAPS argues that the 1.5 percent bandwidth "makes no sense because it simply imposes a penalty for existence as a small utility." Redding states that the 1.5 percent energy imbalance bandwidth is not appropriate for transmission to a small utility that does not operate a control area. In opposing the narrow bandwidth, TDU Systems notes that metering error is typically within a range of +/- 2 percent. It further argues that it is impossible for smaller systems with low load factors, larger load swings, and the need to change the output quickly for a single unit to operate within the narrow bandwidth. Others assert that a too-narrow bandwidth creates a burdensome level of billings unless schedule changes are permitted more frequently than hourly. 176/ They fear that meeting the 1.5 percent bandwidth would require expensive dynamic scheduling. Some entities recommend a particular alternative bandwidth. 177/ TDU Systems suggests a sliding scale as follows. There would be a bandwidth of +/- 5 percent of scheduled energy for transactions of 500 MW or less, decreasing to +/- 1.5 percent for transactions of 5,000 MW or more, with a minimum bandwidth of +/-5 MWh in all cases. Alternatively, TDU Systems says that network customers could be entitled to a bandwidth equal to their load ratio share of the amount (not percentage) of their See also TDU Systems. E.g., NRECA, Blue Ridge, Cooperative Power, Wabash. E.g., TDU Systems, TAPS, NRECA, Wabash, Redding. Docket Nos. RM95-8-001 -169- and RM94-7-002 transmission provider's inadvertent interchange, again subject to a minimum of 5 MWh. TAPS recommends that the deviation bandwidth be changed to 6 percent of the transmission customer's daily peak demand, with a minimum bandwidth of 4 MWh. NRECA proposes an alternative approach (previously set forth in its comments on the proposed rule): a customer's "energy compensation balance" should be determined for each hour based on the net energy deviation from the "bandwidth base," which NRECA defines as the greater of (i) the customer's total on-line and available generator capacity associated with the generation dispatched, or (ii) the sum of a customer's maximum hourly demands at each of its recipient interfaces. NRECA states that its proposal sets forth separate compensation based on whether there is an overdelivery or an underdelivery outside a five percent bandwidth. Wabash argues that the Commission should use a deviation bandwidth based on a period other than a single hour; for example, use a known historical number, such as the maximum hourly load during the previous calendar year. Wabash states that if a larger bandwidth is not adopted, the Commission should permit a transmission customer that is purchasing spinning or supplemental operating reserves as an ancillary service to use those purchases as the basis for an expanded deviation bandwidth. In addition, Wabash asks the Commission to clarify that an imbalance resulting from a system emergency situation caused by loss or failure of facilities should be counted as "inadvertent Docket Nos. RM95-8-001 -170- and RM94-7-002 loads" and repaid in like hours at mutually agreed times and pay-back amounts. Redding points out that the NERC (A2 Criterion) establishes a constant bandwidth for every hour of the year and should be used instead. For energy imbalances of less than 1.5 percent, Schedule 4 of the tariff allows the energy to be returned in kind within 30 days, after which payment must be made. Redding argues that the 30-day period should be deleted. Instead the Commission should follow current industry practice of allowing reasonable deviations to be carried forward into the next month so as to avoid an accounting nightmare. Finally, Redding argues that the bandwidth for network service should apply to the entire network load and not to a "scheduled transaction." Wisconsin Municipals asks the Commission to clarify that if parties have reached a settlement that establishes a wider band, the transmission provider may not use Order No. 888 to avoid this settlement obligation. TAPS argues that any charges for exceeding the bandwidth should be cost-based and compensation should be symmetrical for over- and under-deliveries. 178/ TAPS further argues that the bandwidth should not be applied by transaction, and customers On the other hand, Wabash argues that pursuant to industry practice, overdeliveries should be treated differently than underdeliveries outside the deviation band. It adds that the rate for underdeliveries should be cost-based. Docket Nos. RM95-8-001 -171- and RM94-7-002 should not have to pay for imbalances caused by transmission provider dispatch mistakes. TDU Systems states that public utilities should be placed on notice that they will not be permitted to collect 100 mills per kWh for energy supplied by a customer in excess of its schedules, as some have sought in tariffs already filed. Commission Conclusion Energy Imbalance Service includes a bandwidth to promote good scheduling practices by transmission customers. It is important that the implementation of each scheduled transaction not overly burden others. We do not agree with APPA that the bandwidth imposes an obligation on the transmission customer that the transmission provider does not impose on itself. The Final Rule treats all wholesale customers comparably. The transmission provider must also use its pro forma tariff and apply the same bandwidth for sales to its wholesale customers. Many commenters assert that the energy imbalance bandwidth of +/- 1.5 percent is too narrow and is difficult to meet for small utilities. Several propose an alternative bandwidth or a larger minimum deviation. We believe that the bandwidth included in the Final Rule pro forma tariff is consistent with what the industry has been using as a standard and is as close to an industry standard as anyone can set at this time. However, we will set a larger minimum deviation to meet the needs of small customers. The minimum energy imbalance is now two megawatt- Docket Nos. RM95-8-001 -172- and RM94-7-002 hours per hour (2 MW minimum in the pro forma tariff). This adequately addresses the concerns raised by small utilities because they may exceed the bandwidth without exceeding this minimum. For example, a transmission customer that transfers less than 133 MW (1.5 percent of 133 MW is 2 MW, the minimum energy imbalance) has a larger percentage bandwidth than +/- 1.5 percent. The bandwidth set forth in the pro forma tariff provides a needed incentive for a transmission customer to deliver an amount of energy each hour that is reasonably close to the amount scheduled, while at the same time recognizing the needs of small utilities. To help customers with the difficulty of forecasting loads far in advance of the hour, the Final Rule pro forma tariff permits schedule changes up to twenty minutes before the hour at no charge. By updating its schedule before the hour begins, a transmission customer should be able to reduce or avoid energy imbalance and associated charges. However, we will allow the transmitting utility and the customer to negotiate and file another bandwidth more flexible to the customer, subject to a requirement that the same bandwidth be made available on a not unduly discriminatory basis. We disagree with Wabash's request to require a transmission provider to expand its energy imbalance bandwidth for a transmission customer purchasing spinning and supplemental reserves. Unlike Energy Imbalance Service, which treats deviations between scheduled and actual hourly energy deliveries, spinning and supplemental reserves provide generating capacity Docket Nos. RM95-8-001 -173- and RM94-7-002 that responds to contingency situations (e.g., loss or failure of facilities). Order No. 888 requires a transmission customer to obtain these operating reserve ancillary services for its transactions. Therefore, Wabash is simply requesting a larger energy imbalance bandwidth. We have selected the bandwidth to promote good scheduling practices by transmission customers. A larger bandwidth may introduce poor operating practices that could affect the reliability of the system. If the Energy Imbalance Service bandwidth were larger, energy supplied within this expanded bandwidth could be provided from reserve capacity. Some reserve capacity may not then be available when needed for system reliability. However, as stated in the Final Rule, we will allow a transmission provider to assemble packages of ancillary services (not bundled with basic transmission service) that can be offered at rates that are less than the total of individual charges for the services if purchased separately. 179/ In response to Wabash's other concern, we believe that emergency situations caused by loss or failure of facilities should be addressed in the transmission customer's service agreement (or the generation supplier's separate interconnection agreement) and not as part of Energy Imbalance Service. In response to Redding's statement that the NERC (A2 criterion) establishes a constant bandwidth for imbalances, we note that NERC has set a standard for a kind of deviation that is FERC Stats. & Regs. at 31,719; mimeo at 246. Docket Nos. RM95-8-001 -174- and RM94-7-002 different from our Energy Imbalance Service. NERC's bandwidth is for inadvertent interchange between a control area and all other control areas. Redding has presented no reason that our Energy Imbalance Service bandwidth should be the same as NERC's inadvertent interchange bandwidth. Regarding its concern about the in-kind repayment period, we note that Schedule 4 does not always require a 30-day period for in-kind repayment of energy imbalances; it also permits a term that the transmission provider consistently follows and is generally accepted in the region. In addition, we clarify that the bandwidth for network service applies to the entire network load. With respect to Wisconsin Municipals' request, we clarify that the Final Rule does not require parties to a contract that went into effect prior to July 9, 1996 to stop using a wider bandwidth established by settlement. However, service provided pursuant to a settlement that was expressly approved subject to the outcome of Order No. 888 on non-rate terms and conditions must be revised in the subsequent compliance filing to reflect the language contained in the pro forma tariff. 180/ Subsequent to the compliance tariff filing, public utilities are free to See Order on Non-Rate Terms and Conditions, 77 FERC  61,144 at 61,538 (1996). The Commission explained: Order No. 888 required all tariff compliance filings to contain non-rate terms and conditions identical to the pro forma tariff, with a limited exception for regional practices, and with four attachments where the utility could propose specific inserts. Docket Nos. RM95-8-001 -175- and RM94-7-002 file under section 205 to revise the tariffs (e.g., to reflect various settlement provisions) and customers are free to pursue changes under section 206. 181/ In response to arguments regarding the price of Energy Imbalance Service, we note that the Final Rule intentionally does not provide detailed pricing requirements. We require the transmission provider to determine and apply to the Commission for appropriate rates for Energy Imbalance Service as part of its transmission tariff. Transmission customers may address any disagreements with a specific charge in the company's transmission rate case. 2. Ancillary Services Obligations In the Final Rule, the Commission distinguished two groups or categories of ancillary services: (1) services that the transmission provider is required to provide to all of its basic transmission customers under the tariff, and (2) services that the transmission provider is required to offer to provide only to transmission customers serving load in the provider's control area. The Commission required a transmission provider that operates a control area to provide the first group of ancillary services and the transmission customer to purchase these services from the transmission provider. The Commission required a transmission provider to offer to provide the ancillary services in the second group to transmission customers serving load in the FERC Stats. & Regs. at 31,770 n.514; mimeo at 399 n.514. Docket Nos. RM95-8-001 -176- and RM94-7-002 transmission provider's control area. The Commission required the transmission customer serving load in the transmission provider's area to acquire these services, but allowed the transmission customer to do so from the transmission provider, a third party or self-supply. If the transmission provider is a public utility providing basic transmission service, but is not a control area operator, the Commission allowed the transmission provider to fulfill its obligation to provide, or offer to provide, ancillary services by acting as the customer's agent. In this case, if the control area operator is a public utility, the Commission required the control area operator to offer to provide all ancillary services to any transmission customer that takes transmission service over facilities in its control area whether or not the control area operator owns or controls the facilities used to provide the basic transmission service. a. Obligation of a Control Area Utility Rehearing Requests Carolina P&L asks the Commission to clarify that the transmission provider is not required to provide control area services to another utility operating a control area that simply chooses not to provide for its own control area obligations. It argues that this is not justified in a competitive bulk power market. Maine Public Service asserts that a transmission provider that is not a NERC-recognized control area can provide ancillary Docket Nos. RM95-8-001 -177- and RM94-7-002 services from its own facilities. It asks that the Commission clarify that this is permissible. At a minimum, Maine Public Service states that the Commission must allow transmission providers on a case-by-case basis to establish that they provide ancillary services even if they are not NERC-recognized control areas or do not satisfy the Commission's definition (citing the initial decision in Maine Public Service Company, 74 FERC  63,011 (1996)). Similarly, California DWR states that it has been operating since 1983 as a quasi-control area, self-providing most, if not all, of the ancillary services it uses. It also notes that it provides such services to its utility transmission providers. California DWR argues that it is entitled to appropriate compensation for all ancillary services that it provides to its transmission providers or other parties. Commission Conclusion In response to Carolina P&L, we clarify that the Final Rule does not require a control area operator to provide control area services within another control area. Except for the ancillary service called Scheduling, System Control and Dispatch, 182/ the Final Rule does not preclude a As NERC and others pointed out in their comments on the proposed rule, this service can be provided only by the operator of the control area in which the transmission facilities used are located. FERC Stats. & Regs. at 31,716; mimeo at 238. Docket Nos. RM95-8-001 -178- and RM94-7-002 transmission provider that is not a control area operator from offering ancillary services to its transmission customers. Order No. 888 requires that a transmission customer obtain or provide ancillary services for its transactions. If a transmission customer can self-supply a portion of its requirement for ancillary services (other than Scheduling, System Control, and Dispatch Service), it should pay a reduced charge for these services. As with the transmission provider, a third party may offer ancillary services voluntarily to other customers if technology permits. However, simply supplying some duplicative ancillary services (e.g., providing reactive power at low load periods or providing it at a location where it is not needed) in ways that do not reduce the ancillary services costs of the transmission provider or that are not coordinated with the control area operator does not qualify for a reduced charge. The transmission customer must make separate arrangements with the transmission provider or control area operator to supply its own ancillary services and specify such arrangements in its service agreement. b. Obligation to Provide Dynamic Scheduling Dynamic scheduling electronically moves a generation resource or load from the control area in which it is physically located to a new control area. In the Final Rule, the Commission concluded that it would not require the transmission provider to offer Dynamic Scheduling Service to a transmission customer, although a transmission provider may do so voluntarily. If the Docket Nos. RM95-8-001 -179- and RM94-7-002 customer wants to purchase this service from a third party, the Commission stated that the transmission provider should make a good faith effort to accommodate the necessary arrangements between the customer and the third party for metering and communication facilities. Rehearing Requests AMP-Ohio asks that the Commission clarify that the transmission provider is required to provide dynamic scheduling "to the extent a transmission customer needs and is willing to pay for reasonably priced dynamic scheduling in order to support its operations, including in order to integrate its loads and resources located in more than one control area." Wisconsin Municipals also asks the Commission to clarify that dynamic scheduling must be provided if technically feasible and permitted by regional reliability practices. Wisconsin Municipals further asks that the Commission clarify that if the transmission provider has agreed to provide dynamic scheduling in a settlement, it may not use its Order No. 888 implementation filing to void this obligation. EEI asks that the Commission clarify the residual obligations of a control area utility to an entity that electronically leaves the control area via dynamic scheduling. Docket Nos. RM95-8-001 -180- and RM94-7-002 Commission Conclusion In response to Amp-Ohio and Wisconsin Municipals, we note that dynamic scheduling is not a required ancillary service in Order No. 888, and we do not require a transmission provider to offer this service. However, nothing in the Final Rule precludes a transmission provider from offering it as a separate service. Furthermore, offering dynamic scheduling to integrate loads and resources in more than one control area is also not required. Wisconsin Municipals' argument with respect to prior settlements has been previously addressed in Section IV.D.1.c.(2) (Energy Imbalance Service). We clarify for EEI that, once dynamic scheduling is arranged, each of the two control areas has ancillary service responsibilities under the Rule. The reactive power obligations of the original control area remain and cannot be completely supplied by distant sources. Order No. 888 requires, in the case of dynamic scheduling, both control areas to provide the first two ancillary services in their respective control areas, that is, (1) Scheduling, System Control, and Dispatch Service and (2) Reactive Supply and Voltage Control from Generation Sources Service, and the new control area to offer the remaining ancillary services to the dynamically scheduled entity. In addition, the actual energy transfers between the two control areas will require basic transmission service. We expect that any additional obligations of a control area operator to an entity that electronically leaves the control area via dynamic Docket Nos. RM95-8-001 -181- and RM94-7-002 scheduling, such as backup procedures for the failure of telemetering equipment, will be set out in the transmission customer's service agreement. c. Obligation As Agent Rehearing Requests A transmission provider must act as an agent to help the customer acquire ancillary services if the transmission provider cannot provide them itself. NRECA asks whether a non-public utility may collect a reasonable fee for its agency services in fulfilling its reciprocity requirement. Commission Conclusion While the Final Rule does not allow a public utility transmission provider acting as an ancillary services agent to collect a fee for its agency service, we do not have similar authority to deny a non-public utility the opportunity to charge a fee for providing an agency service. However, to the extent a non-public utility seeks to collect an agency fee from a public utility, it must meet our comparability requirements and charge a comparable fee to its own wholesale merchant function. 3. Miscellaneous Ancillary Services Issues a. Transmission Provider as Ancillary Services Merchant Rehearing Requests Allegheny asserts that the sale of power in connection with ancillary services would make the transmission provider a wholesale merchant under the Commission's standards of conduct Docket Nos. RM95-8-001 -182- and RM94-7-002 (citing section 37.3 of the Commission's Regulations). Allegheny asks that the Commission clarify that a transmission provider's employee responsible for providing ancillary services is not engaged in a wholesale merchant service that would trigger the functional separation requirement. Commission Conclusion We clarify that the transmission provider's sale of ancillary services associated with its provision of basic transmission service is not a wholesale merchant function for purposes of Order No. 889. This is because the provision of ancillary services is essential for providing transmission service. However, the sale of ancillary services not associated with the transmission provider's provision of basic transmission service is a wholesale function for purposes of Order No. 889. Thus, if an employee is marketing an ancillary service independent of the transmission provider's obligations to provide transmission service, i.e., as a third party to another transmission provider's basic transmission service customer, the employee would be providing a wholesale merchant function and the Order No. 889 Standards of Conduct apply. b. QF Receipt of Ancillary Services Rehearing Requests North Jersey argues that the Commission did not engage in reasoned decisionmaking in ruling that Real Power Loss Service is not an ancillary service. It asserts that this service must be provided by the transmission provider. North Jersey further Docket Nos. RM95-8-001 -183- and RM94-7-002 argues that, because the Commission describes the furnishing of real power loss as a sale of power, this could prevent a PURPA qualifying facility (QF) from being a transmission service customer. North Jersey states that a QF faces power purchase and resell restrictions under the Commission's regulations. North Jersey asks that the Commission find that receipt of Real Power Loss Service from a third party to complete a transmission transaction is not a purchase and resale of power. In addition, North Jersey requests that the Commission clarify that receipt of ancillary services by a QF does not constitute a purchase and resale of electric power that would jeopardize its status as a QF (clarification also requested in ER95-791-000). 183/ Commission Conclusion The Commission disagrees with North Jersey's assertion that Real Power Loss Service should be an ancillary service that must be provided by the transmission provider. As stated in the Final Rule, it is not necessary for the transmission provider to supply Real Power Loss Service to effect a transmission service transaction. Although the transmission customer is responsible for losses associated with its transmission service, supply of losses is purely a generation service that can be (1) self supplied; (2) purchased from the transmission provider, if it offers this service; or (3) purchased from a third party. In Docket No. ER95-791 the Commission ruled that this issue was not part of the hearing and that North Jersey should file for a declaratory order to resolve the matter. Docket Nos. RM95-8-001 -184- and RM94-7-002 We clarify that a QF arrangement for receipt of Real Power Loss Service or ancillary services from the transmission provider or a third party for the purpose of completing a transmission transaction is not a sale-for-resale of power by a QF transmission customer that would violate our QF rules. c. Pricing of Ancillary Services In the Final Rule, the Commission concluded that it would consider ancillary services rate proposals on a case-by-case basis and offered general guidance on ancillary services pricing principles. 184/ Rehearing Requests NRECA and TDU Systems argue that there should be truth in transmission pricing so that the rate is clearly identified as including or excluding ancillary services. AEP asserts that if a purchaser of ancillary services has alternative suppliers of these services, then either the transmission provider should not be required to provide those services or it should be able to charge market rates for them. Otherwise, according to AEP, the market is skewed in favor of the customer. Illinois Power argues that if a transmitting utility demonstrates that it incurs incremental costs from its obligation to offer to provide the required ancillary services, it should be FERC Stats. & Regs. at 31,720-21; mimeo at 250-52. Docket Nos. RM95-8-001 -185- and RM94-7-002 permitted to recover such costs through an adjustment to base transmission rates. Commission Conclusion The Final Rule requires unbundling of individual ancillary services from basic transmission service. We point out to NRECA and TDU Systems that the transmission provider must post and update prices for basic transmission and each ancillary service on its OASIS. As discussed below in Section IV.G.1.h. (Discounts), the Commission is revising its policy regarding the discounting of the price of transmission services. There, we establish three principal requirements for discounting basic transmission service. 185/ We clarify here that these principal requirements apply to discounts for ancillary services provided by the transmission provider in support of its provision of basic transmission service. However, because ancillary services are generally not path-specific, a discount agreed upon for an ancillary service must be offered for the same period to all eligible customers on the transmission provider's system. In addition, if a transmission provider offers any rate or packaged In brief, these are that (1) any offer of a discount made by the transmission provider must be announced to all potential customers solely by posting on the OASIS, (2) any customer- initiated requests for discounts (including requests for one's own use or for an affiliate's use) must occur solely by posting on the OASIS, and (3) once a discount is negotiated, details must be immediately posted on the OASIS. In addition to these three principal requirements, we also require that a discount agreed upon for a path must be extended to certain other paths described in Section IV.G.1.h. Docket Nos. RM95-8-001 -186- and RM94-7-002 ancillary service discounts, it must post them on its OASIS and make them available to affiliates and non-affiliates on a basis that is not unduly discriminatory. In this manner, any discounting of ancillary service prices is visible to all market participants. We will require that, as soon as practicable, any "negotiation" of discounts between a transmission provider and potential transmission (and ancillary) service customers should take place on the OASIS. 186/ We continue to require a transmission provider to provide or offer to provide the six ancillary services, even if the transmission customer has some alternative suppliers. We distinguished these six services from others (e.g., Real Power Loss Services) for which many suppliers are typically available. In some cases, only the transmission provider can provide the ancillary service; in other cases too few providers are available to create a market for these services. Further, we were persuaded by the comments of NERC and others that these services are essential for reliability; if a customer must obtain these services to obtain transmission service there must be a default provider of these services. However, market-based rates for some of the ancillary services may be appropriate if the seller lacks market power for such services. Market power issues regarding ancillary services have to be addressed before market-based rates "Negotiation" would only take place if the transmission provider or potential customer seeks prices below the ceiling prices set forth in the tariff. Docket Nos. RM95-8-001 -187- and RM94-7-002 for ancillary services can be approved, as requested by AEP. We will consider market-based rates for ancillary services on a case-by-case basis. In reply to Illinois Power, we agree that the transmission provider may incur incremental costs from its obligation to offer to provide ancillary services. We believe, however, these costs should be included in the price for those services. Order No. 888 requires the transmission provider to unbundle the cost of ancillary services from the base transmission rate. A rebundling of these costs with the base transmission rate, as Illinois Power requests, would not satisfy the unbundling requirement. E. Real-Time Information Networks In the Final Rule, the Commission concluded that in order to remedy undue discrimination in the provision of transmission services it is necessary to have non-discriminatory access to transmission information, and that an electronic information system and standards of conduct are necessary to meet this objective. 187/ Therefore, in conjunction with the Final Rule, the Commission issued a final rule adding a new Part 37 that requires the creation of a basic OASIS and standards of conduct. FERC Stats. & Regs. at 31,722; mimeo at 255-56. Docket Nos. RM95-8-001 -188- and RM94-7-002 Rehearing Requests Rehearing requests raising arguments with respect to specific aspects of OASIS and standards of conduct are addressed in Order No. 889-A, issued concurrently with this order. F. Coordination Arrangements: Power Pools, Public Utility Holding Companies, Bilateral Coordination Arrangements, and Independent System Operators In the Final Rule, the Commission explained that its requirement for non-discriminatory transmission access and pricing by public utilities, and its specific requirement that public utilities unbundle their transmission rates and take transmission service under their own tariffs, apply to all public utilities' wholesale sales and purchases of electric energy, including coordination transactions. 188/ While the Commission "grandfathered" certain existing requirements agreements and non- economy energy coordination agreements, it also determined that certain existing wholesale coordination arrangements and agreements must be modified to ensure that they are not unduly discriminatory. The Commission then discussed (as set forth further below) how and when various types of coordination agreements will need to be modified, and when public utility parties to coordination agreements must begin to trade power under those agreements using transmission service obtained under the same open access transmission tariff available to non- parties. FERC Stats. & Regs. at 31,725-27; mimeo at 266-70. Docket Nos. RM95-8-001 -189- and RM94-7-002 The Commission explained that it was addressing four broad categories of coordination arrangements and accompanying agreements: "tight" power pools, "loose" power pools, public utility holding company arrangements, and bilateral coordination arrangements. In addition, the Commission explained that ISOs may prove to be an effective means for accomplishing comparable access and, accordingly, provided guidance on minimum ISO characteristics. 1. Tight Power Pools The Commission required public utilities that are members of a tight pool to file, within 60 days of publication of the Final Rule in the Federal Register, either: (1) an individual Final Rule pro forma tariff; or (2) a joint pool-wide Final Rule pro forma tariff. 189/ However, the Commission required them to file a joint pool-wide Final Rule pro forma tariff no later than December 31, 1996, and to begin to take service under that tariff for all pool transactions no later than December 31, 1996. 190/ The Commission also required the public utility members of tight pools to file reformed power pooling agreements no later than December 31, 1996 if the agreements contain provisions that are unduly discriminatory or preferential. FERC Stats. & Regs. at 31,727-28; mimeo at 270-72. By notice issued September 27, 1996, the Commission extended the date by which public utilities that are members of tight power pools must take service under joint pool-wide open access transmission tariffs from no later than December 31, 1996 to 60 days after the filing of their joint pool-wide section 206 compliance tariff. Docket Nos. RM95-8-001 -190- and RM94-7-002 If a reformed power pooling agreement allows members to make transmission commitments or contributions in exchange for discounted transmission rates, the Commission indicated that the pool may file a transmission tariff that contains an access fee (or file a higher transmission rate) for non-transmission owning members or non-members, justified solely on the basis of transmission-related costs. Rehearing Requests Consumers Power asks the Commission to clarify that Order No. 888 does not preclude the Michigan Electric Coordinated Systems (MECS) from being in compliance by removing all transmission functions from pool control and allowing pool members or the pool to take transmission service from transmission-owning pool members under their open access tariffs. It asserts that this would be an interim placeholder alternative while retail deliberations continue in Michigan. Furthermore, as one of the two members of MECS, Consumers Power indicates that it would be willing to consider further modifications that would liberalize membership criteria during the transition period if the Commission otherwise clarifies that the MECS Pool is in compliance with Order No. 888. NY Municipals request that the Commission clarify that, particularly if generation services are to be provided at market- based rates, monopoly transmission services must continue to be provided at cost-based rates (raised in connection with the NYPP). They also ask that the Commission clarify that joint Docket Nos. RM95-8-001 -191- and RM94-7-002 pool-wide tariffs must incorporate transmission rates that are uniform (non-pancaked) and strictly based on the embedded costs of the transmission facilities and related transmission expenses. Moreover, NY Municipals argue that transmission owners should receive a credit based on the depreciated costs of their transmission facilities. TAPS also asks the Commission to clarify that pool-wide and system-wide tariffs must contain non-pancaked rates. Commission Conclusion While Consumers Power's proposal to remove transmission functions from pool control, if implemented in a non- discriminatory fashion, would satisfy the comparability requirements of Order No. 888, the Commission encourages Consumers Power to pursue a pool-wide tariff. 191/ NY Municipal Utilities' concern that rates for transmission service will not be priced at cost-based rates is ill-founded. While Order No. 888 does not establish any specific pricing methodology for tariff transmission service, the Commission expects all transmission rate proposals filed on compliance to be cost based and to meet the standard for conforming proposals set It is not clear from the rehearing request exactly how the current members of MECS are proposing to remove all transmission functions from pool control and to take transmission service under their individual open access tariffs. For example, this may preclude the continuation of joint economic dispatch of generating facilities belonging to Consumer Power and Detroit Edison, which the rehearing request appears to assume would continue. However, the Commission will address the adequacy of any such proposal in the context of the appropriate compliance filings. Docket Nos. RM95-8-001 -192- and RM94-7-002 out in the Commission's Transmission Pricing Policy Statement. (See 18 CFR 2.22). Regarding NY Municipal Utilities' and TAPS's requests for a uniform tariff with non-pancaked rates, Order No. 888 does not require a non-pancaked rate structure unless a non-pancaked rate structure is available to pool members. Although the Commission has encouraged the industry to reform transmission pricing, the Commission's current policy does not mandate a specific transmission rate structure. With regard to NY Municipal Utilities' concern about market- based rates for generation, public utility owners of existing NYPP generation are not eligible to charge market-based power sales rates absent Commission approval. Order No. 888 allows market-based rates only if the seller in a case-specific filing demonstrates it meets the Commission's well-established criteria of showing that it and its affiliates do not have or have adequately mitigated transmission market power and generation market power, that there are no other barriers to entry, and there is no evidence of affiliate abuse or reciprocal dealing. With regard to requests to make market-based sales from new generation, the seller does not have to submit evidence of generation market power in long-run bulk power markets (subject to challenge where specific evidence can be presented); 192/ however, for sales from existing generation at market-based FERC Stats. & Regs. at 31,657; mimeo at 64-65; section 35.27. Docket Nos. RM95-8-001 -193- and RM94-7-002 rates, the applicant must demonstrate that it lacks, or has fully mitigated, generation market power. 193/ In response to NY Municipals' request that transmission owners that contribute transmission facilities to a power pool should receive a rate credit based on the depreciated costs of those transmission facilities, we agree that this is one possible way of reflecting a pool member's contributions or commitments of transmission facilities. However, NY Municipals has provided no rationale as to why we should limit the broader approach we adopted in Order No. 888 to this single mechanism. 194/ 2. Loose Pools In the Final Rule, the Commission found that public utilities within a loose pool must file, within 60 days of publication of the Final Rule in the Federal Register, either: (1) an individual Final Rule pro forma tariff; or (2) a pool-wide Final Rule pro forma tariff. 195/ However, the Commission required that they file a joint pool-wide Final Rule pro forma tariff no later than December 31, 1996, and begin to take service under that tariff for all pool transactions no later than December 31, 1996. 196/ The Commission also required that the FERC Stats. & Regs. at 31,660; mimeo at 73-74. See FERC Stats. & Regs. at 31,727-28; mimeo at 271-72. FERC Stats. & Regs. at 31,728; mimeo at 272-74. By notice issued September 27, 1996, the Commission extended the date by which public utility members of loose power pools must take service under joint pool-wide open access (continued...) Docket Nos. RM95-8-001 -194- and RM94-7-002 public utility members of loose pools file reformed power pooling agreements no later than December 31, 1996 if the agreements contain provisions that are unduly discriminatory or preferential. They also must file a joint pool-wide tariff no later than December 31, 1996. If a reformed pooling agreement allows members to make transmission commitments or contributions in exchange for discounted transmission rates, the Commission determined that the pool may file a transmission tariff that contains an access fee (or a higher transmission rate) for non-transmission owning members or non-members, justified solely on the basis of transmission-related costs. Rehearing Requests Union Electric asserts that the definition of loose pools is so vague that many public utilities, regional organizations and multi-lateral arrangements, which are not actually pools, may incorrectly be deemed loose pools by third parties. Thus, Union Electric asks the Commission to clarify that members or parties to multi-lateral arrangements only need to offer transmission services pursuant to their own individual company tariffs. EEI asks the Commission to clarify the nature of the tariffs that loose pools may file to comply with the Rule to ensure that the members are not required to file tariffs for services that (...continued) transmission pro forma tariffs from no later than December 31, 1996 to 60 days after the filing of their joint pool-wide section 206 compliance tariff. Docket Nos. RM95-8-001 -195- and RM94-7-002 they do not now provide. EEI also requests that, where members of loose pools currently provide transmission services to each other, they may continue to provide such services to each other under each member's individual pro forma tariff in lieu of a pool-wide tariff (provided that those services are made available to all eligible entities on a non-discriminatory basis). Similarly, Montana Power argues that members of loose pools should be allowed to meet comparability by filing individual open access tariffs, without having to file a pool-wide tariff. 197/ Public Service Co of CO asserts that the primary purpose of the Inland Power Pool is to provide for reserve sharing during emergency conditions, although the pool agreement also allows for economy transactions. It argues that another way to comply with the Rule should be to eliminate the economy energy schedule of the Inland Power Pool Agreement. Moreover, Public Service Co of CO argues that given the number of non-jurisdictional entities within the Inland Power Pool, it may be impossible to agree on a pool-wide tariff. El Paso adds that Inland Power Pool should not be treated as a loose pool because it functions as a reserve sharing mechanism and not as a pool. Utilities For Improved Transition asks the Commission to clarify that pool members or members of other entities do not have to provide more transmission services than they already provide on a voluntary basis to each other. It contends that See also Public Service Co of CO. Docket Nos. RM95-8-001 -196- and RM94-7-002 there is no record to support a broader obligation and would cause massive disruption and the disintegration of many existing pools. Utilities For Improved Transition maintains that pools should have substantial leeway to develop arrangements reflecting their diverse memberships and the diverse contributions made. VEPCO seeks clarification whether the Commission intended to impose the single-system tariff requirement only with respect to multilateral agreements that provide for system-wide transmission rates for the parties to the agreements. TAPS asks the Commission to clarify that section 35.28(c)(3) includes all pools and all holding company systems, as well as any multi-lateral agreement so long as the multi-lateral agreement explicitly or implicitly addresses transmission (e.g., by providing for a transaction without assessing transmission costs in connection with that transaction). Commission Conclusion In response to parties seeking clarification of the definition of a loose pool, the Commission clarifies that a loose pool is any multilateral arrangement, other than a tight power pool or a holding company arrangement, that explicitly or implicitly contains discounted and/or special transmission arrangements, that is, rates, terms, or conditions. The Commission requires public utilities that are members of a loose pool to either (1) reform their pooling arrangements in accordance with Order No. 888 or (2) excise all discounted and/or special arrangements transmission service from the pooling Docket Nos. RM95-8-001 -197- and RM94-7-002 arrangement. That is, in the latter case the members could continue to provide other services (e.g., generation), but would cease to be a loose pool for purposes of Order No. 888. The primary goal of Order No. 888's requirements for pooling arrangements, including "loose" pools, is to ensure comparability regarding transmission services that are offered on a pool-wide basis. We believe comparability for loose pools can be achieved if pooling agreements are modified: (1) to allow open membership and (2) to make the transmission service in the loose pool agreement available to others. While the Commission encourages pool-wide transmission tariffs that offer the full range of transmission services included in the pro forma tariff, we will not require, under the comparability principles of Order No. 888, that pool members offer to third parties transmission services that they do not provide to themselves on a pool-wide basis. For example, if existing loose pool members do not offer network services to each other, they do not have to expand the pool services to offer network services to themselves or any third parties. Additionally, we do not find it to be unduly discriminatory to provide some pool-wide transmission services to members under a pooling agreement and to provide other transmission services to members under the individual tariff of each member, as long as members and non-members have access to Docket Nos. RM95-8-001 -198- and RM94-7-002 the same transmission services on a comparable basis and pay the same or a comparable rate for transmission. 198/ The Commission notes that the Inland Power Pool agreement provides for non-firm transmission service (Service Schedule D) for emergency service, scheduled outage service, and economy energy service. The Inland Power Pool agreement provides members preferential transmission rates for deliveries of emergency service, i.e., members will provide free non-firm transmission service at a higher priority than any other non-firm transactions. Such preferential service is not available to non- members. We consider any rates, terms or conditions of transmission service that favor members over non-members to be unduly discriminatory and preferential, whether embodied explicitly or implicitly in a loose pooling agreement. Pool members can either amend the agreement to provide comparable services to others and open the pool to new members, or amend the agreement to eliminate any preferential transmission availability and/or pricing. In response to TAPS, the Commission agrees that Section 35.28(c)(3) applies to any pool, holding company system or multi- lateral agreement that contains explicit or implicit transmission rates, terms, or conditions. 199/ For example, if a utility See FERC Stats. & Regs. at 31,728; mimeo at 273-74. See FERC Stats. & Regs. at 31,726; mimeo at 268-69 (filing of open access tariffs by public utility pool members is not enough to cure undue discrimination in transmission if those (continued...) Docket Nos. RM95-8-001 -199- and RM94-7-002 offers transmission without charge as part of such an agreement, it must offer transmission to all parties requesting a similar service either without charge or at an access fee or other transmission rate that comparably reflects transmission-related costs borne by members of the agreement. 200/ 3. Public Utility Holding Companies In the Final Rule, the Commission required that holding company public utility members, with the exception of the Central and South West (CSW) System, file a single system-wide Final Rule pro forma tariff permitting transmission service across the entire holding company system at a single price within 60 days of publication of the Final Rule in the Federal Register. 201/ With respect to CSW, the Commission directed the public utility subsidiaries of CSW to consult with the Texas, Arkansas, Oklahoma and Louisiana Commissions and to file not later than December 31, 1996 a system tariff that will provide comparable service to all wholesale users on the CSW System, regardless of whether they take transmission service wholly within ERCOT or the SPP, or take transmission service between the reliability councils over the North and East Interconnections. (...continued) entities can continue to trade with a selective group within a power pool; the same holds true for certain bilateral arrangements allowing preferential pricing or access) and FERC Stats. & Regs. at 31,727-28; mimeo at 270-272 (tight and loose pools must file joint pool-wide tariffs). See FERC Stats. & Regs. at 31,730; mimeo at 278. FERC Stats. & Regs. at 31,728-29; mimeo at 274-77. Docket Nos. RM95-8-001 -200- and RM94-7-002 The Commission gave public utilities that are members of holding companies an extension of the requirement to take service under the system tariff for wholesale trades between and among the public utility operating companies within the holding company system until December 31, 1996 -- the same extension it granted to power pools. 202/ In addition, the Commission indicated that it may be necessary for registered holding companies to reform their holding company equalization agreement to recognize the non-discriminatory terms and conditions of transmission service required under the Final Rule pro forma tariff. Rehearing Requests FL Com asks the Commission to clarify whether it intends to require operating company members of a registered holding company to charge each other the same wheeling charge to be charged to others even though others pay nothing for transmission construction. FL Com argues that such a charge would be inconsistent with the Commission's traditional treatment of public utility holding companies as a single entity. AL Com asks the Commission to clarify that "intra-holding company transactions in support of economic dispatch across a single integrated system should not be subjected to additional transmission charges, while transactions between operating By notice issued September 27, 1996, the Commission extended the date by which public utilities that are members of holding companies must take service under their system-wide tariffs from December 31, 1996 to no later than March 1, 1997. Docket Nos. RM95-8-001 -201- and RM94-7-002 companies for the benefit of wholesale customers not included within the definition of native load customer require distinct transmission charges." 203/ Southern asks the Commission to clarify that transactions between public utility operating subsidiaries within a holding company system for the benefit of native load customers fall within the network service for which they are assigned cost responsibility under the Final Rule tariff. AEP asserts that the Commission has provided no reason for requiring holding companies to use the pro forma tariff for intra-pool transactions. AEP asks the Commission to clarify whether the Rule applies to AEP. It asserts that the Preamble states that all members of holding company systems must use the pro forma tariff for intra-system transactions, but the regulatory text requires only a member of a public utility holding company "arrangement or agreement that contains transmission rates, terms or conditions. . . ." AEP explains that the AEP System Interconnection Agreement and Transmission Agreement do not contain transmission rates, terms or conditions and the members do not offer transmission service to one another. However, AEP argues that, if the Rule applies to AEP, Order No. 888 contains no explanation of why or how a different intra- pool allocation of transmission costs than would result from the pro forma tariff prejudices transmission users. It asserts that AL Com at 1-4. Docket Nos. RM95-8-001 -202- and RM94-7-002 (1) AEP's allocation has been subject to extensive review over the last few years, (2) AEP treats itself as a single system, not as a collection of individual members, (3) each member carries its fair share of transmission costs, and (4) compliance with the Commission's requirement would be onerous. If the Commission does not remove this requirement, AEP requests waiver of the requirement. Similarly, Allegheny Power asserts that its Power Supply Agreement (PSA) does not provide for "wholesale trades." It argues that the PSA is immaterial to all transmission services, including intra-company exchanges. Because the PSA is an existing contract that the Final Rule does not propose to abrogate, Allegheny Power asserts that the PSA need not be reformed under the Final Rule. Allegheny states that it will provide new wholesale service to itself and others under its open access tariff which was accepted for filing on December 6, 1995 in Docket No. ER96-58. Union Electric assumes that the "rule is intended solely to mean that a holding company system would use the network integration part of the tariff, for its intra-system 'wholesale trades.' Indeed, if Union Electric and CIPS were required to take point-to-point service for their wholesale trades, they would be placed in an inferior and non-comparable position vis-a- vis customers on the Ameren tariff who will be entitled to single-system transmission service for a single or postage-stamp charge." (Union Electric notes that Union Electric and CIPS are Docket Nos. RM95-8-001 -203- and RM94-7-002 currently seeking approval to merge, with the combined facilities being operated as the Ameren System.) NU believes that Order No. 888 could be construed to require NU System Companies to charge each other as separate entities for transmission service in connection with intra-system cost allocations as if off-system wholesale sales had occurred. NU argues, however, that this is inconsistent with Commission precedent in treating the NU System Companies as a single integrated system and would give retail native load customers service inferior to that of wholesale native load (i.e., network) customers. NU further argues that it will result in duplicative transmission charges for energy flows between the NU System Companies. Moreover, NU asserts that viewing NU as a single system for establishing transmission rates, but as separate companies with respect to energy flows that result from economic dispatch of their generation to native load is inconsistent with the treatment of multistate non-holding company utilities and is thus discriminatory. Blue Ridge seeks clarification that, to avoid double payment for transmission, "CSW must file its compliance filing resolving comparability issues and the appropriate CSW ERCOT transmission rate prior to September 1, 1996." Blue Ridge asserts that CSW must resolve a potential conflict between its rate structure and the new PUCT wheeling rule by September 1, 1996 (contemplated effective date for interim PUCT transmission rates). Docket Nos. RM95-8-001 -204- and RM94-7-002 Commission Conclusion In requiring holding companies to file a pool-wide tariff, the Commission does not intend that transmission service provided by the operating subsidiaries to one another on behalf of their respective native loads be subjected to additional transmission charges. The Commission recognizes that the operating subsidiaries of a holding company bear cost responsibility for transmission facilities by virtue of ownership of such facilities. In many, if not all cases, transmission costs are equalized among operating subsidiaries through transmission equalization agreements (e.g., AEP's Transmission Agreement). However, the Commission does intend, pursuant to Order No. 888, that holding company operating subsidiaries take transmission service under the same tariff rates, terms, and conditions as third-party customers that seek transmission service over the holding company system. This applies to all holding company systems that rely upon the transmission facilities of the individual operating subsidiaries to support central economic dispatch -- including AEP and Allegheny. However, as suggested by Southern and Union Electric, the Commission anticipates that transmission service for an operating subsidiary's native load would be treated as network service under the pro forma tariff. Accordingly, the CP demands of each operating subsidiary's native load would establish each operating subsidiary's transmission cost responsibility related to network Docket Nos. RM95-8-001 -205- and RM94-7-002 service over the integrated transmission facilities of the holding company system. Thus, in response to the AL and FL Commissions, Southern, and NU, intra-holding company transactions in support of economic dispatch would not be subjected to "additional" transmission charges. 204/ The load ratio pricing mechanism of the network portion of the tariff should ensure that each operating company bears its proportionate share of transmission costs without jeopardizing or otherwise penalizing these types of intra-system transactions. Moreover, any off-system sales would have to be taken under the point-to-point provisions of the tariff. As we noted in Order No. 888, "it may be necessary for registered holding companies to reform their holding company equalization agreement to recognize the non-discriminatory terms and conditions of transmission service required under the Final Rule pro forma tariff." 205/ However, nothing in Order No. 888 mandates any change to the method chosen for apportioning transmission revenues among the operating companies, which may be based, for example, upon equalizing transmission investment responsibility. The Commission notes that Order No. 888 requires that all third party tariff customers taking network or point-to- point service pay a transmission rate which reflects an appropriate share of transmission costs, including those related to transmission construction. FERC Stats. & Regs. at 31,729; mimeo at 277. Docket Nos. RM95-8-001 -206- and RM94-7-002 The concerns raised here by Blue Ridge are resolved on an interim basis because the PUCT has accepted the filing of CSW's Federal tariff as adequate in the Texas proceeding until differences between the Order No. 888 rate structure and the PUCT rate structure are resolved. If, CSW implements a new ERCOT transmission tariff in response to actions of the PUCT, then affected parties may bring any remaining concerns to the Commission's attention at that time through a section 206 complaint. We note that the issue raised here by Blue Ridge is very similar to the one raised by Tex-La and East Texas Electric Cooperative, and addressed by the Commission's recent order, in Houston Lighting & Power Co., 77 FERC  61,113 at 61,439 (1996). There, the Commission found that it would be premature to address this issue at that time, and noted that parties would have an opportunity to raise their concerns after the PUCT finalizes its ERCOT tariff. 4. Bilateral Coordination Arrangements In the Final Rule, the Commission required that any bilateral wholesale coordination agreements executed after the effective date of the Final Rule would be subject to the functional unbundling and open access requirements set forth in the Rule. 206/ In addition, the Commission required that all bilateral economy energy coordination contracts executed before FERC Stats. & Regs. at 31,729-30; mimeo at 277-78. Docket Nos. RM95-8-001 -207- and RM94-7-002 the effective date of the Rule be modified to require unbundling of any economy energy transaction occurring after December 31, 1996. Moreover, the Commission permitted all non-economy energy bilateral coordination contracts executed before the effective date of the Rule to continue in effect, but subject to section 206 complaints. To compute the unbundled coordination compliance rate, the Commission indicated that the utility must subtract the corresponding transmission unit charge in its open access tariff from the existing coordination rate ceiling. However, the Commission noted, if a utility's transmission operator offers a discounted transmission rate to the utility's wholesale marketing department or an affiliate for the purposes of coordination transactions, the same discounted rate must be offered to others for trades with any party to the coordination agreement. In addition, the Commission explained that discounts offered to non- affiliates must be on a basis that is not unduly discriminatory. Rehearing Requests SoCal Edison seeks clarification as to how Order No. 888 affects package agreements (i.e., bilateral contracts that provide some or all of requirements service, coordination service, or transmission service). In particular, SoCal Edison asks (1) what specific functions of each must be modified to comply with Order No. 888; (2) whether a sale of non-firm energy made pursuant to a package agreement must comply with the unbundling requirements for coordination contracts; (3) whether Docket Nos. RM95-8-001 -208- and RM94-7-002 the requirement to remove preferential transmission access or pricing provisions applies to existing or future transmission services provided pursuant to package agreements; if so, what is the deadline; and (4) whether the rulings with respect to Mobile- Sierra apply to package agreements. 207/ APPA argues that the Commission should require all coordination arrangements to be subject to Order No. 888. CCEM asserts that to the extent non-economy energy coordination agreements are allowed to remain bundled, they should be identified in connection with determinations of available transfer capacity and, because they should only be a transitional matter, should be subject to a sunset date of December 31, 1996. According to Utilities For Improved Transition, requiring the subtraction of the current tariff transmission rate from the current rate ceiling, without increasing the residual sales price, will force transmission providers to fail to recover their full costs of providing service because the Commission has previously prohibited these rates from including a transmission component (citing Green Mountain, 63 FERC  61,071 at 61,307-08 Anaheim, in an answer opposing SoCal Edison's request for clarification regarding its package agreements, requests that these agreements be dealt with on a case-by-case basis "in context." (Anaheim Answer). While answers to requests for rehearing generally are not permitted, we will depart from our general rule because of the significant nature of this proceeding and accept the Anaheim Answer. Docket Nos. RM95-8-001 -209- and RM94-7-002 (1993) and Cleveland Electric, 63 FERC  61,244 at 62,277-78 (1993)). 208/ Union Electric also argues that the Commission should delete the requirement that the utility subtract the corresponding transmission unit charge in its open access tariff from the existing coordination rate ceiling. According to Union Electric, actual bilateral economy sales do not include adders for recovery of transmission costs, but are typically limited to production or generation costs. Union Electric further asserts that the definition of economy energy coordination agreement is so open- ended, it may apply to many types of coordination transactions that are not mere energy economy sales. Union Electric argues that a split-the-savings charge cannot be unbundled in the manner described by the Commission because it is an incorrect assumption that the rate ceiling for every economy energy coordination sales agreement includes a transmission cost component. If Union Electric is required to arbitrarily subtract a transmission charge for its economy sales, it argues that it will be penalized. At a minimum, it argues, a utility should be permitted to submit a list of economy coordination rate schedules that it believes to be already unbundled and should not have to subtract a transmission charge. Alternatively, it argues that the Commission should not require unbundling unless the Commission determines that the existing rate ceiling has been See also VEPCO. Docket Nos. RM95-8-001 -210- and RM94-7-002 cost justified on a basis that includes an allowance for the full recovery of transmission function cost. 209/ Commission Conclusion SoCal Edison represents that its package agreements include requirements services as well as coordination services. For existing bilateral economy energy coordination agreements, Order No. 888, as clarified by the Commission's May 17 Order, requires the unbundling of transmission from generation for all such contracts on or before December 31, 1996. 210/ Thus, any economy energy service included in existing package agreements must be unbundled. Regarding non-firm energy sales made under a package agreement, SoCal Edison provides no information distinguishing that service from other economy energy coordination transactions, which include all "if, as and when available" services (see section 35.28(b)(2)). Absent more information, non-firm energy sales should be unbundled. We further note that our requirements concerning unbundling of bilateral coordination arrangements apply regardless of whether such arrangements are governed by the public interest or just and reasonable standard of review. See also Florida Power Corp (if the Commission requires an unbundled transmission rate, it must allow transmission providers to reformulate their unbundled economy energy agreements to recover both their capacity and energy costs and the costs of transmission). FERC Stats. & Regs. at 31,730; mimeo at 277. Docket Nos. RM95-8-001 -211- and RM94-7-002 With respect to APPA's concerns, the Final Rule provides that all bilateral economy energy coordination contracts executed before the effective date of the Final Rule must be modified to require unbundling of any economy energy transaction occurring after December 31, 1996. Non-economy energy bilateral coordination contracts executed before the effective date of the Final Rule, however, were allowed to continue in effect, but subject to complaints filed under section 206 of the FPA. 211/ We drew this distinction for both policy and practical reasons. The ability to use discounts on transmission in order to favor short-term economy energy sales made out of the transmission provider's own generation was of particular concern to the Commission. Thus, in order to eliminate the ability of transmission providers to exercise undue discrimination for short-term coordination transactions under existing umbrella-type agreements, we required unbundling by December 31, 1996. 212/ However, non-economy energy coordination agreements presented a different situation. In the Final Rule, we expressed a particular concern with not abrogating non-economy energy coordination agreements, which we indicated may reflect complementary long-term obligations FERC Stats. & Regs. at 31,730; mimeo at 277. Approximately 300 filings to unbundle this category were filed by December 31, 1996. Docket Nos. RM95-8-001 -212- and RM94-7-002 among the parties. 213/ Non-economy energy coordination agreements consist for the most part of long-term reliability arrangements. Providing for the abrogation of these arrangements could cause special problems for the reliable operation of the grid. Examples include agreements governing sales during emergency or maintenance periods. These agreements, unlike economy energy agreements where trade is on an "as, if and when available" basis, often have specified terms governing the parties' responsibilities. As a result, many non-economy energy coordination agreements are more akin to requirements contracts than to economy energy coordination agreements. Therefore, we determined to permit this category of contracts to run their course, absent a case specific complaint. The burden would be on the complainant to demonstrate that the transmission component of a non-economy energy coordination agreement is unduly discriminatory or otherwise unlawful. The Commission would decide based on the facts of the case whether unbundling is the appropriate remedy. Neither CCEM nor APPA have presented evidence or convincing arguments as to why these types of agreements should be unbundled generically. 214/ FERC Stats. & Regs. at 31,666; mimeo at 90. Regarding CCEM's request that non-economy energy coordination agreements be identified in determining available transfer capacity (ATC), we note that all data used to calculate ATC and total transfer capacity (TTC) must be made publicly available upon request pursuant to section 37.6(b)(2)(ii) of the OASIS regulations. Docket Nos. RM95-8-001 -213- and RM94-7-002 The Commission affirms the requirement in Order No. 888 that the transmission rate for any economy energy coordination service be unbundled. The Commission states in Order No. 888 that to adequately remedy undue discrimination, public utilities must remove preferential transmission access and pricing provisions from agreements governing their transactions. 215/ In the cases cited by Utilities For Improved Transition, the Commission prohibited the utility from charging a split-savings rate plus a contribution to fixed costs. The Commission has long allowed utilities to set their coordination rates by reference to their own costs (cost-based ceilings) or by dividing the pool of benefits (fuel cost differentials) brought about by the transaction. 216/ Utilities have been free to design a rate using either method but not both. Regardless of the method adopted to set a bundled rate on file (a seller's own costs or a sharing of transaction benefits), a bundled rate constitutes the total charge for all components and must now be unbundled. A split-savings rate is set without reference to the seller's fixed costs and, therefore, Union Electric's argument is not germane. We are not requiring that the present rate be adjusted upward or downward. Rather, we are requiring disassembly of the existing rate into component parts one of which represents the rate being charged for transmission service. FERC Stats. & Regs. at 31,726; mimeo at 268-69. See e.g., Illinois Power Company, 62 FERC  61,147 at 62,062 (1993). Docket Nos. RM95-8-001 -214- and RM94-7-002 If a utility is no longer satisfied that an existing rate is compensatory, with regard to either the generation component or the transmission component, it may file an appropriate revision under section 205. ISO Principles In the Final Rule, the Commission set out certain principles that will be used in assessing ISO proposals that may be submitted to the Commission in the future. 217/ The Commission emphasized that these principles are applicable only to ISOs that would be control area operators, including any ISO established in the restructuring of power pools. The Commission set forth the following principles for ISOs: 1. The ISO's governance should be structured in a fair and non-discriminatory manner. 2. An ISO and its employees should have no financial interest in the economic performance of any power market participant. An ISO should adopt and enforce strict conflict of interest standards. 3. An ISO should provide open access to the transmission system and all services under its control at non-pancaked rates pursuant to a single, unbundled, grid-wide tariff that applies to all eligible users in a non-discriminatory manner. FERC Stats. & Regs. at 31,730-32; mimeo at 279-86. Docket Nos. RM95-8-001 -215- and RM94-7-002 4. An ISO should have the primary responsibility in ensuring short-term reliability of grid operations. Its role in this responsibility should be well-defined and comply with applicable standards set by NERC and the regional reliability council. 5. An ISO should have control over the operation of interconnected transmission facilities within its region. 6. An ISO should identify constraints on the system and be able to take operational actions to relieve those constraints within the trading rules established by the governing body. These rules should promote efficient trading. 7. The ISO should have appropriate incentives for efficient management and administration and should procure the services needed for such management and administration in an open competitive market. 8. An ISO's transmission and ancillary services pricing policies should promote the efficient use of and investment in generation, transmission, and consumption. An ISO or an RTG of which the ISO is a member should conduct such studies as may be necessary to identify operational problems or appropriate expansions. 9. An ISO should make transmission system information publicly available on a timely basis via an electronic information network consistent with the Commission's requirements. Docket Nos. RM95-8-001 -216- and RM94-7-002 10. An ISO should develop mechanisms to coordinate with neighboring control areas. 11. An ISO should establish an alternative dispute resolution (ADR) process to resolve disputes in the first instance. Rehearing Requests General Comments NY Municipal Utilities argue that if the NYPP participants (or other tight pools) elect to establish an ISO, the ISO Principles should be made mandatory for the protection of transmission dependent utilities. NY Com asks the Commission to clarify that it will allow flexibility to states and utilities in structuring proposals that meet the goals underlying the ISO principles. It explains that the parties to New York's electric competition proceeding are discussing the formation of an ISO in which transmission owners control the system operator, but would have to divest their competitive generation. NY Com further notes that it has not decided that matter yet, but it does not want to see such options foreclosed. Minnesota P&L argues that certain functions, particularly those involving local area circumstances and safety, are better handled at the local level. It further argues that control area responsibilities of an ISO should focus on regional issues and operations, and on establishing and enforcing uniform criteria and guidelines for local control area operations in order to Docket Nos. RM95-8-001 -217- and RM94-7-002 assure non-discriminatory treatment of all transmission customers. AMP-Ohio asserts that the Commission should require the separation of transmission, generation and distribution through an ISO and, at a minimum, the Commission should include a Stage 3 of implementation to bring ISOs to reality. ISO Principle 1: NYPP argues that the Commission should not include a rigid ban on transmission owner leadership in ISO governance because it is the transmission owner that is ultimately responsible for the reliability of the bulk power system. 218/ ISO Principle 2: NYPP asks that the Commission revise this principle to take a more flexible approach to significant employee issues. NYPP explains that it has 81 management employees on the payroll of individual member systems and that pension rights (accrual rights based on an average salary) and medical insurance (preexisting conditions) are through the individual member systems. Sithe, in a response to the NYPP's request for clarification, opposes the "transmission owners only" ISO sought by NYPP. (Sithe Response). Subsequently, NYPP filed an objection to Sithe's pleading and request that it be rejected. (NYPP Objection). NYPP explains that its rehearing was a request that the Commission refrain from setting fixed rules for ISO governance in advance, not an argument that the Commission should adopt one particular mechanism or another for all ISOs. While answers to requests for rehearing generally are not permitted, we will depart from our general rule because of the significant nature of this proceeding and accept the Sithe Response and NYPP Objection. Docket Nos. RM95-8-001 -218- and RM94-7-002 ISO Principle 3: SoCal Edison asks that this principle be revised to permit a separate access charge for each utility in order to avoid cost shifting. Anaheim seeks revision of this principle to require that an ISO provide comparable compensation to all transmission owners that make transmission facilities available for use by the ISO. ISO Principle 5: Anaheim asks that this principle be revised to make clear that ISO arrangements should seek to encourage participation by all transmission owners within the region. ISO Principle 6: NYPP seeks clarification that an ISO needs control over more than some generation facilities because the more generating facilities operating under an ISO the more reliability there is. Thus, it asserts that the Commission should clarify that its description of ISO control of generation does not require only a minimalist approach to ISO generation control. ISO Principle 8: SoCal Edison seeks revision of this principle to remove the language linking the ISO to performing studies necessary to identify appropriate grid expansions. According to SoCal Edison, an ISO should not be a project sponsor or should not conduct planning studies to determine what facilities should be constructed because those actions would compromise its independence. In addition, SoCal Edison seeks revision of this Docket Nos. RM95-8-001 -219- and RM94-7-002 principle to permit a transmission usage charge that incorporates locational marginal cost pricing for managing transmission congestion. Commission Conclusion We reaffirm our strong commitment to the concept of ISOs, and to the ISO principles described in Order No. 888. We continue to believe that properly structured ISOs can be an effective way to comply with the comparability requirements of open access transmission service. Nevertheless, we do not believe at this time that it is appropriate to require public utilities or power pools to establish ISOs, as suggested by AMP- Ohio. We think it is appropriate to permit some time to confirm whether functional unbundling will remedy undue discrimination before reconsidering our decision that ISO formation should be voluntary. A number of the above rehearing requests on ISOs are from New York parties and deal with ongoing efforts in New York that would reform the New York Power Pool pooling agreements, restructure power markets, and possibly form an ISO. Some of these arguments are in apparent conflict; for example, the NY Municipal Utilities argue that the 11 ISO principles should be made mandatory if the New York Power Pool participants elect to establish an ISO, while the NY Com argues that the Commission should clarify Order No. 888 to state that it will allow flexibility to states and utilities in structuring proposals that meet the goals underlying the ISO principles. We note that since Docket Nos. RM95-8-001 -220- and RM94-7-002 the time the rehearing requests were filed, the NY Power Pool has filed amendments to its pooling agreements on December 30, 1996 and also has filed, on January 31, 1997, various agreements and tariffs designed to implement an ISO and market exchange. To the extent the rehearing requests from New York parties deal with matters that have been filed with the Commission subsequent to the rehearing requests, the Commission will address the issues raised in the context of those filings. In response to NY Com's request for clarification that we provide flexibility to states and their utilities in structuring ISO proposals, the Commission at this time clearly cannot, and does not intend to, prescribe a "cookie cutter" approach to ISOs. However, the Commission does believe that certain basic principles must be met to ensure non-discriminatory transmission services. We reaffirm our view that ISO Principles 1 (independence with respect to governance) and 2 (independence with respect to financial interests) are fundamental to ensuring that an ISO is truly independent and would not favor any class of transmission users. As the Commission stated in its recent order on the proposed PJM ISO: The principle of independence is the bedrock upon which the ISO must be built if stakeholders are to have confidence that it will function in a manner consistent with this Commission's pro-competitive goals. [219/] Atlantic City Electric Company, et al., 77 FERC  61,148 (1996) (mimeo at 36-41); see also Pacific Gas & Electric (continued...) Docket Nos. RM95-8-001 -221- and RM94-7-002 ISO governance that is disproportionately influenced by transmission owners, unless they have fully divested their interests in generation, is not consistent with ISO Principle 1. We remain concerned that ISO proposals that do not include governance by a fair representation of all system users may not be independent, although we reserve final judgment on any specific governance structure until we have an opportunity to review a specific proposal. 220/ In response to the argument made by NYPP that transmission owner leadership in ISO governance may be needed because transmission owners are ultimately responsible for the reliability of the bulk power system, we emphasize that reliability is of primary importance to this Commission and that the formation and operation of an ISO should not in any way impair reliability. We believe that one of the main purposes of an ISO is to make an independent party, the ISO, responsible for at least short-term reliability. Even if both the transmission owners and the ISO will be responsible for some aspects of reliability, this does not affect our finding that the governance of the ISO must be independent of the transmission owners so that (...continued) Company, 77 FERC  61,204 (1996). In making this finding, we are not suggesting that an independent transmission company, which owns only transmission, is undesirable. However, an ISO, which separates ownership and operation, is designed in large part to recognize that transmission owners today have significant generation or load interests that may bias their operational decisions. Docket Nos. RM95-8-001 -222- and RM94-7-002 the ISO can carry out its own responsibilities in a not-unduly discriminatory manner. In response to arguments of the NYPP that the Commission should revise Principle 2 to take a more flexible approach to employee issues, we reaffirm the necessity of requiring the employees of an ISO to be financially independent of market participants and note that Principle 2 suggests that a short transition period should be adequate for ISO employees to sever all financial ties with former transmission owners. We recognize that some flexibility may be necessary regarding the length of a transition period, but believe that ISO employees must in fairly short order be independent of all financial ties to any market participants, if we are to achieve not unduly discriminatory practices in generation and transmission markets. A number of additional parties seek other revisions to or clarifications of the ISO Principles. For example, Minnesota P&L requests clarification or rehearing to ensure that the Commission provides sufficient flexibility to permit local operators, under the general supervision and control of the ISO, to perform local operational functions, such as performing switching operations. In response to this concern, we note that Principle 3 (open access under a single tariff) says that the portion of the transmission grid operated by a single ISO should be as large as possible. Our view, as described above, is that an ISO, which includes all affected users, should be responsible for operation of the system and ensuring reliability. The ISO may use some Docket Nos. RM95-8-001 -223- and RM94-7-002 combination of actual physical control over facilities and virtual control of facilities by others (i.e., the ISO exercises control over facilities by instructing the transmission owners' or generation owners' staffs as to the actions to be taken). The broad range of interested parties that establish the ISO must determine what services the ISO will perform and what services transmission owners or others will perform under ISO supervision. We deny the requests by Socal Edison and Anaheim to revise ISO Principle 3 to permit separate access charges for each utility to avoid cost shifting. We think ISO Principle 3 already provides sufficient flexibility to accommodate the concerns of these parties with respect to design of access charges and compensation to owners for transmission facilities under operational control of the ISO. Similarly, we see no reason to revise Principle 5 (control of interconnected operations) as requested by Anaheim. We agree with Anaheim that wide participation of transmission owners in a region will help ensure open access and increase efficient transmission coordination. ISO Principle 3 says that the portion of the transmission grid operated by a single ISO should be as large as possible. ISO Principle 5 says that an ISO should have control over the operation of interconnected transmission facilities within its region. These principles, as written, address Anaheim's concern. With respect to NYPP's request for clarification of ISO Principle 6 (dealing with constraints), we note that the Docket Nos. RM95-8-001 -224- and RM94-7-002 description of ISO Principle 6 in the Final Rule says that the ISO may need to exercise some level of operational control over generation facilities in order to regulate and balance the power system. 221/ We do not think it is appropriate for the Commission to give further generic guidance now on what constitutes the proper level of operational control over generation. The ISO, including all stakeholders, needs to address this issue, based on the structure of power markets and perhaps other local considerations, in preparing a specific proposal for our approval. Finally, we deny SoCal Edison's request for revision of ISO Principle 8 (pricing). In response to SoCal Edison's concern, ISO Principle 8 allows the use of appropriate locational marginal cost pricing. The principle allows flexibility regarding which regional organization of market participants (ISO or RTG) conducts the necessary studies to identify the need for expansion. We are unpersuaded by SoCal Edison's arguments that the fact that an ISO is involved in planning for transmission facility expansion would in any way compromise the independence of the ISO. G. Pro Forma Tariff In the Final Rule, the Commission combined the requirements for point-to-point transmission service and network transmission FERC Stats. & Regs. at 31,731; mimeo at 283. Docket Nos. RM95-8-001 -225- and RM94-7-002 service into a single pro forma tariff. 222/ The Commission explained that this eliminates many of the differences between the two NOPR pro forma tariffs, provides a unified set of definitions, and consolidates certain common requirements such as the obligation to provide ancillary services. The Commission also noted that it was issuing an accompanying Notice of Proposed Rulemaking in Docket No. RM96-11-000 in which it was seeking comments on whether a different form of open access tariff -- one based solely on a capacity reservation system -- might better accommodate competitive changes occurring in the industry while ensuring that all wholesale transmission service is provided in a fair and non-discriminatory manner. 223/ 1. Tariff Provisions That Affect The Pricing Mechanism a. Non-Price Terms and Conditions In the Final Rule, the Commission explained that the Final Rule pro forma tariff is intended to initiate open access, with non-price terms and conditions based on the contract path model of power flows and embedded cost ratemaking. 224/ It emphasized that the Final Rule pro forma tariff is not intended to signal a preference for contract path/embedded cost pricing for the future. The Commission indicated that it will in the future FERC Stats. & Regs. at 31,733; mimeo at 288-89. FERC Stats. & Regs. at 31,733; mimeo at 289. FERC Stats. & Regs. at 31,734-35; mimeo at 291-93. Docket Nos. RM95-8-001 -226- and RM94-7-002 entertain non-discriminatory tariff innovations to accommodate new pricing proposals. The Commission further indicated that, by initially requiring a standardized tariff, it intends to foster broad access across multiple systems under standardized terms and conditions. However, the Commission emphasized that the tariff provides for certain deviations where it can be demonstrated that unique practices in a geographic region require modifications to the Final Rule pro forma tariff provisions. Finally, the Commission stated that it will allow utilities to propose a single cost allocation method for network and point- to-point transmission services. b. Network and Point-to-Point Customers' Uses of the System (so called "Headroom") In the Final Rule, the Commission explained that it will not allow network customers to make off-system sales within the load- ratio transmission entitlement at no additional charge. 225/ The Commission further explained that use of transmission by network customers for non-firm economy purchases, which are used to displace designated network resources, must be accorded a higher priority than non-firm point-to-point service and secondary point-to-point service under the tariff. In addition, the Commission found that off-system sales transactions, which are sales other than those to serve the transmission provider's native load or a network customer's load, must be made using FERC Stats. & Regs. at 31,751; mimeo at 342-43. Docket Nos. RM95-8-001 -227- and RM94-7-002 point-to-point service on either a firm or non-firm basis. In rejecting the "headroom" concept (where a network customer can make off-system sales as long as its total use of the system does not exceed its coincident peak demand), the Commission explained that it was not requiring any utility to take network service to integrate resources and loads and if any transmission user (including the public utility) prefers to take flexible point-to- point service, 226/ they are free to do so. Further, the Commission explained that any point-to-point customer may take advantage of the secondary, non-firm flexibility provided under point-to-point service equally, on an as-available basis. Rehearing Requests A number of entities argue that it is unreasonable to permit firm point-to-point customers to receive non-firm service, up to their contract demand, at no additional charge, at secondary receipt and delivery points, but to require transmission providers and network customers to purchase transmission for all off-system sales, including non-firm sales made in competition with sales made by the point-to-point customer. 227/ FPL asserts that having built and paid for the entire transmission network, the owner and the network customer should have the flexibility to use the network as they need. Utilities For Improved Transition See Florida Municipal Power Agency v. Florida Power & Light Company, 74 FERC  61,006 at 61,013 and n.70 (1996). E.g., FPL, Utilities For Improved Transition, TDU Systems, Carolina P&L, AEC & SMEPA, VT DPS, EEI. Docket Nos. RM95-8-001 -228- and RM94-7-002 declare that just as the firm point-to-point customer is permitted to maximize the use of its contract demand, the transmission provider and network customer should be entitled to maximize their long-term fixed cost obligation (citing AES Power, Inc., 69 FERC  61,345 at 62,300 (1994) (AES) for the proposition that the utility and its native load customers are obligated to pay all the costs of the transmission system without regard to the amount of energy actually scheduled). FPL and Carolina P&L suggest two possible solutions: (1) allow the transmission provider and network customer to have rights to the headroom beneath their fixed cost obligations at no additional charge, or (2) restrict the no-charge use of firm point-to-point headroom to transmission service associated with non-firm purchases to serve load. Under either of these options, they assert, the firm point-to-point customer's rights to make non-firm off-system sales would be on an even competitive footing with the transmission provider or network customer. PA Coops maintain that network customers should have the right to reassign/sell unused capacity below their 12-month rolling average peak demand at no additional charge. Cajun argues that network customers should be allowed to use the transmission system for non-firm (and perhaps firm) coordination transactions at no additional cost, provided the network customer's total use of the transmission system does not exceed its load ratio share. Cajun notes that the Commission seems to have determined elsewhere in the Rule that a network customer has Docket Nos. RM95-8-001 -229- and RM94-7-002 already paid for the full use of its load ratio share (citing mimeo at 332 and 338). In addition, Cajun states that requiring the network customer to use point-to-point service results in the network customer paying twice for the same capacity. VT DPS argues that the Commission should permit network users to make limited use of their network capacity to make off- peak off-system sales. It asserts that UtiliCorp's network tariff, filed in Docket No. ER95-203, provides a useful model: "the level of capacity utilized by the company or the customer for its combined network load and off-system sales load would be fixed by the tariff as the highest coincident peak load experienced by the transmitting utility in the three years preceding the off-system sale." According to VT DPS, this places all firm users on a par. In contrast, VT DPS argues that the Commission's solution is arbitrary and patently inadequate. VT DPS claims that concerned parties are not just transmission providers, but include state agencies and entities that need to take network service. VT DPS further argues that the lower priority for secondary service under the point-to-point tariff may pose an unacceptable risk to public utilities with firm obligations to serve their load, and having to agree to a fixed demand quantity may be unsatisfactory for public utilities with growing customer loads and a statutory obligation to serve those loads. Docket Nos. RM95-8-001 -230- and RM94-7-002 LEPA argues that [t]he Commission erred in not finding that in order to compete, one must be able to utilize base load units of 500MW size because entry without the ability to employ such base load units would make the putative entrant unable to compete; that in order to employ such units, or portions of them, the entrant had to engage in the coordinated development of base load units; that such coordinated development requires use of transmission for that purpose so as to be able to sell portions of the output of a baseload unit off-system, and that without 'headroom,' the cost of transmission for that purpose would not be comparable with the cost of transmission for the same purpose of the owner of the transmission. (LEPA at 5). Commission Conclusion The requests for rehearing on this issue present no arguments that were not fully considered in Order No. 888. Petitioners continue to claim that transmission providers and network customers are competitively disadvantaged vis-a-vis point-to-point transmission customers due to the point-to-point customers' ability to use as available, non-firm service over secondary points of receipt and delivery at no additional cost. The Commission attempted to strike a balance on this issue in Order No. 888 by allowing both network and point-to-point services to be priced on the same basis (i.e., no longer summarily rejecting the use of the average of the 12 monthly system peaks as the denominator for the rate for point-to-point service). Additionally, the Commission established a lower priority for the non-firm secondary point-to-point service than for either economy purchases by network customers or for stand- Docket Nos. RM95-8-001 -231- and RM94-7-002 alone non-firm point-to-point service, as discussed in Section IV.G.3.b. Accordingly, we believe that these concerns have been sufficiently addressed. Furthermore, these entities want to be allowed to make off- system sales under their network service at no additional charge as long as their total use of the system does not exceed their load ratio share. They claim that it is inequitable not to allow such "headroom" sales under the network service while allowing firm point-to-point customers to use non-firm transmission service up to their contract demands using secondary receipt and delivery points at no additional charge. As the Commission stated in Order No. 888, customers are not obligated to take network transmission service. 228/ If customers want to take advantage of the as-available, non-firm service over secondary points of receipt and delivery through the point-to-point service, they may elect to take firm point-to-point transmission service in lieu of the network service. We further note that transmission providers must take point-to-point transmission service for their own off-system sales, which results in comparable treatment for both the transmission provider and network customers. Transmission providers and other customers taking point-to-point transmission service do not need to be allowed to make "headroom" sales because they have access to as- available, non-firm service over secondary points of receipt and FERC Stats. & Regs. at 31,751; mimeo at 342-43. Docket Nos. RM95-8-001 -232- and RM94-7-002 delivery at no additional charge through their point-to-point service. Cajun's argument that a network customer has already paid for the full use of its load-ratio share of the system ignores the fact that network service is based on integrating a network customer's resources with its load, not on making off-system sales. This is why network customers pay for service on a load- ratio basis. If Cajun is concerned that it may need to pay for both network service and point-to-point service, Cajun can simply elect to take point-to-point service for all of its transmission needs. VT DPS' claim that the lower priority accorded to transmission service to secondary points of receipt and delivery under flexible point-to-point service would present an "unacceptable risk" to public utilities is unsubstantiated. If the risk of having this secondary service curtailed is too great, this customer has the option to: (1) take stand-alone non-firm point-to-point service (which has a higher priority), (2) take this service on a firm point-to-point basis, or (3) take network service, which has a higher priority for economy purchases than either stand-alone non-firm or secondary non-firm point-to-point service. With respect to LEPA's argument, the Commission has the goal of encouraging competition in the generation market, not discouraging generation competition by erecting barriers to entry such as arbitrary generator size. Furthermore, LEPA's argument Docket Nos. RM95-8-001 -233- and RM94-7-002 that comparability is not achieved without allowing headroom is incorrect because both network customers as well as the transmission provider must obtain point-to-point transmission service to accommodate transmission for wholesale sales. c. Load Ratio Sharing Allocation Mechanism for Network Service In the Final Rule, the Commission concluded that the load ratio allocation method of pricing network service continues to be reasonable for purposes of initiating open access transmission. 229/ The Commission also reaffirmed the use of a twelve monthly coincident peak (12 CP) allocation method because it believed the majority of utilities plan their systems to meet their twelve monthly peaks. However, the Commission stated that it would allow utilities to file another method (e.g., annual system peak) if they demonstrate that it reflects their transmission system planning. With respect to concerns raised about pancaked rates for network service provided to load served by more than one network service provider, the Commission indicated that if a customer wishes to exclude a particular load at discrete points of delivery from its load ratio share of the allocated cost of the transmission provider's integrated system, it may do so. However, customers that elect to do so, the Commission explained, must seek alternative transmission service for any such load that has not been designated as network load for network service. The FERC Stats. & Regs. at 31,736; mimeo at 296-97. Docket Nos. RM95-8-001 -234- and RM94-7-002 Commission indicated that this option is also available to customers with load served by "behind the meter" generation 230/ that seek to eliminate the load from their network load ratio calculation. (1) Multiple Control Area Network Customers Rehearing Requests A number of entities argue that excluding load from the designation of Network Load does not solve the pancaking problem and results in the network customer paying even more transmission charges. They contend that a network customer must still pay two network charges and point-to-point charges to be able to operate its resources across two control areas. The Commission's approach, they argue, makes it impossible for a network customer with loads and resources in multiple control areas to integrate those loads and resources on an economic dispatch basis. 231/ In essence, these entities state that a network customer must frequently dispatch resources in one transmission provider's control area (control area A) to serve that customer's load (in the case of a G&T cooperative, the load of a member system or third-party requirements customer) located in an adjacent control area of another transmission provider (control area B). As a result, they believe, the tariff essentially requires that network load in control area B, served by resources in control Behind-the-meter generation means generation located on the customer's side of the point of delivery. E.g., NRECA, TDU Systems, Blue Ridge. Docket Nos. RM95-8-001 -235- and RM94-7-002 area A, must be counted as load in control area B. Alternatively, they believe that the tariff allows the transmission of resources in control area A to load in control area B as point-to-point transmission that requires an additional charge. These entities argue that either of these situations produces uneconomic results for multiple control-area network customers. To avoid these problems, these entities propose that a network customer be allowed to use its network service to transmit power and energy from resources in control area A to serve load in control area B without designating the control area B load as network load for billing purposes. These entities suggest that no additional compensation should be required if such transfers to load in adjacent control areas plus other network transactions on behalf of the transmission customer in control area A do not exceed the customer's coincident demand in control area A. They also maintain that the ultimate solution is a regional system operated by an ISO. At the very least, TDU Systems contends, the Commission should require provision of service to network customers with loads and resources located on multiple systems under a rate that recovers the customer's load ratio share -- but no more -- of the transmission owners' collective transmission investment in the control areas that the customer straddles. AMP-Ohio maintains that rational economic transmission pricing policies demand elimination of the pancaking of rates Docket Nos. RM95-8-001 -236- and RM94-7-002 caused by the arbitrary ownership boundaries of individual utilities. TAPS asks that the Commission clarify that the Commission will look closely at how to create and promote region-wide rates when evaluating mergers and market-based rate proposals. It argues that the Commission should be receptive to section 211 filings seeking non-pancaked rates and should establish a Stage 3 for the purpose of addressing directly the need for transmission access on a non-pancaked, regional basis. Commission Conclusion In the Final Rule, the Commission addressed concerns regarding pancaked rates for network service for customers with load in multiple control areas. 232/ Tariff section 31.3 allows a network customer the option to exclude all load from its designated network load that is outside the transmission provider's transmission system, and to serve such load using point-to-point transmission service. NRECA and TDU Systems, however, argue that network customers located in multiple control areas should not have to pay for any additional point-to-point transmission service to make sales to non-designated load located in a separate control area. We disagree. Because the additional transmission service to non- designated network load outside of the transmission provider's control area is a service for which the transmission provider FERC Stats. & Regs. at 31,736; mimeo at 297. Docket Nos. RM95-8-001 -237- and RM94-7-002 must separately plan and operate its system beyond what is required to provide service to the customer's designated network load, it is appropriate to have an additional charge associated with the additional service. AMP-Ohio's concerns regarding "arbitrary ownership boundaries of individual utilities," and TAP's proposal to require regional rates are beyond the scope of Order No. 888. 233/ However, as the Commission explained in the Final Rule, it encourages the voluntary formation of regional transmission groups, as well as the establishment of regional ISOs, and will address those matters on a case-by-case basis. (2) Twelve Monthly Coincident Peak v. Annual System Peak Rehearing Requests Several utilities ask that the Commission eliminate the requirement that charges for network service be calculated using a 12-month rolling average load ratio share and allow utilities discretion to determine the way network customers pay. 234/ They assert that the requirement makes it impossible to recover the full cost of service when customers begin or terminate service. They suggest a unit charge based on a formula rate that is trued up each year or a month-by-month load ratio share calculation. These entities do not explain how the Commission could force non-public utility control area operators, of which there are approximately 62 out of 138 in the United States (as of October 1996), to accede to these pricing policies. E.g., Utilities For Improved Transition, Florida Power Corp, VEPCO. Docket Nos. RM95-8-001 -238- and RM94-7-002 NE Public Power District states that the definition of load ratio share in section 1.16 of the pro forma tariff, taken together with sections 34.2 and 34.3 of the pro forma tariff require the use of the 12-CP method and the inclusion of losses to the generator bus. This, it argues, is inconsistent with the Commission's statement that "[u]tilities that plan their systems to meet an annual system peak . . . are free to file another method if they demonstrate that it reflects their transmission system planning." (NE Public Power District at 22-23). NE Public Power District argues that utilities should be allowed to use CP demands measured at delivery points at some common specified voltage. It further asks the Commission to clarify whether the monthly peak includes or excludes transmission losses. EEI and AEP argue that transmission reservations for services of less than one month's duration and any discounted firm transactions should not be counted in the load ratio calculation when determining the 12 CP on point-to-point rates, but that the revenues from these services should be credited to all firm transmission users. Montana Power argues that the Commission's pricing approach discriminates against native load customers because all non- network uses of the system do not occur at full, non-discounted prices for the entire month and the effects of discounts will be shouldered by native load customers. According to Montana Power, this is a disincentive to utilities to offer discounts and creates a possibility of gaming by network customers buying one- Docket Nos. RM95-8-001 -239- and RM94-7-002 day firm point-to-point reservations to reduce their network load ratio shares. Commission Conclusion While the Commission reaffirmed the use of a twelve monthly coincident peak (12 CP) allocation method for pricing network service in the Final Rule, the Commission also stated: [u]tilities that plan their systems to meet an annual system peak . . . are free to file another method if they demonstrate that it reflects their transmission system planning. [235/] Accordingly, utilities are free to propose in a section 205 filing an alternative to the use of the 12-month rolling average (e.g., annual system peak) in the load ratio share calculation, subject to demonstrating that such alternative is consistent with the utility's transmission system planning and would not result in overcollection of the utility's revenue requirement. Any proposed alternative would also be subject to any future filing conditions established by the Commission. 236/ We also are not convinced that we should require the calculation of load ratios using a particular method on a generic basis. Any such proposals, including those concerning the treatment of discounted firm transmission transactions in the load ratio calculation and revenue credits associated with such FERC Stats. & Regs. at 31,736; mimeo at 296-97. FERC Stats. & Regs. at 31,770; mimeo at 398-99. Docket Nos. RM95-8-001 -240- and RM94-7-002 transactions, are best resolved on a fact-specific, case-by-case basis. Finally, the Final Rule does not prohibit utilities from "us[ing] CP demands measured at delivery points at some common specified voltage" as claimed by NE Public Power District. Treatment of transmission losses can be accomplished in different ways by different transmission providers under the pro forma tariff, such as adjustment to a consistently applied voltage level. Regarding NE Public Power District's allegation that certain sections of the pro forma tariff do not allow the use of the annual system peak method in the load ratio share calculation, the Commission recognizes that certain rate methodologies may require minor adjustments to the non-price terms and conditions to be consistent with the proposed rate methodology. However, any modifications to the non-price terms and conditions established in the pro forma tariff must be fully supported by the utility and the appropriateness of such proposed changes will be evaluated by the Commission for consistency with the proposed rates or rate methodologies. The remainder of NE Public Power District's concerns are case-specific and should be raised by NE Public Power District at such time as a transmission provider makes a filing. Docket Nos. RM95-8-001 -241- and RM94-7-002 (3) Load and Generation "Behind the Meter" Rehearing Requests Several entities request clarification 237/ concerning the definition of Network Load in pro forma tariff section 1.22, which provides, in pertinent part, that: A Network Customer may elect to designate less than its total load as Network Load but may not designate only part of the load at a discrete Point of Delivery. These entities maintain that section 1.22 is too restrictive and is inconsistent with the Final Rule's treatment of load served from "behind the meter" generation. 238/ Specifically, these entities request that the Commission clarify that a network customer can exclude from its designated network load a portion of load at a discrete point of delivery, which is served from generation behind the meter. In support of this position, a number of petitioners cite to FMPA v. FPL, 74 FERC  61,006 at 61,012-13, in which they claim the Commission allowed network customers to exclude load served by behind the meter generation. 239/ TAPS asserts that there is no operational or economic reason to require the designation of all load at a discrete point of delivery as network load. E.g., AMP-Ohio, TAPS. See FERC Stats. & Regs. at 31,736 and 31,743; mimeo at 297 and 317. E.g., TAPS, Central Minnesota Municipal. Docket Nos. RM95-8-001 -242- and RM94-7-002 FMPA argues that network customers should not be charged a network rate to use their own transmission (or distribution) system to serve loads that are located beyond the transmission owner's system. FMPA interprets the Final Rule on this issue as allowing a network customer that has behind-the-meter generation to serve part of its behind the meter load from such generation; thus, a customer can exclude that load, which is served without using the transmission provider's transmission system, from the load ratio share. FMPA's interpretation of section 1.22 is that "a network customer may not import power using both point-to- point and network transmission service at the same delivery point, but that this Section does not prevent a network customer from serving load from generation when both are behind the delivery point and when the transaction does not rely upon use of the transmission provider's transmission system." (FMPA at 5). FMPA requests that the Commission clarify the language in section 1.22 consistent with its interpretation above. Michigan Systems asks the Commission to modify section 1.22 because the "clause may be interpreted to require network integration transmission service customers to pay a second time for the transmission of power that is already being transmitted under other arrangements, such as transmission ownership. The clause could also be interpreted to allow the transmission provider to charge customers for the transmission of power which does not use the transmitter's system, such as for transmission Docket Nos. RM95-8-001 -243- and RM94-7-002 from 'behind the meter' generation to 'behind the meter' load." (Michigan Systems at 5-13). Wisconsin Municipals ask the Commission to "clarify that a partial designation is appropriate if (1) only part of the load behind a particular delivery point relies upon the transmission provider's transmission system for service or (2) a network customer is responsible for serving only a portion of the load behind a discrete delivery point." (Wisconsin Municipals at 17- 18). Blue Ridge asks the Commission to clarify that it intended to allow for multiple ownership of resources by customers who are not network customers. Utility Position FPL and Carolina P&L ask the Commission to clarify that section 1.22 and the Rule (see also Original Sheet No. 94 and FMPA I, 67 FERC  61,167 at 61,481-82 (1994)) mean that regardless of whether or not a customer has behind the meter or local generation at a delivery point, if a customer wants to purchase network service to serve load at a delivery point, it must purchase network service for all such load -- the customer cannot split the load into network and point-to-point components at a specific point of delivery. 240/ Otherwise, FPL states, Utilities For Improved Transition argues that a transmission dependent utility should be required to serve its load using only network transmission service. It asserts that such a utility should not be allowed to avoid its full cost responsibility by using point-to-point firm during peak (continued...) Docket Nos. RM95-8-001 -244- and RM94-7-002 there would be a split system with the potential to game the system and problems with how it would work. AEP argues that the option in section 1.22 of excluding load from network load should be deleted. AEP states that, as the Commission recognized in its original FMPA v. FPL order, the provision is contrary to the comparability standard. Specifically, AEP argues that transmission-owning utilities do not and cannot offer themselves partial integration service electing to pay only a portion of the network costs, but rather must pay for the entire network, which integrates all of the transmission-owning utility's resources and loads. According to AEP, the load served by behind-the-meter generation is not isolated from the system, which is there to serve that load when the behind-the-meter generation is unavailable. Allowing a network customer to use short-term non-firm point-to-point transmission, AEP asserts, allows customers to evade a large portion of the network's costs, which they will do on an unconstrained system such as AEP. (...continued) periods and non-firm service during non-peak periods. See also VEPCO. Moreover, FMPA filed an answer in opposition to the requests for clarification of FP&L, Carolina P&L and others concerning the definition of network load and related issues. (FMPA Answer). Likewise, Michigan Systems and TAPS filed answers opposing these requests for rehearing. (Michigan Systems Answer and TAPS Answer). While answers to requests for rehearing generally are not permitted, we will depart from our general rule because of the significant nature of this proceeding and accept the FMPA Answer, Michigan Systems Answer and TAPS Answer. Docket Nos. RM95-8-001 -245- and RM94-7-002 Commission Conclusion We disagree that the prohibition in tariff section 1.22 against a network customer designating only part of a load at a discrete point of delivery as network load is either inconsistent with the Final Rule's treatment of generation "behind the meter" or is contrary to the Commission's decisions in FMPA I and FMPA II. The Commission addressed "behind the meter" generation in the Final Rule as follows: if a customer wishes to exclude a particular load at discrete points of delivery from its load ratio share of the allocated cost of the transmission provider's integrated system, it may do so. [citing Florida Municipal Power Agency v. Florida Power & Light Company, 74 FERC  61,006 (1996), reh'g pending.] Customers that elect to do so, however, must seek alternative transmission service for any such load that has not been designated as network load for network service. This option is also available to customers with load served by 'behind the meter' generation that seek to eliminate the load from their network load ratio calculation. [241/] Implicit in the Commission's discussion of this issue in the Final Rule and also in FMPA I and FMPA II, in permitting the "exclusion of a particular load," is that the Commission will allow a network customer to exclude the entirety of a discrete load from network load, but not just a portion of the load served by generation behind the meter. FERC Stats. & Regs. at 31,736; mimeo at 297. Docket Nos. RM95-8-001 -246- and RM94-7-002 In its request for rehearing of FMPA I, FMPA requested that the Commission confirm its interpretation of the Commission's finding in FMPA I that: [FMPA] can choose to serve an amount of load in a city from generation in the city, so long as FMPA does not sometimes serve that level of load from external generation or use that generation to serve member loads outside the city. [242/] On rehearing in FMPA II, the Commission did not grant FMPA's request to allow a partial designation of network load. Furthermore, the Commission provided an example of how FMPA could request that certain of its loads and resources be excluded from network integration transmission service. The Commission explained that FMPA could choose to exclude the loads of the cities of Ft. Pierce and Vero Beach from the request for network integrated transmission service and alternatively request point- to-point transmission service to transmit power from resources in those cities to other FMPA members or from FMPA member cities to Ft. Pierce and Vero Beach. 243/ The Commission neither stated that it would allow a partial designation of a discrete load as network load nor provided any examples of such treatment. Additionally, throughout the pro forma tariff, network customers are consistently prohibited from designating only a portion of a discrete network load. For example, tariff section 31.2 provides: FMPA II at 61,012 (emphasis added). FMPA II at 61,011. Docket Nos. RM95-8-001 -247- and RM94-7-002 To the extent that the Network Customer desires to obtain transmission service for a load outside the Transmission Provider's Transmission System, the Network Customer shall have the option of (1) electing to include the entire load as Network Load for all purposes under Part III of the Tariff and designating Network Resources in connection with such additional Network Load, or (2) excluding that entire load from its Network Load and purchasing Point-To-Point Transmission Service under Part II of the Tariff. [Emphasis added] Accordingly, we find that no inconsistency exists between the tariff language and either the language in the Final Rule or the Commission's findings in FMPA I or FMPA II. In support of its position to allow a partial designation of network load at a point of delivery, TAPS claims that there are no operational reasons to require the designation of all load at a discrete point of delivery as network load. We disagree. Utilities, both commenting on the NOPR and on rehearing (e.g., AEP rehearing at 19-20 and Florida Power & Light at 14-18), express concern that customers allowed to divide a discrete load between point-to-point and network services would create a "split system." The concept of allowing a "split system" or splitting a discrete load is antithetical to the concept of network service. A request for network service is a request for the integration of a customer's resources and loads. Quite simply, a load at a discrete point of delivery cannot be partially integrated -- it is either fully integrated or not integrated. Furthermore, such a split system creates the potential for a customer to "game the Docket Nos. RM95-8-001 -248- and RM94-7-002 system" thereby evading some or all of its load-ratio cost responsibility for network services. 244/ For example, FMPA asserts that if a FMPA member city has a peak load of 100 MW and behind the meter generation of 75 MW, FMPA should be allowed to designate a portion of its load as network load (e.g., 60 MW), and to serve the remaining load (e.g., 40 MW) from its behind-the-meter generation. 245/ However, as a number of utilities note, this would lead to the possibility of gaming the system. For example, if at the time of the monthly system peak the FMPA member city generates more than 40 MW (or takes short-term firm transmission service (or a combination of the two)), it may be able to lower its monthly coincident peak load for network billing purposes, 246/ and thereby reducing if not eliminating its load-ratio cost responsibility for network service. Because network and native load customers bear any residual system costs on a load-ratio basis, any cost responsibility evaded by a network customer in this manner would be borne by the remaining network customers and native load. The load-ratio cost responsibility is based on the network customer's monthly contribution to the transmission system peak (i.e., coincident peak billing). FMPA at 3-4. While this customer could lower its coincident peak use of the transmission system, it could be making substantial use of the transmission system during all other hours of the month but yet have little or no load-ratio cost responsibility. Docket Nos. RM95-8-001 -249- and RM94-7-002 FPL also raises several fundamental operational problems associated with allowing partial network service or creating a "split system:" If all the loads are included in a single control area, how does the transmission provider know what portion of the power delivered is serving the point-to-point load (which presumably would not be counted toward the network's load ratio)? Using the same 100 MW load example previously mentioned where there is a 40/60 network/point-to-point split, there would have to be a determination of how the split would be done in non-peak situations. Are the first 40 MW of load all network load, or all point-to-point load, or split on a 40/60 basis? If the system purchases economy power from non-local resources, how is that delivery allocated between the network portion (for which there would be no point-to-point scheduling, curtailment, or transmission charges) and the point-to-point portion (which must be arranged and paid for separately under a point-to-point tariff)? The bottom line is that all potential transmission customers, including those with generation behind the meter, must choose between network integration transmission service or point-to- point transmission service. Each of these services has its own advantages and risks. 247/ Customers taking network integration transmission service choose to have the transmission provider integrate their generation resources with their loads. Network service is a service comparable to the service that the transmission provider provides to its retail native load, where the Transmission Provider includes the network customers resources and loads (projected over a minimum ten-year period) into its long-term planning horizon. Because network service is usage (continued...) Docket Nos. RM95-8-001 -250- and RM94-7-002 In choosing between network and point-to-point transmission services, the potential customer must assess the degree of risk that it is willing to accept associated with the availability of firm transmission capacity. Customers choosing point-to-point service, based solely on the amount of transmission capacity reserved (or contract demand), may face a relatively higher risk associated with the availability of firm transmission capacity. For example, if a customer with a peak load of 100 MW, and behind the meter generation of 75 MW, chooses to serve a portion of its load with point-to-point transmission service (e.g., 60 MW) and the remaining load (e.g., 40 MW) with its behind-the-meter generation, this customer faces the risk that, should its generation behind the meter become unavailable, the transmission provider may not have firm transmission capacity available to serve the remaining 40 MW of that customer's load. One way to minimize this risk would be for the customer to reserve and pay for additional firm point-to-point transmission service to protect against the unavailability of its behind-the-meter generation. Alternatively, the customer could choose network (...continued) based, network customers pay on the basis of their total load, paying a load-ratio share of the costs of the transmission provider s transmission system on an ongoing basis. In contrast, point-to-point transmission service is more transitory in nature. Point-to-point service is frequently tailored for discrete transactions for various time periods, which may or may not enter into the transmission provider's planning horizon. A point-to- point transmission service customer is only responsible for paying for its reserved capacity on a contract demand basis over the contract term. Docket Nos. RM95-8-001 -251- and RM94-7-002 service in which the transmission provider will plan and provide for firm transmission capacity sufficient to meet the customer's current and projected peak loads, including integration of the customer's behind-the-meter generation as a network resource. For the reasons stated above, a network customer will not be permitted to take a combination of both network and point-to- point transmission services under the pro forma tariff to serve the same discrete load. Accordingly, the requests for rehearing to modify tariff section 1.22 are hereby rejected. Moreover, the Commission will allow a network customer to either designate all of a discrete load 248/ as network load under the network integration transmission service or to exclude the entirety of a discrete load from network service and serve such load with the customer's "behind-the-meter" generation and/or through any point-to-point transmission service. 249/ We also clarify that while the tariff prohibits the designation of only part of the load at a discrete point of delivery, this prohibition also applies to network customers with a discrete load served by multiple points of delivery. In other words, for the same reasons explained above, a customer may not choose to have part of a discrete load served under network integration service at one or more delivery points and at the same time have the remaining portion of the same load served under point-to-point transmission service at other delivery points. An example of excluding the entirety of a discrete load would be a municipal power agency excluding the entire load of a member city with generation behind the meter, while requesting network service to serve the remaining member cities' loads. The excluded load of the member city must be met using a combination of generation behind the meter and any remote generation that may be necessary. The member city would be responsible for arranging any point-to-point transmission service (continued...) Docket Nos. RM95-8-001 -252- and RM94-7-002 (4) Existing Transmission Arrangements associated with Generating Capacity Entitlements (e.g., "preference power" customers of PMAs) Rehearing Requests Several entities argue that section 1.22 of the pro forma tariff is arbitrary and cannot be reconciled with the Final Rule's determination not to abrogate existing agreements. 250/ Specifically, several transmission customers claim that the prohibition against designating only part of the load at a discrete point of delivery is problematic for customers with existing transmission arrangements for receiving preference power or capacity entitlements from power marketing agencies (PMAs). For example, Central Minnesota Municipal argues that the limiting language of section 1.22 should be eliminated as it would preclude Mountain Lake (a member of Central Minnesota Municipal) from using network transmission and, at the same time, point-to- point transmission for WAPA power under a separate arrangement. These transmission customers assert that if they designate all of the load at a discrete point of delivery as network load, and pay for such network load on a load-ratio basis, then the transmission provider is paid twice for the same transmission service -- once through the existing transmission arrangement and a second time through the network service. (...continued) under the pro forma tariff that may be necessary to import the power and energy from any remote generation. E.g., NRECA, TDU Systems, AEC & SMEPA. Docket Nos. RM95-8-001 -253- and RM94-7-002 NRECA and TDU Systems argue that if a customer chooses to use network service under the pro forma tariff to supplement its existing arrangements to meet future full requirements, the Commission should amend section 1.22 so the transmission provider cannot overcharge the customer: A Network Customer may elect to designate less than its total load as Network Load. Where a Network Customer has elected not to designate a particular load as a Network Load, the Network Customer is responsible for making separate arrangements under Part II of the Tariff for any Point-to-Point Transmission Service that may be necessary for such non-designated load, unless such non-designated load is served pursuant to other arrangements. [251/] Alternatively, the transmission customer may choose not to designate any load at a discrete point of delivery as network load. However, these transmission customers note that the preference power allotments received from PMAs typically do not equal the total load of a customer at a discrete point of delivery. Therefore, the customer would need to acquire additional point-to-point transmission service for any remaining transmission needs. Accordingly, these transmission customers conclude that the existence of their current transmission arrangements precludes them from receiving network service which they claim does not allow the comparable use of the system that the transmission provider enjoys. Commission Conclusion NRECA at 78-79; TDU Systems at 32. Docket Nos. RM95-8-001 -254- and RM94-7-002 The Commission recognizes that existing power and transmission arrangements represent a transitional problem as customers begin to take service under the pro forma tariff. Clearly, the Commission did not intend for a transmission provider to receive two payments for providing service to the same portion of a transmission customer's load. Any such double recovery is unacceptable and inconsistent with cost causation principles. Neither did the Commission intend to allow a transmission customer to designate less than its total load as network load at a discrete point of delivery even though a portion of that load is served under a pre-existing contract. We clarify that such a transmission customer has several alternatives it can pursue using either point-to-point or network transmission service. Using network transmission service, the network customer would designate its existing generation supply contract(s) as a network resource(s) and the associated load served under such contract(s) designated as network load. The network customer then has two options: pursue negotiations with the transmission provider to obtain a credit on its network service bill for any separate transmission arrangements or for the unbundled transmission rate component of the existing generation supply contract or (2) seek to have any separate transmission or the unbundled transmission rate component of its generation supply Docket Nos. RM95-8-001 -255- and RM94-7-002 contract eliminated in recognition of the network transmission service now being provided and paid for under the tariff. 252/ Using point-to-point transmission service, the transmission customer would identify the discrete points of delivery being served under existing generation supply and existing transmission contracts and acquire additional point-to-point transmission service under the tariff for any remaining load at those discrete points of delivery. Any of these three alternatives should address concerns regarding the possibility of double recovery. Furthermore, a transmission customer may file a complaint under section 206 with the Commission to address any claims of double recovery that it is unable to resolve with the transmission provider. d. Annual System Peak Pricing for Flexible Point-to-Point Service In the Final Rule, the Commission indicated that it will allow a transmission provider to propose a formula rate that assigns costs consistently to firm point-to-point and network services. 253/ The Commission added that it will no longer summarily reject a firm point-to-point transmission rate developed by using the average of the 12 monthly system peaks. The Commission explained that it still believed that it was appropriate for utilities to use a customer-specific allocated Clearly, any such modification of existing contracts would required the agreement of all parties and a filing with the Commission. FERC Stats. & Regs. at 31,737-38; mimeo at 301-04. Docket Nos. RM95-8-001 -256- and RM94-7-002 cost of service to account for diversity, but based on the changed circumstances since Southern Company Services, Inc., 61 FERC  61,339 (1992) (Southern), it indicated that it would now permit an alternative. Thus, the Commission indicated that it will allow all firm transmission rates, including those for flexible point-to-point service, to be based on adjusted system monthly peak loads. In order to prevent over-recovery of costs for those who use this approach, the Commission explained that it will require transmission providers to include firm point-to-point capacity reservations in the derivation of their load ratio calculations for billings under network service. In addition, the Commission explained that revenue from non-firm transmission services should continue to be reflected as a revenue credit in the derivation of firm transmission tariff rates. The Commission noted that the combination of allocating costs to firm point-to-point service and the use of a revenue credit for non-firm transmission service will satisfy the requirements of a conforming rate proposal enunciated in our Transmission Pricing Policy Statement. 254/ Rehearing Requests Blue Ridge maintains: The sea change in the Commission's approach to the pricing of transmission services is not warranted by any claimed change in circumstances and Blue Ridge accordingly FERC Stats. & Regs.  31,005 (1994). Docket Nos. RM95-8-001 -257- and RM94-7-002 requests rehearing and rejection of the new approach. At a minimum, the Commission should clarify that any deviation from use of an annual peak divisor (or other methodology based on system capability) for setting point-to-point transmission rates will be considered only on a case-by-case basis. TAPS also argues that the use of the same denominator for two different services is inconsistent, unjust and discriminatory. It asserts that the Commission should use a system capability divisor for allocating fixed costs between reservation-based and load-based firm service. TAPS also asserts that most utilities plan their transmission systems to cover the annual system peak estimated conservatively on the higher side in order to meet unusually high loads reliably, rather than planning on the basis of the twelve monthly peaks as stated in Order No. 888. Therefore, TAPS asks that the Commission maintain 1 CP pricing for point-to-point service. TAPS argues that the Commission should allow transmission providers and customers to demonstrate the appropriate measure for each transmission system's capability in utility-specific proceedings. If the Commission uses a 12 CP denominator, TAPS requests that the Commission clarify that capacity reservations should be established consistently with that denominator and should recognize the inappropriateness of using such rates as a cap for non-firm rates. It asserts that non-firm rates should be limited to actual variable costs of transmission, plus losses, plus a modest adder as a contribution toward fixed costs. At the very Docket Nos. RM95-8-001 -258- and RM94-7-002 least, TAPS argues that the cap should be developed using a more appropriate denominator, e.g., system capability. TAPS further argues that if the rate divisor is based on experienced 12 CP, the capacity reservations and the divisor should be measured at the delivery points (as it is for native load customers), not the higher of the receipt or delivery points, to avoid a mismatch between the rate divisor and billing determinants. 255/ Wisconsin Municipals and TAPS argue that if a 12 CP divisor is used, customers must have the flexibility to vary their monthly nomination under the point-to-point tariff. Commission Conclusion With respect to TAPS argument that the annual system peak method would be appropriate for most systems, the Commission has determined in Order No. 888 that this issue is best resolved on a case-by-case basis and specifically provided utilities the opportunity to propose to use other allocation methods, including the annual system peak method sought by TAPS. 256/ The Commission already recognized the potential for a mismatch between the rate divisor and billing determinants that TAPS now raises on rehearing. We explicitly stated in the Final Rule that See also NE Public Power District. FERC Stats. & Regs. at 31,736; mimeo at 296-97. Docket Nos. RM95-8-001 -259- and RM94-7-002 [t]he adjusted system monthly peak loads consist of the transmission provider's total monthly firm peak load minus the monthly coincident peaks associated with all firm point-to-point service customers plus the monthly contract demand reservations for all firm point-to-point service. [257/] Use of the adjusted system monthly peak loads in the rate divisor for flexible point-to-point transmission service eliminates the mismatch concern raised by TAPS. We have also fully addressed in the Final Rule those arguments objecting to the use of the average of the 12 monthly peaks in determining a firm point-to-point transmission rate and no further discussion is required. The other arguments raised with respect to this section are fact specific and best addressed in individual rate proceedings where the use of an annual system peak versus an average of the 12 monthly peaks in determining a firm point-to-point transmission rate is more appropriately evaluated. e. Opportunity Cost Pricing (1) Recovery of Opportunity Costs The Commission emphasized in the Final Rule that it had fully explained its rationale for allowing utilities to charge opportunity costs in Northeast Utilities and Penelec. 258/ The FERC Stats. & Regs. at 31,738; mimeo at 303. Northeast Utilities Service Company (Northeast Utilities), 56 FERC  61,269 (1991), order on reh'g, 58 FERC  61,070, reh'g denied, 59 FERC  61,042 (1992), order granting motion to vacate and dismissing request for rehearing, 59 FERC  61,089 (1992), aff'd in relevant part and remanded in part, (continued...) Docket Nos. RM95-8-001 -260- and RM94-7-002 Commission also explained that transmission providers proposing to recover opportunity costs must adhere to the following requirements: (1) A fully developed formula describing the derivation of opportunity costs must be attached as an appendix to their proposed tariff; (2) Proposals must address how they will be consistent with comparability; and (3) All information necessary to calculate and verify opportunity costs must be made available to the transmission customer. Rehearing Requests VT DPS disputes the Commission's holding with respect to opportunity costs and argues that rate filings seeking recovery of opportunity costs should be summarily rejected. It asserts that, contrary to statements by the Commission, courts have not endorsed opportunity cost pricing for transmission customers and maintains that the Commission's failure to consider objections to opportunity cost pricing on the merits "directly flouts the court's ruling" in Northeast Utilities. According to VT DPS, opportunity costs are inherently unverifiable: "there are insuperable difficulties in proving the existence of lost (...continued) Northeast Utilities Service Company v. FERC, 993 F.2d 937 (1st Cir. 1993); Pennsylvania Electric Company (Penelec), 58 FERC  61,278 at 62,871-75, reh'g denied, 60 FERC  61,034 (1992), aff'd, Pennsylvania Electric Company v. FERC, 11 F.3d 207 (D.C. Cir. 1993). Docket Nos. RM95-8-001 -261- and RM94-7-002 opportunity costs in any fashion which can readily and objectively be applied." At a minimum, VT DPS asserts, opportunity costs arising more than five years out are unverifiable and should not be permitted. Moreover, VT DPS argues that the right to challenge the verifiability of opportunity costs is not adequate protection because it is wasteful and burdensome (citing Cajun Electric Power Cooperative v. FERC, 28 F.3d 173 at 179 (D.C. Cir. 1994) (Cajun)). VT DPS also asserts that the Commission's treatment is inconsistent with its treatment of gas pipeline pricing policies, which do not permit the assessment of opportunity costs in gas pipeline transportation rates. In addition, VT DPS asserts that opportunity cost pricing for firm transportation service would allow the transmitting utility to charge more for firm transmission of a third party's power supplies than it charges its own native load for the transmission component of native load service. Finally, VT DPS claims that opportunity cost pricing contravenes Cajun because opportunity cost pricing has a chilling effect on competition in New England and nationally. VT DPS challenges whether a tariff provision that permits the imposition of opportunity costs "precludes the mitigation of [a utility's] market power." CCEM asserts that there is no justification for allowing opportunity cost charges when such charges can be eliminated in the secondary or released capacity market, without the discriminatory charge. It notes that opportunity costs are not Docket Nos. RM95-8-001 -262- and RM94-7-002 allowed in any other industry and the Commission should not allow recovery of lost profits. American Forest & Paper argues that the only way to ensure comparability is to require that transmission services are priced for all customers based upon embedded cost principles (including pricing for expansions). It opposes opportunity cost pricing as being discriminatory because wheeling customers are required to compensate the transmitting utility for its lost opportunities to make economy purchases or sales to benefit native load. It further argues that transmission capacity was not designed to facilitate non-firm, unplanned economy purchases or sales on behalf of native load. American Forest & Paper also asserts that allowing redispatch costs incorrectly presupposes that native load has a superior right to the transmission system. According to American Forest & Paper, neither of these costs (opportunity/redispatch) should be imposed on the former sales, now transmission-only, customers -- the transmission customer is no more responsible for the alleged transmission constraint than the existing native load customer who adds to its requirements or the new customer locating in the service territory. It maintains that firm transmission contracts cannot by definition displace opportunity sales because there is no "opportunity" until there is capacity in excess of the firm transmission contractual commitments. In addition, American Forest & Paper asserts that opportunity cost pricing may create difficulties for IPPs, i.e., a lender may not finance projects because of cost uncertainty Docket Nos. RM95-8-001 -263- and RM94-7-002 related to varying revenue flows caused by opportunity cost pricing. It believes that utilities should be required to establish a separate subsidiary to make opportunity purchases or sales on its behalf, which may minimize self dealing. 259/ It further asserts that expansions should be subject to embedded cost pricing -- unlike in gas pipeline expansions, electric transmission expansions invariably affect an integrated network. CCEM asserts that, if opportunity cost pricing is maintained, transmission customers should be given the information they need to avert or mitigate opportunity-cost exposure. In particular, it argues that customers need information on the run status and cost of generating units that the transmission provider controls in advance of any proposed redispatch. In addition, CCEM argues that transmission providers should be required to inform customers of a redispatch in advance. Commission Conclusion As an initial matter, many of the arguments raised are collateral attacks on Penelec, Northeast Utilities, and the Commission's Transmission Pricing Policy Statement. These matters are not the subject of this proceeding, but rather Order The Commission has effectively achieved this result for opportunity sales by requiring separation of the transmission provider's wholesale merchant from its transmission operation employees. Docket Nos. RM95-8-001 -264- and RM94-7-002 No. 888 simply applies the policy already in place. Therefore, these arguments are not properly raised in this proceeding. 260/ The Commission does not believe that any changes are necessary to its policy on opportunity cost recovery. 261/ In the Final Rule, we fully explained our rationale for allowing utilities to charge opportunity costs and no arguments have been presented on rehearing that would persuade us otherwise. As has been our policy, we will continue to determine the appropriateness of opportunity cost pricing proposals on a case- by-case basis. We continue to believe that opportunity cost These arguments include those made by VT DPS concerning Northeast Utilities and alleged inconsistencies with our natural gas policies. Under the Commission's transmission pricing policy, utilities are limited to charging the higher of embedded costs or opportunity/incremental costs. See Order on Reconsideration and Clarifying Policy Statement, 71 FERC  61,195 (1995). Opportunity costs are capped by incremental expansion costs. Opportunity costs are viewed as a form of incremental or marginal cost pricing and include: (1) out- of-rate costs or costs associated with the uneconomic dispatch of generating units necessary to accommodate a transaction; and (2) costs that arise from a utility having to reduce its off-system purchases or sales in order to avoid a potential constraint on the transmission grid. We note that Order No. 888 requires that off-system sales by the transmission provider must be made under the point-to- point provisions of the pro forma tariff. If a utility expands its transmission system so that it can provide the requested transmission service, it can charge the higher of its embedded costs or its incremental expansion costs. When a transmission grid is constrained and a utility does not expand its system, the Commission has allowed a utility to charge transmission-only customers the higher of embedded costs or legitimate and verifiable opportunity costs ("or" pricing), but not the sum of the two ("and" pricing). Docket Nos. RM95-8-001 -265- and RM94-7-002 pricing will promote efficient decision-making by both transmission owners and users and will not result in unduly discriminatory or anticompetitive pricing. We have stated that because any transmission pricing proposal must meet the comparability standard, we will have ample opportunity to address any concerns that opportunity cost pricing may be unfair and anticompetitive or otherwise inconsistent with the comparability standard, including those concerns raised by CCEM with respect to the need for advance information as to any proposed redispatch. We note that in compliance filings made pursuant to Order No. 888, most utilities did not make the tariff changes necessary to charge opportunity costs to customers under the pro forma tariff. Absent a subsequent section 205 filing, these transmission providers will not be able to charge opportunity costs under their compliance tariffs. Where transmission providers did modify their tariff to allow for opportunity costs, the Commission is reviewing the proposed charges on a case-by- case basis. (2) Redispatch Costs In the Final Rule, the Commission clarified that redispatch is required only if it can be achieved while maintaining reliable operation of the transmission system in accordance with prudent utility practice. 262/ FERC Stats. & Regs. at 31,739-40; mimeo at 307-09. Docket Nos. RM95-8-001 -266- and RM94-7-002 The Commission further explained that the recovery of redispatch costs requires that: (1) a formal redispatch protocol be developed and made available to all customers; and (2) all information necessary to calculate redispatch costs be made available to the customer for audit. The Commission also noted that the rates proposed must meet the standards for conforming proposals in the Transmission Pricing Policy Statement. The Commission also explained in the Final Rule that if the transmission provider proposes to separately collect redispatch costs on a direct assignment basis from a specific transmission customer, the transmission provider must credit these revenues to the cost of fuel and purchased power expense included in its wholesale fuel adjustment clause. 263/ Rehearing Requests TAPS asserts that there is too much uncertainty with respect to the treatment of redispatch costs. It asserts that the Commission should require a section 205 filing for each corridor/constraint for which redispatch costs are intended to be shared among the transmission provider and network customers. Once there has been a determination regarding a particular corridor/constraint, TAPS argues that "it would be appropriate to charge network customers for redispatch costs through a mechanism with no fewer protections than a fuel clause." It further argues that redispatch costs, like opportunity costs, should be capped FERC Stats. & Regs. at 31,740; mimeo at 309. Docket Nos. RM95-8-001 -267- and RM94-7-002 at the cost of the upgrade and, at the least, the Commission should clarify that application of the redispatch sharing provision should be adjudicated in particular cases. TDU Systems states that it does not object to a redispatch obligation that is necessary to ensure transmission system reliability, but they object to the fact that a transmission provider can determine that a transmission constraint will arise as a result of the sale of additional firm transmission service by the transmission provider. It asks the Commission to clarify that the transmission constraint that would trigger a redispatch obligation cannot be caused by a transmission provider's sale of additional firm transmission capability. Wisconsin Municipals asks the Commission to clarify that recovery of redispatch costs on a load ratio basis, without a section 205 filing, is limited to when such action is necessary for reliability reasons alone (not for economic reasons), and that in all other circumstances a section 205 filing must be made and costs directly assigned to the customer receiving the economic benefit of the redispatch. It further asserts that if redispatch is allowed for economic reasons, it must be offered on a comparable, non-discriminatory basis to all customers and the transmission provider, provided the beneficiary agrees to accept a direct assignment. Several utilities argue that redispatch costs are a subset of opportunity costs and that the Commission should not use both terms in the tariff because it implies different standards apply Docket Nos. RM95-8-001 -268- and RM94-7-002 to transmission providers and their customers (e.g., sections 23.1 and 27). 264/ They request that the Commission only use the term "redispatch costs" in the pro forma tariff and impose the same redispatch obligations on network customers as are imposed on transmission providers. No rehearing requests addressed the subject of fuel adjustment clause treatment for redispatch costs. Commission Conclusion The Commission believes that the obligation to create additional transmission capacity to accommodate a request for firm transmission service should properly lie with the transmission provider, not a network customer. The Commission clearly established in the Final Rule that utilities are to be given "substantial flexibility . . . to propose appropriate pricing terms, including opportunity cost pricing [of which redispatch costs are a subset], in their compliance tariff." 265/ The Commission further required that any such rate proposals must meet the standards for conforming proposals in the Transmission Pricing Policy Statement. Accordingly, TAPS is free to pursue its concerns in any relevant compliance filings. Tariff sections 33.2 and 33.3 clearly establish that redispatch of all Network Resources and the transmission E.g., Utilities For Improved Transition, Florida Power Corp, VEPCO. FERC Stats. & Regs. at 31,739; mimeo at 307-08. Docket Nos. RM95-8-001 -269- and RM94-7-002 provider's own resources are only to be performed to maintain the reliability of the transmission system, not for economic reasons. Such costs are to be shared between network customers and the transmission provider on a load ratio basis. Similarly, the Commission clarified in Order No. 888, in modifying the transmission customer's redispatch obligation, that such change was "to limit the redispatch obligation to reliability reasons." 266/ Therefore, no further clarification is necessary. Other redispatching provisions under the tariff (e.g., sections 13.5 and 27) refer to situations where the transmission provider can relieve a system constraint more economically by redispatching the transmission provider's resources than through constructing Network Upgrades in order to provide the requested transmission service. However, in this circumstance, redispatch is conditioned upon the eligible customer agreeing to compensate the transmission provider for such redispatch costs. Section 13.5 of the pro forma tariff further requires that any such redispatch costs to be charged to the transmission customer on an incremental basis must be specified in the customer's service agreement prior to initiating service. These tariff requirements would appear to satisfy Wisconsin Municipals concerns because a section 205 filing must be made to directly assign costs to the customer receiving the economic benefit of the redispatch. FERC Stats. & Regs. at 31,767; mimeo at 388. Docket Nos. RM95-8-001 -270- and RM94-7-002 Regarding the argument that only the term "redispatch costs" should be used in the pro forma tariff, we note that the Commission followed this suggestion in drafting the pro forma tariff. The only exception is the use of opportunity costs in section 23.1 of the tariff, which caps the compensation for resellers at the higher of: (1) the original rate, (2) the transmission provider's maximum rate on file at the time of the assignment or (3) the reseller's opportunity cost. We further note that their concerns that different standards may be applied to transmission providers than to their customers are addressed in Section IV.C.6 (Capacity Reassignment). f. Expansion Costs In the Final Rule, the Commission allowed transmission providers to propose any method of collecting expansion costs that is consistent with the Commission's transmission pricing policy. 267/ The Commission explained that "or" pricing sends the proper price signal to customers and promotes efficiency and further indicated that "and" pricing will not be allowed. The Commission also indicated that any request to recover future expansion costs will require a separate section 205 filing. Rehearing Requests Several entities argue that requiring section 205 filings for all transmission expansion costs would impose difficult FERC Stats. & Regs. at 31,741; mimeo at 312-13. Docket Nos. RM95-8-001 -271- and RM94-7-002 burdens on transmission providers that use formula rates because they would have to try to distinguish between replacement costs, which are included in formula rates, and expansion costs, which are not. 268/ They assert that section 205 filings should be required only for system expansion costs that the transmission provider proposes to recover on a direct assignment or incremental cost basis, but not for costs to be recovered on an embedded cost basis. TDU Systems maintain that to the extent Order No. 888's provisions concerning direct assignment of transmission facilities indicate a change in the historic policy of rolling transmission investments into rate base, there is a risk TDUs will bear a disproportionate share of the transmission burden relative to transmission owners under the Commission's "or" pricing policy. According to TDU Systems, transmission owners should be required to permit customers to substitute their own lower cost capital for that of the owner's. SoCal Edison and Carolina P&L ask the Commission to clarify that a transmission provider has no obligation to build or upgrade its facilities for short-term firm point-to-point transmission customers ( 13.5, 15.4 and 1.13). SoCal Edison states that if a transmission provider is required to build, the Commission should clarify that any costs must be directly assigned to the requesting customer. E.g., Utilities For Improved Transition, Florida Power Corp, VEPCO. Docket Nos. RM95-8-001 -272- and RM94-7-002 Commission Conclusion The Final Rule does not change the Commission's filing requirements for recovery of transmission expansion costs or other transmission-related expenses. The Rule does not impose a section 205 filing requirement to the extent that existing formula rates do not require that such a filing be made to add transmission investment. However, consistent with the Commission's transmission pricing principles in effect prior to Order No. 888, a decision to price transmission on an incremental cost basis, or to directly assign facilities, are cost assignments that require a section 205 filing. The Final Rule also does not change the Commission's transmission pricing policies. Under our transmission pricing policy, a utility is still permitted to charge the higher of incremental expansion costs "or" a rolled-in embedded cost rate. There is no bias in the Final Rule that should cause TDU customers or any other customer to pay a disproportionate share of transmission costs. Moreover, we note that we also encourage joint planning/building options and regional solutions such as RTGs and ISOs. We do not believe that any change is necessary with regard to the obligation to build or expand. While both sections 13.5 and 15.4 obligate the transmission provider to expand or upgrade its transmission system to accommodate an application for firm point-to-point transmission service, these sections are conditioned upon the transmission customer agreeing to compensate Docket Nos. RM95-8-001 -273- and RM94-7-002 the transmission provider for such upgrade. In light of this compensation requirement, we do not anticipate that transmission providers will be requested to upgrade facilities in order to accommodate requests for short-term point-to-point transmission service. However, in the unlikely event that a short-term firm point-to-point transmission customer agrees to pay the costs of such upgrades, we believe that it is appropriate to require a transmission provider to expand its system to accommodate the request. g. Credit for Customers' Transmission Facilities In the Final Rule, the Commission concluded that credits related to customer-owned facilities are more appropriately addressed on a case-by-case basis, where individual claims for credits may be evaluated against a specific set of facts. 269/ The Commission stressed that while certain facilities may warrant some form of cost credit, the mere fact that transmission customers may own transmission facilities is not a guaranteed entitlement to such a credit. The Commission further explained that it must be demonstrated that a transmission customer's transmission facilities are integrated with the transmission system of the transmission provider in order to establish a right to credits. The Commission also noted that consistent with its ruling in FMPA II, 270/ if a customer wishes not to integrate FERC Stats. & Regs. at 31,742-43; mimeo at 316-18. Florida Municipal Power Agency v. Florida Power & Light (continued...) Docket Nos. RM95-8-001 -274- and RM94-7-002 certain loads and resources, and thereby exclude them from its load ratio share of the allocated cost of the integrated system, it may do so by separately contracting for point-to-point transmission service. Rehearing Requests APPA asserts that several differences between the treatment of transmission customers' and transmission providers' facilities are not comparable and must be corrected: (1) transmission providers' facilities include those owned, controlled or operated by the transmission provider, but to obtain credit, transmission customers must own the facilities; (2) transmission providers are under no obligation to engage in joint planning and historically have refused, thus putting the matter beyond the control of the customer; and (3) facilities of the customer must serve all of the transmission provider's power and transmission customers, but a transmission provider can include facilities in rates that serve only certain customers. APPA also maintains that the Commission failed to provide sufficient guidance to allow customers to ascertain the type of transmission facilities for which they can expect to receive credit. Several entities assert that the standard as to existing customer-owned facilities is inherently ambiguous -- the Final Rule preamble says integrated into the "plans or operations" of the transmitting utility, but section 30.9 of the tariff says the (...continued) Company, 74 FERC  61,006 (1996), reh'g pending. Docket Nos. RM95-8-001 -275- and RM94-7-002 "planning and operations" of the transmission provider (emphasis added). 271/ Further, they assert, it is unreasonable to require, as a key to integration, that "the transmission provider is able to provide transmission service to itself or other transmission customers over those facilities" because it may be that the facilities are necessary to provide network service to the customer that owns the facilities and a credit would be appropriate. They argue that if transmission facilities serve load included in the network customer's network load, the transmission customer should get a credit. Blue Ridge states that "[i]f the Commission does intend to change its standard or otherwise codify the result of FMPA II, then Blue Ridge urges rehearing and suggests a more analytical, policy oriented approach to the issue." (Blue Ridge at 31). It recommends adding the following language to the end of section 30.9 of the tariff concerning credit for new facilities: "or if such facilities are integrated with, and support the Transmission Provider's Transmission system." (Blue Ridge at Attachment 1). FMPA argues that a transmission provider can avoid paying credits for transmission that is functionally the same as that of the transmission provider simply by refusing to jointly plan. It asserts that the Commission should adopt either the Commission's integration test, without requiring joint planning, or a functionality test that considers whether the facilities of the E.g., NRECA, Blue Ridge, TDU Systems. Docket Nos. RM95-8-001 -276- and RM94-7-002 customer and transmission provider are similar. Moreover, it argues that a more inclusive definition of the grid would better achieve comparability and competitive generation markets and would remove incentives to avoid joint planning. It argues that crediting customer-owned transmission also promotes the establishment of regional grids. Several entities state that the standard as to future network customer-owned facilities should be modified to make joint planning mandatory on the part of the transmission provider, who otherwise has little incentive to cooperate and coordinate. 272/ They claim that in joint planning, plans cannot be developed by the transmission provider alone. They further argue that the Commission should not deem the lack of joint planning dispositive of the operation and planning issue. TAPS asks the Commission to clarify that credits will be provided for existing, as well as future, facilities if the integration requirement is met. Wisconsin Municipals asks the Commission to clarify that the level of customer-owned credits is a rate issue and that if parties have negotiated provisions for credits, the Final Rule cannot be used by transmission providers to avoid the obligations undertaken in a settlement. NRECA and TDU Systems assert that the Commission should not abandon its historical practice of rolling in transmission E.g., NRECA, TDU Systems, TAPS. Docket Nos. RM95-8-001 -277- and RM94-7-002 facilities for purposes of transmission pricing; otherwise, the Commission must examine the function of all transmission facilities in a transmission provider's rate base and exclude them if they are not "integrated" (referencing Order No. 888 at 317 n.452). They argue that because customers would have to file section 206 filings to enforce this, the Commission should require transmission providers to file under section 205 the identity of those facilities that will be included in the transmission rate base, those that will be excluded, and the supporting data. Turlock wants the Commission to provide concrete guidelines as to the eligibility of facilities for customer credits. Moreover, Turlock asserts that credits may be appropriate for point-to-point customers as well -- especially in Northern California where PG&E, according to Turlock, encouraged customers to build facilities. Turlock finds this particularly important where PG&E has proposed to switch from subfunctionalized ratemaking to system-wide rolled-in ratemaking. It asserts that, if there are system-wide rolled in rates without a credit provision, there may be a violation of the "or" pricing policy. Several entities ask the Commission to clarify that the crediting provision works on a comparable basis for transmission customers and providers. 273/ They ask the Commission to clarify that the phrase "serve all of its power and transmission E.g., IMPA, TAPS, AMP-Ohio, Michigan Systems. Docket Nos. RM95-8-001 -278- and RM94-7-002 customers" in section 30.9 is to be measured by the facilities that the transmission provider rolls into rate base to determine transmission rates and the transmission component of requirements rates. For example, they argue that because AEP rolls radial lines into rate base, comparable customer-owned lines should receive a credit. They also ask the Commission to clarify that the test that facilities are integrated into the planning and operations of the transmission provider is an objective standard that is satisfied by evidence that the transmission provider's load flow studies take into account the transmission customer's facilities. They assert that the standard should not be a subjective one that depends on whether the transmission provider says that it includes customer facilities in its planning and operations. AMP-Ohio adds that the integration requirement should also be satisfied by evidence that the transmission provider includes costs in its rate base or transmission expenses that are associated with transmission facilities of utilities that it acquires. Michigan Systems also asks that the Commission clarify that the test in section 30.9 is a functional test and not whether the transmission owner says it is integrating its operations. Michigan Systems states that it has no objection to leaving determinations of credits to rate cases, as an abstract matter, but asserts that the Commission should make clear that it will not implement newly-filed tariffs in a way that imposes multiple Docket Nos. RM95-8-001 -279- and RM94-7-002 or inconsistent charges for transmission in the interim. Otherwise, it asserts, transmission dependent utilities may be out of business if they must wait years to get credit for grid transmission they already own and that they must pay to finance. Michigan Systems also states that it would be illegal to require systems to pay for transmission by applying a load ratio share based on total loads when they have made investments under contracts for transmission to serve a portion of those loads. TAPS states that the Commission must define what it means by "integrated." TAPS asserts that the term should mean grid facilities used to integrate the network customer's resources and loads. It further asserts that the Commission should continue to use the test whether the facilities serve a comparable function. Unless a proper credit is provided, TAPS maintains, network customers could pay twice for transmission. TAPS adds that without proper crediting, the Commission cannot require load ratio pricing of network service. TAPS asks the Commission to clarify the method it will use to calculate the credit in individual cases and suggests that the Commission adopt the method TAPS proposed in its initial comments in this proceeding. With respect to joint ownership of transmission facilities or ownership of transmission facilities through a joint exercise of powers agency (JPA) or a Generation and Transmission Cooperative, TANC asks that the Commission provide for proportionate entitlement to a credit among those who have Docket Nos. RM95-8-001 -280- and RM94-7-002 invested in, and are entitled to the use of, such facilities. TANC also argues that the credit should apply to facilities used to complete a transaction under the transmission provider's point-to-point tariff. Further, TANC asserts that upon a showing that the facilities are integrated, the credit in section 30.9 should be mandatory and asks that the Commission provide guidance as to the method of either calculating or applying the credit. Commission Conclusion The Commission reaffirms its finding in Order No. 888 that the question of credits for customer-owned facilities is best resolved on a fact-specific, case-by-case basis. 274/ Accordingly, the Commission does not believe that the rehearing requests seeking specific guidance regarding various aspects of customer credits are appropriate for resolution at this time. 275/ In order to conform the Final Rule preamble language with the tariff provisions of Order No. 888, 276/ we will modify section 30.9 of the pro forma tariff to provide that a customer may receive a credit for its own facilities if it demonstrates that "its transmission facilities are integrated into the plans or operations (instead of "planning and operations") of the FERC Stats. & Regs. at 31,742; mimeo at 316. Wisconsin Municipals' argument with respect to prior settlements has been previously addressed in Section IV.D.1.c.(2) (Energy Imbalance Bandwidth). See FERC Stats. & Regs. at 31,742-43; mimeo at 316-17. Docket Nos. RM95-8-001 -281- and RM94-7-002 transmission provider to serve its power and transmission customers." 277/ The intent of section 30.9 of the pro forma tariff is that, for a customer to be eligible for a credit, its facilities must not only be integrated with the transmission provider's system, but must also provide additional benefits to the transmission grid in terms of capability and reliability, and be relied upon for the coordinated operation of the grid. Indeed, in the Final Rule we explicitly stated that the fact that a transmission customer's facilities may be interconnected with a transmission provider's system does not prove that the two systems comprise an integrated whole such that the transmission provider is able to provide transmission service to itself or other transmission customers over these facilities. 278/ The Commission further stated in the Final Rule that where disputes over credits for customer-owned facilities arise, it encourages all parties not to seek formal resolution at the Commission, but to first pursue alternative dispute resolution. In this regard, the customer at the time it is requesting network service could also request that a study be undertaken by the As we noted in FMPA II, this fundamental cost allocation concept applies to the transmission provider as well. Just as the customer cannot secure credit for facilities not used by the transmission provider to provide service, the transmission provider cannot charge the customer for facilities not used to provide transmission service. 74 FERC  61,006 at 61,010 n.48 (1996). FERC Stats. & Regs. at 31,742-43; mimeo at 317. Docket Nos. RM95-8-001 -282- and RM94-7-002 company to analyze the impact and benefit of the customer's facilities provided to the integrated transmission network. We share the concern of APPA and others that transmission providers have not allowed transmission customers to participate in the planning process for new transmission projects. Allowing potential transmission customers the opportunity to participate in transmission projects is important in ensuring that regional transmission needs are met efficiently. One way of accomplishing this goal is through an RTG, ISO, or other regional entity that has an open planning process. Where such entities do not exist, we strongly encourage public utilities to hold an open season for all transmission expansion projects, including those in response to a service request, so that all entities in the region have an opportunity to identify their future needs and participate in the project. Finally, requests for the Commission to mandate joint- planning are addressed below in the discussion of section 1.12 of the pro forma tariff. h. Ceiling Rate for Non-firm Point-to-Point Service In the Final Rule, the Commission stated that it is important to continue to allow pricing flexibility. 279/ The Commission explained that, in accordance with its current policies, the rate for non-firm point-to-point transmission service may reflect opportunity costs. The Commission further FERC Stats. & Regs. at 31,743-44; mimeo at 319-20. Docket Nos. RM95-8-001 -283- and RM94-7-002 explained that, if a utility chooses to adopt opportunity cost pricing, the non-firm rate is effectively capped by the availability of firm service and is not subject to a separately- stated price cap. On the other hand, the Commission explained that, if a utility chooses not to adopt opportunity cost pricing, the non-firm rate is capped at the firm rate. Rehearing Requests Duquesne asks the Commission to clarify that the phrase "the non-firm rate is capped at the firm rate" does not mean that the Commission is deviating from its principles that non-firm transmission service must be priced in a manner that (i) reflects the interruptibility of the service, and (ii) is economically efficient. Docket Nos. RM95-8-001 -284- and RM94-7-002 Commission Conclusion With regard to Duquesne's request, we clarify that the firm transmission rate simply represents a maximum rate or price cap for non-firm transmission prices. We emphasize that non-firm transmission prices should reflect the interruptibility of the service and should promote efficient use of the transmission system, subject to this price cap. Accordingly, while in some circumstances non-firm transmission rates may be set at the firm transmission rate level, the Commission expects that non-firm transmission rates would, in most instances, be priced below the price cap. i. Discounts In the Final Rule, the Commission stated that if a transmission provider offers a rate discount to its affiliate, or if the transmission provider attributes a discounted rate to its own wholesale transactions, the same discounted rate must also be offered at the same time to non-affiliates on the same transmission path and on all unconstrained transmission paths. 280/ In addition, the Commission required that discounts from the maximum firm rate for the provider's own wholesale use or its All offers or agreements to provide rate discounts to affiliates (including the Transmission Provider's wholesale merchant) on a particular path must be posted immediately on the OASIS and be available for a long enough period to allow non-affiliates to obtain the same discounted service on that path and on other paths for which the transmission provider must provide the same discount. We modify below our requirement regarding which other paths must receive the same discount. Docket Nos. RM95-8-001 -285- and RM94-7-002 affiliate's wholesale use must be transparent, readily understandable, and posted on the transmission provider's OASIS in advance so that all eligible customers have an equal opportunity to purchase non-firm transmission at the discounted rate. 281/ Finally, the Commission explained that discounts offered to non-affiliates must be on a basis that is not unduly discriminatory and must be reported on the OASIS within 24 hours of when available transmission capability (ATC) is adjusted in response to the transaction. Rehearing Requests Utility Position A number of utilities assert that the affiliate discounting provision is too broad. 282/ SoCal Edison asserts that if the affiliate discounting provision is kept, the requirement to discount similarly for non-affiliates on unconstrained paths should be limited to offers on the same day only for new transmission services and only for the duration of the service offered to the affiliate. The Commission also stated that the same requirements will apply to discounts for firm transmission service. The Commission added that if a transmission provider offers an affiliate a discount for ancillary services, or attributes a discounted ancillary service rate to its own transactions, it must offer at the same time the same discounted rate to all eligible customers. The Commission noted that discounted ancillary services rates must be posted on the OASIS pursuant to Part 37 of the Commission's regulations. E.g., SoCal Edison, Entergy, Southwestern, PacifiCorp, Montana Power, AEP, Utilities For Improved Transition, EEI. Docket Nos. RM95-8-001 -286- and RM94-7-002 Entergy and Southwestern assert that the Commission should change the discount language, which provides that whenever the transmission provider offers a discount to an affiliate, or attributes a discount to its own transaction, it must offer a comparable discount to all similarly situated transmission customers. Southwestern believes that the Commission does not justify its different treatment of discounts to affiliates and discounts to non-affiliates -- section 205(b) of the FPA states that a public utility may not give any undue preference or advantage to any person. Southwestern also notes that for gas pipelines, the Commission required that affiliate discounts be available to similarly situated shippers (citing 18 CFR 161.3(h)(1)). PacifiCorp suggests replacing the last sentence of section 37.6(c)(3) of the OASIS regulations with the following sentence: "With respect to any discount offered to its own power customers or its affiliates, the Transmission Provider must, at the same time, post on the OASIS an offer to provide the same discount to all Transmission Customers on the same transmission path and on all other unconstrained transmission paths parallel thereto for deliveries to the same Point of Delivery." It argues that the Commission's approach of requiring the same discount to all transmission customers on the same path and on all unconstrained Docket Nos. RM95-8-001 -287- and RM94-7-002 transmission paths would discourage discounting, even when done to attract counter-wheeling to relieve constraints. 283/ Several utilities argue that the discount language should be changed to require only that the same discount be offered to all customers on the same path. 284/ Otherwise, Montana Power asserts, transmission providers will be reluctant to offer discounts to its own marketers so as to protect revenues on other paths. AEP suggests that the discount language be changed to require that the discount be made available for all unconstrained paths terminating at the same interface. Illinois Power argues that the Commission should require discounts for equivalent (i.e., similarly situated) service requests, on the basis of location, term and time of service, which it asserts conforms to the Commission's standards for natural gas pipelines (citing 18 CFR 161.3(h)). Otherwise, it asserts, the Commission's approach will result in inefficient use of scarce transmission capacity and thereby discourage efficient bulk power trading. VEPCO asserts that transmission providers must be given more flexibility to accommodate differences in regional wholesale markets and to maximize the movement of economical capacity and energy. It states that a transmission provider will provide See also Washington Water Power. E.g., Montana Power, Allegheny, Puget. Docket Nos. RM95-8-001 -288- and RM94-7-002 discounts only if they are not detrimental to existing committed agreements or potential future revenue -- revenue from additional sales must offset the decrease in revenues from making discounts. It suggests that preferential treatment can be reduced by the following constraints: (1) offer the same discount to all transmission requests to the same points of delivery for the same time, and (2) a discount should not apply to service already agreed to but not yet provided at that point. Utilities For Improved Transition adds the following constraint: evaluate request for discount on whether it would increase volume without reducing total revenues. 285/ Florida Power Corp asserts that because communications regarding discounts must be posted on OASIS, preferential treatment would be readily apparent. EEI states that the discount requirement has the potential to arbitrarily reduce the revenue that the transmission provider may be able to obtain over alternative paths that may be unconstrained, but of greater potential value than the path(s) identified as appropriate for discounting. It adds that the requirements for posting discounts should be the same regardless of affiliation and should be limited to the specific transmission path(s) discounted by the transmission provider. Carolina P&L argues that the Commission should permit selective discounting of non-firm transmission service on a posted-in-advance (on OASIS) basis that will not create a most See also Florida Power Corp. Docket Nos. RM95-8-001 -289- and RM94-7-002 favored nations situation merely because the transmission provider or an affiliate availed itself of the posted discount. Customer Position Tallahassee asks the Commission to clarify that the transmission provider must automatically apply the discount to any eligible customer or, at the minimum, provide actual and timely notice of the discount's availability. Similarly, PA Coops asserts that "[i]f transmission service is being discounted to any customer, affiliated or not, for a specific level of service at a specific point in time, it should be equally discounted to all customers receiving the same transmission service. To do otherwise is unduly discriminatory." (PA Coops at 11). TAPS asserts that all discounts must be posted in advance, the reasons for the discounts should be transparent, the transmission provider should keep all requests for discounts in a log, and short-lived discounts should not be permitted. Commission Conclusion In response to the arguments raised with respect to discounting, we will revise our policy on discounting transmission service. This revised policy will assure consistency with our standards of conduct requirements, which preclude a utility's wholesale merchant function from having access to its transmission system information (including price) not posted on the OASIS that is not otherwise also available to the general public or that is not also publicly available to all Docket Nos. RM95-8-001 -290- and RM94-7-002 transmission users. The revised policy also should result in less opportunity for affiliate abuse and enable better monitoring of potential abuse. Additionally, we have concluded that the same policy should apply regardless of whether the discount is for the transmission provider's own wholesale use (i.e., wholesale merchant function), for the transmission provider's affiliate, or for a non-affiliate. A transmission provider should discount only if necessary to increase throughput on its system. While the potential for abuse is most obvious in situations involving the transmission provider's own wholesale use or use by an affiliate (own use/affiliate), 286/ we must also be concerned with a transmission provider agreeing to discount to non-affiliates in any unduly discriminatory manner. To satisfy these dual concerns, we believe that any "negotiation" 287/ between a transmission provider and potential transmission customers should take place on the OASIS. Toward this end, we believe three principal requirements are appropriate. (These requirements would remain even after negotiation takes place on the OASIS.). First, any offer of a discount for transmission services made by the transmission provider must be announced to all We clarify that own use/affiliate transactions include all transactions where the transmission provider or any of its affiliates is either the buyer, seller, marketer, or broker of wholesale power. "Negotiation" would only take place if the transmission provider or potential customer seeks prices below the ceiling prices set forth in the tariff. Docket Nos. RM95-8-001 -291- and RM94-7-002 potential customers solely by posting on the OASIS. This requirement, which will ensure that all potential transmission customers under the pro forma tariff will have equal access to discount information, will guard against own use/affiliate customers gaining an unfair timing advantage concerning the availability of discounts. Second, we will require that any customer-initiated requests for discounts occur solely by posting on the OASIS, regardless of whether the customer is an own use/affiliate or a non-affiliate. We have considered, and rejected at least for now, a more restrictive approach which would require that all discounts be initiated solely through offers by the transmission provider. Under such an arrangement, negotiations for discounts would effectively take place by customers accepting or not accepting the offered discount. While such an arrangement could better protect against affiliate abuse, it might be less efficient. 288/ Accordingly, we will permit customer-initiated requests for discounts but will require that such requests be visible (via posting on the OASIS) to all market participants. Finally, we will require that, once the transmission provider and customer agree to a discounted transaction, the details (e.g., price, points of receipt and delivery, and length For example, requiring the transmission provider to wait to see if an offered 5% discount clears the market would appear to be less efficient than permitting the customer to advise the transmission provider (via the OASIS) of its need for a higher discount in order to take service. Docket Nos. RM95-8-001 -292- and RM94-7-002 of service) be immediately posted on the OASIS. This requirement will be equally applicable regardless of whether the customer is an own use/affiliate or non-affiliate. We will also revise our policy with respect to the transmission paths on which a discount must be offered. Many petitioners argue that the policy in Order No. 888, particularly that the discount rate must be offered over all unconstrained paths, is too broad, and may provide disincentives for the efficient operation of the transmission grid. Their concerns include, for example, the possibility that the policy would inhibit the transmission provider from offering discounts that would relieve line constraints. For example, PacifiCorp argues that it would be reluctant to offer a discount on northbound power flows that would relieve transmission constraints on transmission paths that are normally used for southbound flows, if by virtue of discounting northbound flows, it would also be required to discount all unconstrained southbound flows. Another concern is that while requiring discounts on all unconstrained paths could conceivably result in more service being provided, it may not have that effect. Since the level of transmission revenues will decline if the discount applies to all unconstrained paths and this, in turn, could reduce the credit to firm transmission users for non-firm service revenues, transmission providers may simply decide not to discount a particular unconstrained path. In light of these persuasive Docket Nos. RM95-8-001 -293- and RM94-7-002 arguments, we will no longer require the transmission provider to provide the same discount over all unconstrained paths. Under our revised policy, if the transmission provider offers a discount on a particular path, i.e., from a point of receipt to a point of delivery, the transmission provider must offer the same discount for the same time period on all unconstrained paths that go to the same point(s) of delivery on the transmission provider's system. In this regard, a point of delivery includes an interconnection with another control area. Also, if a power purchaser can take delivery at more than one point of delivery (such as two substations serving a municipality), we would consider these to be the same point of delivery for discounting purposes. This change provides some flexibility to transmission providers to set prices for transmission service efficiently and at the same time maintains the requirement that public utilities provide comparable service at rates that are not unduly discriminatory or preferential. The change is designed to ensure that the transmission owner will provide the same discounted service to its competitors that it provides to itself or its affiliates for their wholesale sales. The Commission considered requiring the transmission provider offering a discount on a particular path to offer discounts on all unconstrained paths that go from the same points of receipt on the transmission provider's system and decided that such a requirement was not necessary to ensure comparability. Docket Nos. RM95-8-001 -294- and RM94-7-002 We further clarify that a transmission provider may limit its offers of discounts over the OASIS to particular time periods. There is nothing per se unduly discriminatory in offering a discount in one period and not in another. 289/ Finally, we recognize that even with this revised policy utilities may engage in affiliate abuse by offering discounts only at times or along paths that are of advantage to it or its affiliates. While requiring the posting of discount information on the OASIS does not completely eliminate the possibility of affiliate abuse, these procedures will allow ready identification of unduly discriminatory or preferential transactions, and thus make easier the preparation of complaints that the transmission provider is engaging in a pattern of discounting that indicates affiliate abuse, such as offering discounts preferentially at times or on paths that only the transmission provider or its affiliate can take advantage of, without offering discounts at times or on paths that its competitors can take advantage of. We will require that all "negotiation" take place on the OASIS as soon as practicable, as explained in Order No. 889-A. Thus, there is no need to revise contracts to reflect later offered discounts. Docket Nos. RM95-8-001 -295- and RM94-7-002 j. Other Pricing Related Issues Not Specifically Addressed in the Final Rule (1) Demand Charge Credits Rehearing Requests VT DPS argues that demand charge credits for curtailments or interruptions are needed to provide an incentive to utilities to provide high quality service. It points out that the Commission has allowed demand charge credits in the gas pipeline context (citing Tennessee Gas Pipeline Co., 71 FERC  61,399 at 62,580). 290/ Commission Conclusion The Commission does not believe that electrical systems will be less reliable as a result of our initiatives on competition and open access in the Final Rule. As such, the Commission does not intend to require demand charge credits on a generic basis to encourage reliable transmission service. However, because the Commission has not mandated any particular rate design methodology under the Final Rule pro forma tariff, customers are free to argue in the compliance filing proceedings or subsequent section 205 proceedings that demand charge credits are reasonable in the context of a particular rate design method. (2) In-Kind Transactions Rehearing Requests CCEM asserts that in-kind transactions in reformed power pool agreements should be abolished because of the uncertainty of See also Valero. Docket Nos. RM95-8-001 -296- and RM94-7-002 valuing non-cash transactions and the potential for cross subsidizing the utilities' generation sales. It contends that a cash equivalent transaction for all formerly in-kind transactions among transmission owners is needed. Commission Conclusion To satisfy CCEM's concerns, the Commission concludes that in-kind transactions must be provided on a non-discriminatory basis. The Commission recently found that in-kind transactions (i.e., transactions with payment by energy returned in kind instead of by a monetary charge) with no unbundling requirement "could hide and, thereby, mask unduly preferential terms and rates," which is precisely one of the practices that the Final Rule is intended to remedy. 291/ While we will now require that all in-kind transactions be provided on an unbundled basis, we stress that we are not prohibiting in-kind transactions. Utilities are free to enter into contracts that contain in-kind compensation for the wholesale generation component, as long as it unbundles such transactions. Consistent with Arizona, unless the other party to the transaction contracts for transmission service under that utility's open access pro forma tariff, that utility must obtain the necessary transmission and ancillary services under the terms of its open access transmission tariff Arizona Public Service Company, Order Addressing Functional Unbundling Issues, 78 FERC  61,016 (slip op. at 11) (1997) (Arizona). Docket Nos. RM95-8-001 -297- and RM94-7-002 and must separately state the transmission and ancillary service prices that it will recover from the customer. 2. Priority For Obtaining Service a. Reservation Priority for Existing Firm Service Customers In the Final Rule, the Commission indicated that a transmission provider may reserve in its calculation of ATC transmission capacity necessary to accommodate native load growth reasonably forecasted in its planning horizon. 292/ Rehearing Requests This issue is discussed in Section IV.C.5. (Reservation of Transmission Capacity for Future Use by Utility). b. Reservation Priority for Firm Point-to-Point and Network Service In the Final Rule, in response to concerns that network service should have a reservation priority over point-to-point service because of pricing differences, the Commission allowed utilities the opportunity to eliminate the differences in pricing between network and point-to-point services by permitting utilities to adopt point-to-point reservations as the customer load. 293/ The Commission explained that utilities are free to propose a single cost allocation method for the two services. In addition, the Commission provided that reservations for short-term firm point-to-point service (less than one year) will FERC Stats. & Regs. at 31,745; mimeo at 323-24. FERC Stats. & Regs. at 31,746-47; mimeo at 326-29. Docket Nos. RM95-8-001 -298- and RM94-7-002 be conditional until one day before the commencement of daily service, one week before the commencement of weekly service, and one month before the commencement of monthly service. According to the Commission, these conditional reservations may be displaced by competing requests for longer-term firm point-to- point service. The Commission explained that after the deadline, the reservation becomes unconditional, and the service would be entitled to the same priorities as any long-term point-to-point or network firm service. Moreover, the Commission explained that the Final Rule pro forma tariff does not propose point-to-point or network service with various degrees of firmness beyond the simple categories of firm and non-firm. It explained that when a customer requests firm transmission service, reservation priorities are established based first on availability, and in the event the system is constrained, based on duration of the underlying firm service request -- customers may choose the "firmness" of service they want by electing to take non-firm service, or by reserving and paying for firm service. Rehearing Requests NRECA and TDU Systems declare that provisions making reservations for short-term firm point-to-point service conditional will not reduce the incentive to cream skim, i.e., a customer has an incentive to submit reservations for very short terms without fear of not getting service because it can always increase its request to match another longer request. They Docket Nos. RM95-8-001 -299- and RM94-7-002 suggest an alternative: all native load, network, and long-term firm (one year or more) requests would be given priority over short-term firm requests, which would have priority over non-firm requests. Commission Conclusion The Final Rule has sufficiently minimized the potential for cream skimming. Further, we note that the alternative proposed by NRECA & TDU Systems has substantially been adopted in Order No. 888. Specifically, Order No. 888 provides: (1) public utilities the right to reserve existing transmission capacity needed for native load growth and network transmission customer load growth, 294/ and (2) existing transmission customers the right of first refusal. 295/ The only entities not covered above -- potential long-term firm customers -- must submit their service applications as far in advance as practicable. c. Reservation Priorities for Non-firm Service In the Final Rule, the Commission found that network economy purchases should have a reservation priority over non-firm point- to-point and secondary point-to-point uses of the transmission system. 296/ FERC Stats. & Regs. at 31,694; mimeo at 172. FERC Stats. & Regs. at 31,665 and 31,694; mimeo at 88 & 172. FERC Stats. & Regs. at 31,748; mimeo at 332-33. Docket Nos. RM95-8-001 -300- and RM94-7-002 Rehearing Requests North Jersey argues that non-firm service should be allocated on a first-come, first-served basis, and where multiple customers request service at the same time, available capacity should be allocated on a pro rata basis. It asserts that the proposed priority system based on duration of non-firm service would simply encourage non-firm customers to request service for longer durations than needed. Commission Conclusion We reject North Jersey's argument that the proposed priority system based on duration of non-firm service would encourage non- firm customers to request service for longer durations than needed. North Jersey ignores the fact that section 14.2 of the pro forma tariff establishes a right for eligible customers with existing non-firm reservations to match any longer term reservation before being preempted. A related matter is discussed in Section IV.G.3.b below. 3. Curtailment and Interruption Provisions 297/ In the Final Rule pro forma tariff, the Commission defines curtailment as: "A reduction in firm or non-firm transmission service in response to a transmission capacity shortage as a result of system reliability conditions." (pro forma tariff section 1.7). The pro forma tariff defines interruption as: "A reduction in non-firm service due to economic reasons pursuant to Section 14.7." (pro forma tariff section 1.15). The distinction between curtailment and interruption may have been blurred in Order No. 888 and this order attempts to clarify that distinction. Docket Nos. RM95-8-001 -301- and RM94-7-002 a. Pro-rata Curtailment Provisions In the Final Rule, the Commission found that curtailment on a pro-rata basis is appropriate for curtailing transactions that substantially relieve a constraint. 298/ The Commission explicitly allowed the transmission provider discretion to curtail the services, whether firm or non-firm, that substantially relieve the constraint. The Commission also indicated that it would consider granting deference to an alternative curtailment method to avoid hydro spill if such a regional practice is generally accepted and adhered to across the region. The Commission further found that under network and point- to-point service, the transmission provider may propose a rate treatment (penalty provision) to apply in the event a customer fails to curtail service as required under the Final Rule pro forma tariff and indicated that such proposals will be evaluated on a case-by-case basis on compliance. Rehearing Requests PA Com asserts that pro rata curtailment fails to hold native load harmless to the extent practical as required by the FPA. PA Com points out that on January 19, 1994, PJM initiated pro-rata load shedding, in part to preserve economic transactions, leaving customers in Pennsylvania without power during a record cold spell. FERC Stats. & Regs. at 31,749; mimeo at 335-36. Docket Nos. RM95-8-001 -302- and RM94-7-002 VA Com argues that pro rata curtailment may harm native load customers and section 206 complaints are after the fact and of little assistance to native load. VA Com argues that curtailment priority (in order of curtailment) should be: non-firm, contract firm, and then native load, and that utilities should have flexibility to curtail on a pro-rata basis within classes, subject to state curtailment policy. Several entities argue that provision must be made for preference in curtailment priorities obtained through settlement, through payment of good and valuable consideration, or under existing transmission contracts. 299/ Turlock argues that customers should be able to obtain a variation from the pro rata scheme if they can show that they have made either past or future investments to improve constrained facilities and that the quid pro quo for their investment is improved curtailment priority. Allegheny asks the Commission to clarify that it did not intend to require public utilities to shed (through pro rata curtailment) native transmission load customers in order to preserve some portion of service to through system users of the grid. According to Allegheny, the FPA mandates that service reliability to franchise customers must be maintained and through-system users are not similarly situated to native transmission load customers and should not be treated the same in an emergency because through system customers can protect E.g., Santa Clara, Redding, TANC. Docket Nos. RM95-8-001 -303- and RM94-7-002 themselves, but native transmission load customers cannot. Allegheny adds that failure to maintain system reliability would violate section 211 of the FPA. CCEM asserts that hard and fast priority rules are needed to prevent inconsistent rules from developing for different utilities, pools, or control areas. Commission Conclusion Assertions that the pro-rata curtailment provision in the tariff may harm native load customers are misplaced. The Commission clarified in the Final Rule that it was not requiring a pro-rata curtailment of all transactions at the time of a constraint, but rather curtailment of those transactions, whether firm or non-firm, that effectively relieve the constraint. 300/ The Commission also required that such curtailments be made on a non-discriminatory basis, including the transmission provider's own wholesale use of the system. The Commission further explained that the pro-rata curtailment provision was intended to apply to situations where multiple transactions could be curtailed to relieve a constraint. Of course, if curtailment of multiple transactions is necessary, non-firm service would be curtailed prior to firm service. However, the Commission established that, in emergencies, the transmission provider had the discretion to interrupt firm service under the tariff to ensure the reliability of its transmission system. FERC Stats. & Regs. at 31,749; mimeo at 335. Docket Nos. RM95-8-001 -304- and RM94-7-002 In terms of reliability, we believe that sufficient safeguards have been established to protect native load. In particular, the transmission provider is responsible for planning and maintaining sufficient transmission capacity to safely and reliably serve its native load. Order Nos. 888 and 889 permit the transmission provider to reserve, in its calculation of ATC, sufficient capacity to serve native load. Allegations that a utility did not curtail on a non- discriminatory basis, but instead favored a certain class of customer or type of transaction should be filed in a section 206 complaint proceeding to be reviewed on a case-specific basis. While it is true that such complaints will be processed on an after-the-fact basis, it is only on a fact-specific basis that such complaints can be fully and adequately reviewed. Additionally, tariff section 14.7 does in fact establish that for curtailment purposes, non-firm point-to-point transmission shall be subordinate to firm transmission service and non-firm service may also be interrupted for economic reasons. However, adopting curtailment schemes based solely on classes of service, as proposed by the VA Com, is inappropriate. Specifically, VA Com's proposal to curtail all non-firm transmission transactions prior to firm transactions could exacerbate an emergency situation. For example, a curtailment could be necessary due to a constraint affecting northbound transactions. However, curtailing all non-firm transactions, including southbound transactions (or counterflows), could worsen Docket Nos. RM95-8-001 -305- and RM94-7-002 the situation. Accordingly, the Commission believes the approach established in the Final Rule of allowing non-discriminatory curtailments of the transaction(s) that effectively relieve(s) the constraint is appropriate. In response to CCEM's concerns regarding the potential for inconsistent rules for different utilities, pools or control areas, the Commission explained in the Final Rule that any proposed deviations from the non-price terms and conditions of the pro forma tariff, such as regional practices, must be adequately supported by the utility proposing the change. Finally, Order No. 888 did not abrogate existing contracts; 301/ therefore, customers with unique curtailment priorities established by pre-existing contracts would not have these priorities eliminated for the term of the existing contract. b. Curtailment and Interruption Provisions for Non-firm Service In the Final Rule, the Commission explained that it had clarified in the pro forma tariff that a network customer's economy purchases have a higher priority than non-firm point-to- point transmission service (citing AES Power, Inc. 302/). 303/ We note that in Order No. 888 we partially modified existing economy energy coordination agreements. FERC Stats. & Regs. at 31,666; mimeo at 91. 69 FERC  61,145 at 62,300 (1994) (proposed order), 74 FERC  61,220 (1996) (final order). FERC Stats. & Regs. at 31,750; mimeo at 338-39. Docket Nos. RM95-8-001 -306- and RM94-7-002 The Commission also revised the pro forma tariff to allow the transmission provider to curtail non-firm service for reliability reasons or to interrupt the service for economic reasons (i.e., in order to accommodate (1) a request for firm transmission service, (2) a request for non-firm service of greater duration, (3) a request for non-firm transmission service of equal duration with a higher price, or (4) transmission service for economy purchases by network customers from non- designated resources). The Commission further explained that a firm point-to-point customer's use of transmission service at secondary points of receipt and delivery will continue to have the lowest priority. Rehearing Requests For comparability, CCEM asserts that secondary receipt points should be made subordinate to other firm services, 304/ but should have priority over non-firm point-to-point transactions. CCEM also argues that non-firm point-to-point service, once scheduled, should not be interrupted to accommodate non-firm service for a network service economy purchase. VT DPS argues that firm flexible point-to-point service over secondary points of receipt and delivery should have a priority over non-firm point-to-point service (citing sections 14.2 and A firm point-to-point customer has a right to change its receipt points if capacity is available. These changed receipt points are known as secondary receipt points. The issue addressed here is the priority that is assigned to those secondary receipt points. Docket Nos. RM95-8-001 -307- and RM94-7-002 14.7 of the pro forma tariff). It argues that this priority is necessary to reflect the fact that point-to-point customers pay for firm service and to be consistent with the treatment of network customers. VT DPS notes that in the natural gas industry the Commission has found that such priority is essential to reflect the fact that firm customers are paying for firm service (citing Order No. 636-B). APPA asks the Commission to clarify the conditions under which the Commission will allow non-firm service to be interrupted by the transmission provider solely for economic reasons. APPA claims that this clarification is needed so as to prevent interruption of service on a discriminatory basis. CCEM states that non-firm point-to-point transmission service does not provide the user with a specific capacity reservation, and therefore such service should bear no reservation or demand-like charges and the customer should pay a commodity-only charge only for when the service is being provided. 305/ It contends, for example, that if a customer schedules one week of weekly non-firm transmission service and is interrupted on the second day of service, the customer should only pay for the service it used and should have no responsibility to take or to pay for service for the remainder of the week. Alternatively, it argues that if there are reservation charges and the non-firm customer pays for service on a "take-or- See also Tallahassee. Docket Nos. RM95-8-001 -308- and RM94-7-002 pay basis" regardless of use, non-firm service should not be subject to being bumped once service is scheduled and power is flowing. Moreover, if the non-firm point-to-point transmission customer does pay reservation charges on a "take-or-pay basis," the non-firm reserved capacity should be tradeable in a secondary market. Commission Conclusion We reject CCEM's proposal to prevent scheduled non-firm transmission service from being interrupted to accommodate economy purchases for network customers. Non-firm service is provided on an interruptible basis. To the extent CCEM wishes to obtain service that cannot be interrupted to accommodate other transactions, it has the option of requesting firm service in the form of either network or point-to-point transmission service. APPA's concerns have already been addressed by the Commission. In the Final Rule, the Commission specifically listed the economic reasons that a transmission provider could interrupt non-firm point-to-point transmission to include: accommodat[ing] (1) a request for firm transmission service, (2) a request for non-firm service of greater duration, (3) a request for non-firm transmission service of equal duration with a higher price, or (4) transmission service for economy purchases by network customers from non-designated resources. [306/] CCEM's arguments are misplaced in that they focus on the specific rate (including any potential credits for service FERC Stats. & Regs. at 31,750; mimeo at 338. Docket Nos. RM95-8-001 -309- and RM94-7-002 interruption) that utilities may propose for non-firm point-to- point transmission service. Order No. 888 did not mandate any pricing methodology to be used for non-firm point-to-point transmission service. Rather, the Commission established the minimum non-price terms and conditions necessary to ensure comparable service. As the Commission explained in the Final Rule, utilities are free to propose any rates for non-firm point- to-point transmission in a section 205 filing consistent with the Commission's Transmission Pricing Policy Statement. 307/ However, the Commission will evaluate the appropriateness of such proposed rates against the non-price terms and conditions established in the pro forma tariff or other non-price terms and conditions proposed and fully supported by the utility. 308/ The Commission has previously addressed VT DPS' point. 309/ Non-firm point-to-point customers pay for non-firm service as their service. Firm point-to-point customers, on the other hand, contract and reserve a specified amount of service over designated points of receipt and delivery. The Commission permitted these firm point-to-point customers to use secondary non-firm service (from points of receipt/delivery other than FERC Stats. & Regs. at 31,769-70; mimeo at 395-99. We note that CCEM has pursued these arguments (raised on rehearing) in utility-specific rate cases and its objections will be addressed there. See FERC Stats. & Regs. at 31,750; mimeo at 338, and AES Power, Inc., 69 FERC  61,145 at 62,300 (1994) (proposed order), 74 FERC  61,220 (1996) (final order).