75 FERC 61,080 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. RM95-8-000 Through Open Access ) Non-discriminatory Transmission ) Services by Public Utilities ) ) Recovery of Stranded Costs by ) Docket No. RM94-7-001 Public Utilities and Transmitting ) Utilities ) ORDER NO. 888 FINAL RULE (Issued April 24, 1996) I. INTRODUCTION/SUMMARY Today the Commission issues three final, interrelated rules designed 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. 1/ The legal and policy cornerstone of these rules is to remedy undue discrimination in access to the monopoly owned transmission wires that control whether and to whom electricity can be transported in interstate commerce. A second critical aspect of the rules is 1/ These rules are the rules on open access and stranded costs in the above dockets (FERC Stats. & Regs.  31,036), and an accompanying rule on Open Access Same-Time Information System and Standards of Conduct (OASIS Final Rule) (FERC Stats. & Regs.  31,037) being issued contemporaneously. The Commission also is issuing contemporaneously a notice of proposed rulemaking on capacity reservation open access transmission tariffs in Docket No. RM96-11-000, FERC Stats. & Regs.  32,517. These final rules and proposed rule are being published concurrently in the Federal Register. Docket Nos. RM95-8-000 - 2 - and RM94-7-001 to address recovery of the transition costs of moving from a monopoly-regulated regime to one in which all sellers can compete on a fair basis and in which electricity is more competitively priced. In the year since the proposed rules were issued, 2/ the pace of competitive changes in the electric utility industry has accelerated. By March of last year, 38 public utilities had filed wholesale open access transmission tariffs with the Commission. Today, prodded by such competitive changes and encouraged by our proposed rules, 106 of the approximately 166 public utilities that own, control, or operate 3/ transmission facilities used in interstate commerce have filed some form of wholesale open access tariff. In addition, since the time the 2/ On March 29, 1995, the Commission issued two notices of proposed rulemaking concerning open access transmission and stranded cost recovery. Promoting Wholesale Competition Through Open-Access Non-Discriminatory Transmission Service by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Notice of Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking, 60 FR 17662 (April 7, 1995), FERC Stats. & Regs.  32,514 (1995). On December 13, 1995, the Commission issued a notice of proposed rulemaking on information systems. Real- Time Information Networks and Standards of Conduct, Notice of Proposed Rulemaking, 60 FR 66182 (December 21, 1995), FERC Stats. & Regs.  32,516 (1995). 3/ The Commission's notice of proposed rulemaking in the above dockets proposed to apply the proposed requirements to public utilities that own and/or control facilities used for the transmission of electric energy in interstate commerce. "Own and/or control" is intended to include public utilities that "operate" facilities used for the transmission of electric energy in interstate commerce. However, we have modified the Final Rule regulatory text to remove any ambiguity. Docket Nos. RM95-8-000 - 3 - and RM94-7-001 proposed rules were issued, numerous state regulatory commissions have adopted or are actively evaluating retail customer choice programs or other utility restructuring alternatives. These events have been spurred by continuing pressures in the marketplace for changes in the way electricity is bought, sold, and transported. Increasingly, customers are demanding the benefits of competition in the growing electricity commodity market. The Commission estimates the potential quantitative benefits from the Final Rule will be approximately $3.8 to $5.4 billion per year of 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. The continuing competitive changes in the industry and the prospect of these benefits to customers make it imperative that this Commission take the necessary steps within its jurisdiction to ensure that all wholesale buyers and sellers of electric energy can obtain non-discriminatory transmission access, that the transition to competition is orderly and fair, and that the integrity and reliability of our electricity infrastructure is maintained. In this Rule, the Commission seeks to remedy both existing and future undue discrimination in the industry and realize the significant customer benefits that will come with open access. Indeed, it is our statutory obligation under sections 205 and 206 of the Federal Power Act (FPA) to remedy undue discrimination. Docket Nos. RM95-8-000 - 4 - and RM94-7-001 To do so, we must eliminate the remaining patchwork of closed and open jurisdictional transmission systems and ensure that all these systems, including those that already provide some form of open access, cannot use monopoly power over transmission to unduly discriminate against others. If we do not take this step now, the result will be benefits to some customers at the expense of others. We have learned from our experience in the natural gas area the importance of addressing competitive transition issues early and with as much certainty to market participants as possible. Accordingly, in this proceeding and in the accompanying proceeding on OASIS, the Commission, pursuant to its authorities under sections 205 and 206 of the FPA: ù requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce ù to file open access non-discriminatory transmission tariffs that contain minimum terms and conditions of non-discriminatory service; ù to take transmission service (including ancillary services) for their own new wholesale sales and purchases of electric energy under the open access tariffs; ù to develop and maintain a same-time information system that will give existing and potential transmission users the same access to transmission information that the public utility enjoys, and further requires public utilities to separate transmission from generation marketing functions and communications; ù clarifies Federal/state jurisdiction over transmission in interstate commerce and local distribution and provides for deference to certain state recommendations; and Docket Nos. RM95-8-000 - 5 - and RM94-7-001 ù permits public utilities and transmitting utilities to seek recovery of legitimate, prudent and verifiable stranded costs associated with providing open access and FPA section 211 transmission services. Open Access The Final Rule requires public utilities to file a single open access tariff that offers both network, load-based service and point-to-point, contract-based service. The Rule contains a pro forma tariff that reflects modifications to the NOPR's proposed terms and conditions and also permits variations for regional practices. All public utilities subject to the Rule, including those that already have tariffs on file, will be required to make section 206 compliance filings to meet the new pro forma tariff non-price minimum terms and conditions of non- discriminatory transmission. Utilities may propose their own rates in a section 205 compliance filing. The Rule provides that public utilities may seek a waiver of some or all of the requirements of the Final Rule. In addition, non-public utilities may seek a waiver of the tariff reciprocity provisions. The Final Rule does not generically abrogate existing requirements contracts, but will permit customers and public utilities to seek modification, or termination, of certain existing requirements contracts on a case-by-case basis. As to coordination arrangements and contracts, the Rule finds that these arrangements and contracts may need to be modified to remove unduly discriminatory transmission access and/or pricing Docket Nos. RM95-8-000 - 6 - and RM94-7-001 provisions. Such arrangements and agreements include power pool agreements, public utility holding company agreements, and certain bilateral coordination agreements. The Rule provides guidance and timelines for modifying unduly discriminatory coordination arrangements and contracts, and specifies when the members of such arrangements must begin to conduct trade with each other using the same open access tariff offered to others. The Rule also provides guidance regarding the formation of independent system operators (ISOs). The Rule does not require any form of corporate restructuring, but will accommodate voluntary restructuring that is consistent with the Rule s open access and comparability policies. As discussed in the NOPR, not all owners or controllers of interstate transmission facilities are subject to the Commission s jurisdiction under sections 205 and 206 of the FPA and therefore are not subject to this Rule s open access requirements. Therefore, the Final Rule retains the proposed reciprocity provision in the pro forma tariff. Without such a provision, non-open access utilities could take advantage of the competitive opportunities of open access, while at the same time offering inferior access, or no access at all, over their own facilities. Thus, open access utilities would be unfairly burdened. We note that some non-jurisdictional utilities have expressed an interest in a mechanism for obtaining a Commission determination that their transmission tariffs satisfy the Docket Nos. RM95-8-000 - 7 - and RM94-7-001 reciprocity provisions in the pro forma tariffs, and we provide such a mechanism in the Rule. The Final Rule does not generically provide for market-based generation rates. Although the Rule codifies the Commission s prior decision that there is no generation dominance in new generating capacity, intervenors in cases may raise generation dominance issues related to new capacity. In addition, to obtain market-based rates for existing generation, we will continue to require public utilities to show, on a case-by-case basis, that there is no generation dominance in existing capacity. Further, in all market-based rate cases, we will continue to look at whether an applicant and its affiliates could erect other barriers to entry and whether there may be problems due to affiliate abuse or reciprocal dealing. Finally, contemporaneously with this Rule the Commission issues a NOPR on capacity reservation tariffs as an alternative, and perhaps superior, means of remedying undue discrimination. Transmission/Local Distribution The Rule clarifies the Commission's interpretation of the Federal/state jurisdictional boundaries over transmission and local distribution. While we reaffirm our conclusion that this Commission has exclusive jurisdiction over the rates, terms, and conditions of unbundled retail transmission in interstate commerce by public utilities, we nevertheless recognize the very legitimate concerns of state regulatory authorities as they contemplate direct retail access or other state restructuring Docket Nos. RM95-8-000 - 8 - and RM94-7-001 programs. Accordingly, we specify circumstances under which we will give deference to state recommendations. Although jurisdictional boundaries may shift as a result of restructuring programs in wholesale and retail markets, we do not believe this will change fundamental state regulatory authorities, including authority to regulate the vast majority of generation asset costs, the siting of generation and transmission facilities, and decisions regarding retail service territories. We intend to be respectful of state objectives so long as they do not balkanize interstate transmission of power or conflict with our interstate open access policies. Stranded Costs With regard to stranded costs, the Final Rule adopts the Commission s supplemental proposal. It will permit utilities to seek extra-contractual recovery of stranded costs associated with a limited set of existing (executed on or before July 11, 1994) wholesale requirements contracts and provides that the Commission will be the primary forum for utilities to seek recovery of stranded costs associated with retail-turned-wholesale transmission customers. It also will allow utilities to seek recovery of stranded costs caused by retail wheeling only in circumstances in which the state regulatory authority does not have authority to address retail stranded costs at the time the retail wheeling is required. The Rule retains the revenues lost approach for calculating stranded costs and provides a formula for calculating such costs. Docket Nos. RM95-8-000 - 9 - and RM94-7-001 Environmental Issues The Commission has prepared a Final Environmental Impact Statement (FEIS) evaluating the possible environmental consequences of changes in the bulk power marketplace expected to occur as a result of the open access requirements of this Final Rule. The FEIS focuses, as do most commenters, on possible increases in emissions of nitrogen oxides (NOx) from certain fossil-fuel fired generators, which could affect air quality in the producing region and in areas to which these emissions may be carried. In response to comments on the Draft EIS, the Commission performed numerous additional studies. The FEIS finds that the relative future competitiveness of coal and natural gas generation is the key variable affecting the impact of the Final Rule. If competitive conditions favor natural gas, the Rule is likely to lead to environmental benefits. Both EPA and the Commission staff believe this projected scenario is the more likely one. If competitive conditions favor coal, the Rule may lead to small negative environmental impacts. However, even using the most extreme, unlikely assumptions about the future of the industry, the negative consequences are not likely to occur until after the turn of the century. Because the impacts will remain modest at least until 2010, there is no need for an interim mitigation program. In addition, even if the data showed more significant negative consequences requiring mitigation, the Commission does not have the statutory authority under the Docket Nos. RM95-8-000 - 10 - and RM94-7-001 Federal Power Act or the expertise to address this possible far- term problem. The Commission believes, however, that there is time for federal and state air quality authorities to address any potential adverse impact as part of a comprehensive NOx regulatory program under the Clean Air Act. 4/ Despite our conclusions regarding the lack of environmental impacts expected to result from the Rule, the Commission has examined a wide variety of proposals for mitigating possible adverse effects. We share the view of most commenters that the preferred approach for mitigating increased NOx emissions generally is a NOx cap and trading regulatory program comparable to that developed by Congress to address sulfur dioxide emissions in the Clean Air Act Amendments of 1990. 5/ The Commission has examined various means of establishing such a program, including use of existing federal authorities under the Clean Air Act, cooperative efforts by state and federal air quality regulators, and development of a new emissions regulatory program administered by the Commission under the Federal Power Act. The Commission has concluded that a NOx regulatory program could best be developed and administered under the Clean Air Act, in cooperation with interested states, and offers to lend Commission support to that effort should it become necessary. 4/ 42 U.S.C.  7401, et seq. 5/ 42 U.S.C.A.  7651b-e. Docket Nos. RM95-8-000 - 11 - and RM94-7-001 Conclusion The Commission believes that the Final Rule will remedy undue discrimination in transmission services in interstate commerce and provide an orderly and fair transition to competitive bulk power markets. II. PUBLIC REPORTING BURDEN The Open Access Final Rule and the Stranded Cost Final Rule specify filing requirements to be followed by public utilities that own, control or operate transmission facilities in interstate commerce in making non-discriminatory open access tariff filings and filings to recover legitimate, prudent and verifiable stranded costs. The information collection requirements of the final rules are attributable to FERC-516 "Electric Rate Filings." The current total annual reporting burden for FERC-516 is 828,300 hours. A. Docket No. RM95-8-000 (Open Access Final Rule) The Open Access Final Rule requires public utilities filing non-discriminatory open access tariffs to provide certain information to the Commission. The Commission estimated that the public reporting burden for the information collection would average 300 hours per response. This estimate included time for reviewing the requirements of the Commission's regulations, searching existing data sources, gathering and maintaining the necessary data, completing and reviewing the collection of information, and filing the revised information. No comments on the burden estimate were received. Because the Final Rule adopts Docket Nos. RM95-8-000 - 12 - and RM94-7-001 essentially the same information requirements that are contained in the proposed rule, we believe that the average filing burden is same for the Final Rule. In the proposed rule, the Commission noted that there are approximately 328 public utilities, including marketers and wholesale generation entities. We initially estimated that 137 public utilities own, control or operate facilities used for the transmission of electric energy in interstate commerce, and would be subject to the filing requirements of the proposed rule. Upon further review, the Commission believes that approximately 166 public utilities will respond to the information collection. Accordingly, the public reporting burden is estimated to be 49,800 hours. B. Docket No. RM94-7-001 (Stranded Cost Final Rule) In the supplemental notice of proposed rulemaking, the Commission estimated that the information requirements of the proposed rule would not differ substantially from those contained in the initial proposed rule. In that notice, the Commission estimated that the public reporting burden for the information requirements contained in the proposed rule would be 50 hours per response with 10 responses annually. No comments on this filing burden were received. The information requirements adopted in the Stranded Cost Final Rule are not substantially different from those in the proposed rule. Therefore, the Commission concludes that there will be no additional public filing burden associated with the Stranded Cost Final Rule. Docket Nos. RM95-8-000 - 13 - and RM94-7-001 III. BACKGROUND In the NOPR, we set out a detailed statement of the events leading up to this rulemaking. We repeat that background here, updated to reflect what has happened since March 1995, and discuss why it is necessary to undertake regulatory reform in the electric industry at this time. We do so to provide the necessary backdrop to our action in adopting this Rule. A. Structure of the Electric Industry at Enactment of Federal Power Act The Federal Power Act was enacted in an age of mostly self- sufficient, vertically integrated electric utilities, in which generation, transmission, and distribution facilities were owned by a single entity and sold as part of a bundled service (delivered electric energy) to wholesale and retail customers. Most electric utilities built their own power plants and transmission systems, entered into interconnection and coordination arrangements with neighboring utilities, and entered into long-term contracts to make wholesale requirements sales (bundled sales of generation and transmission) to municipal, cooperative, and other investor-owned utilities (IOUs) connected to each utility's transmission system. Each system covered limited service areas. This structure of separate systems arose naturally due primarily to the cost and technological limitations on the distance over which electricity could be transmitted. Through much of the 1960s, utilities were able to avoid price increases, but still achieve increased profits, because of Docket Nos. RM95-8-000 - 14 - and RM94-7-001 substantial increases in scale economies, technological improvements, and only moderate increases in input prices. 6/ Thus, there was no pressure on regulatory commissions to use regulation to affect the structure of the industry. 7/ B. Significant Changes in the Electric Industry In the late 1960s and throughout the 1970s, a number of significant events occurred in the electric industry that changed the perceptions of utilities and began a shift to a more competitive marketplace for wholesale power. 8/ This was the beginning of periods of rapid inflation, higher nominal interest rates, and higher electricity rates. 9/ During this time, consumers became concerned about higher electricity rates and questioned any price increases filed by utilities. 10/ During this same time frame, the construction of nuclear and other capital-intensive baseload facilities -- actively encouraged by federal and some state governments -- contributed 6/ Paul L. Joskow, Inflation and Environmental Concern: Structural Change in the Process of Public Utility Regulation, 17 J. Law & Econ. 291, 312 (1974); see also Charles F. Phillips, Jr., The Regulation of Public Utilities 11 (1988). 7/ See Joskow, supra at 312; see also Phillips, supra at 12. 8/ See Joskow, supra at 312; see also Phillips, supra at 12-13. 9/ See Joskow, supra at 312-13; see also Phillips, supra at 13. The Arab oil embargo resulted in significantly higher oil prices through the 1970s. See Richard J. Pierce, Jr., The Regulatory Treatment of Mistakes in Retrospect: Canceled Plants and Excess Capacity, 132 U. Pa. L. Rev. 497, 501 (1984). 10/ See Joskow, supra at 313; see also Phillips, supra at 13. Docket Nos. RM95-8-000 - 15 - and RM94-7-001 to the continuing cost increases and uncertainties in the industry. 11/ These investments were made based on the assumptions that there would be steady increases in the demand for electricity and continued large increases in the price of oil. 12/ However, due to conservation and economic downturns, the expected demand increases did not materialize. Load growth virtually disappeared in some areas, and many utilities unexpectedly found themselves with excess capacity. 13/ In addition, by the 1980s, the oil cartel collapsed, with a resulting glut of low-priced oil. 14/ At the same time, inflation substantially increased the costs of these large baseload generating plants. 15/ Surging interest rates further increased the cost of the capital needed to finance and capitalize these projects and completion schedules were 11/ See generally Jersey Central Power & Light Company v. FERC, 810 F.2d 1168, 1171 (D.C. Cir. 1987). 12/ Id. 13/ See Pierce, supra at 503. By 1983, the Department of Energy had estimated that the sunk costs for canceled nuclear plants alone amounted to $10 billion. Id. at 498. 14/ Id. 15/ See Bernard S. Black & Richard J. Pierce, Jr., The Choice Between Markets and Central Planning in Regulating the U.S. Electricity Industry, 93 Col. L. Rev. 1339, 1346 (1993) ("Actual costs of nuclear power plants vastly exceeded estimates, sometimes by as much as 1000%."). Docket Nos. RM95-8-000 - 16 - and RM94-7-001 significantly extended by, in part, more stringent safety and environmental requirements. 16/ As a result, expensive large baseload plants for which there was little or no demand, came onto the market or were in the process of being constructed. Accordingly, between 1970 and 1985, average residential electricity prices more than tripled in nominal terms, and increased by 25% after adjusting for general inflation. 17/ Moreover, average electricity prices for industrial customers more than quadrupled in nominal terms over the same period and increased 86% after adjusting for inflation. 18/ The rapidly increasing rates for electric power during this period, together with the opportunities provided by the Public Utility Regulatory Policies Act of 1978 (PURPA) (discussed infra), also prompted some industrial customers to bypass utilities by constructing their own generation facilities. This 16/ See Phillips, supra at 13. Fossil fuel-fired plants became subject to increased regulation as a result of the Clean Air Act of 1970, and its 1977 amendments. 42 U.S.C.  7401- 7642. In 1971, nuclear plant licensing became subject to the environmental impact statement requirements of the National Environmental Policy Act of 1969. 42 U.S.C.  4332. Following the 1979 accident at the Three Mile Island nuclear plant, nuclear plants also became subject to additional safety regulations, resulting in higher costs. See Energy Information Administration, The Changing Structure of the Electric Power Industry 1970-1991 (March 1993) 35. Between 1976 and 1980, most states and many localities instituted laws governing power plant siting. 17/ Based on retail prices reported in Energy Information Administration (EIA), Monthly Energy Review, January 1995, Table 9.9 (Prices adjusted for inflation using the GDP Deflator (1987 = 100)). 18/ Id. Docket Nos. RM95-8-000 - 17 - and RM94-7-001 further exacerbated rate increases for remaining customers -- primarily residential and commercial customers. Consumers responded to these "rate shocks" by exerting pressure on regulatory bodies to investigate the prudence of management decisions to build generating plants, especially when construction resulted in cost overruns, excess capacity, or both. Between 1985 and 1992, writeoffs of nuclear power plants totalled $22.4 billion. 19/ These writeoffs significantly reduced the earnings of the affected utilities. 20/ Delays in obtaining rate increases to reflect the effects of inflation further reduced investor returns. Thus, many utilities became reluctant to commit capital to long-term construction decisions involving large scale generating plants. 21/ In addition to economic changes in the industry, significant technological changes in both generation and transmission have occurred since 1935. Through the 1960s, bigger was cheaper in the generation sector and the industry was able to capitalize on economies of scale to produce power at lower per-unit costs from 19/ See Black & Pierce, supra at 1346 (These writeoffs were "about 17% of the book value of total 1992 utility investment."). 20/ Id. 21/ Id. ("The high perceived risk of future disallowances reversed utilities' incentives to overinvest, and made utilities extremely reluctant to build new power plants."). Docket Nos. RM95-8-000 - 18 - and RM94-7-001 larger and larger plants. 22/ As a result, large utility companies that could finance and manage construction projects of larger scale had a price advantage over smaller utility companies and customers who might otherwise have considered building their own generating units. Scale economies encouraged power generation by large vertically-integrated utility companies that also transmitted and distributed power. Beginning in the 1970s, however, additional economies of scale in generation were no longer being achieved. 23/ A significant factor was that larger generation units were found to need relatively greater maintenance and experience longer downtimes. 24/ The electric industry faced the situation "where the price of each incremental unit of electric power exceeded the average cost." 25/ Bigger was no longer better. 22/ See Preston Michie, Billing Credits for Conservation, Renewable, and Other Electric Power Resources: an Alternative to Marginal-Cost-Based Power Rates in the Pacific Northwest, 13 Environmental Law 963, 964-65 (1983). 23/ Id. at 965. 24/ Energy Information Administration, The Changing Structure of the Electric Power Industry 1970-1991 (March 1993) 37 ("As larger units were constructed, however, utilities discovered that downtime was as much as 5 times greater for units larger than 600 megawatts than for units in the 100-megawatt range.") 25/ Id.; see also George A. Perrault, Downsizing Generation: Utility Plans for the 1990s, Pub. Util. Fort. 15-16 (Sept. 27, 1990) ("The large base-load generating units that form the backbone of utility systems are almost totally absent from capacity plans for the 1990s."). Docket Nos. RM95-8-000 - 19 - and RM94-7-001 Further dictating against larger generation units were advances in technologies that allowed scale economies to be exploited by smaller size units, thereby allowing smaller new plants to be brought on line at costs below those of the large plants of the 1970s and earlier. Such new technologies include combined cycle units and conventional steam units that use circulating fluidized bed boilers. 26/ The combined cycle generating plants generally use natural gas as their primary fuel. This technology has been made possible by the development of more efficient gas turbines, shorter construction lead times, lower capital costs, increased reliability, and relatively minimal environmental impacts. 27/ Similarly, the circulating fluidized bed combustion boilers, fueled by coal and other conventional fuels, provide a more efficient and less polluting resource. Today, "the optimum size [of generation plants] has shifted from [more than 500 MW] (10-year lead time) to smaller units 26/ "From 1982 through 1991, the average capacity of fluidized- bed units increased rapidly to 72 megawatts for 4 units in 1991. The average capacity for the 19 units planned to begin operating in 1992 through 1995 increases to 83 megawatts." Energy Information Administration, The Changing Structure of the Electric Power Industry 1970-1991 (March 1993) 38. 27/ See Charles E. Bayless, Less is More: Why Gas Turbines Will Transform Electric Utilities, Pub. Util. Fort. (Dec. 1, 1994) 21. Docket Nos. RM95-8-000 - 20 - and RM94-7-001 (one-year lead time) [in the 50- to 150-MW range]." 28/ Indeed, smaller and more efficient gas-fired combined-cycle generation facilities can produce power on the grid at a cost ranging from 5 cents per kWh to less than 3 cents per kWh. 29/ This is significantly less than the costs for large plants constructed and installed by utilities over the last decade, which were typically in the range of 4 to 7 cents per kWh for coal plants and 9 to 15 cents for nuclear plants. 30/ Significant changes have also occurred in the transmission sector of the industry. Technological advances in transmission have made possible the economic transmission of electric power over long distances at higher voltages. 31/ This has made it 28/ Id. at 24. See also Wallace E. Brand, Is Bigger Better? Market Power in Bulk Power Supply: From FDR to NOPR, Pub. Util. Fort. (Feb. 15, 1996) 23 at 25 (while the optimal baseload unit size is about 500 MW for coal-fired steam turbines, the optimal size for gas fired combined-cycle units is about 150 to 200 MW). 29/ FERC staff calculations based in part on combined-cycle plant cost data reported in 1994 FERC Form No. 1 for a sample of units placed in service during 1990-94. Costs vary with regional fuel and construction costs, among other reasons. 30/ Coal and Nuclear plant cost data reported in 1994 FERC Form No. 1 and the EIA report, Electric Plant Cost and Power Production Expenses 1991, 1993 DOE/EIA-0455(91), for plants placed in service during 1986-94; see also The 1994 Electric Executives' Forum, Bakke (President and CEO of the AES Corporation), Pub. Util. Fort. (June 1, 1994) 45 ("New generation can be built at about 3 cents per kilowatt-hour (U.S. average). Old generation costs about twice that. . . ."). 31/ See Black & Pierce, supra at 1345 (In the late 1960s and 1970s, improved transmission efficiency and development of (continued...) Docket Nos. RM95-8-000 - 21 - and RM94-7-001 technically feasible for utilities with lower cost generation sources to reach previously isolated systems where customers had been captive to higher cost generation. In addition, the nature and magnitude of coordination transactions 32/ have changed dramatically since enactment of the FPA, allowing increased coordinated operations and reduced reserve margins. Substantial amounts of electricity now move between regions, as well as between utilities in the same region. Physically isolated systems have become a thing of the past. C. The Public Utility Regulatory Policies Act and the Growth of Competition In enacting PURPA, 33/ Congress recognized that the rising costs and decreasing efficiencies of utility-owned generating facilities were increasing rates and harming the economy as a whole. 34/ To lessen dependence on expensive foreign oil, avoid repetition of the 1977 natural gas shortage, 31/(...continued) regional transmission networks "made it possible to build power plants up to 1000 miles from power users."). 32/ Coordination transactions are voluntary sales or exchanges of specialized electricity services that allow buyers to realize cost savings or reliability gains that are not attainable if they rely solely on their own resources. For sellers, these transactions provide opportunities to earn additional revenue, and to lower customer rates, from capacity that is temporarily excess to native load capacity requirements. 33/ Pub. L. No. 95-617, 92 Stat. 3117 (codified in U.S.C. sections 15, 16, 26, 30, 42, and 43). 34/ See generally FERC v. Mississippi, 456 U.S. 742, 745-46 (1982). Docket Nos. RM95-8-000 - 22 - and RM94-7-001 and control consumer costs, Congress sought to encourage electric utilities to conserve oil and natural gas. 35/ In particular, Congress sanctioned the development of alternative generation sources designated as "qualifying facilities" (QFs) as a means of reducing the demand for traditional fossil fuels. 36/ PURPA required utilities to purchase power from QFs at a price not to exceed the utility's avoided costs and to sell backup power to QFs. 37/ PURPA specifically set forth limitations on who, and what, could qualify as QFs. In addition to technological and size 35/ The Power Plant and Industrial Fuel Use Act of 1978. Pub. L. No. 95-617, 92 Stat. 3117 (codified in U.S.C. sections 15, 16, 26, 30, 42, and 43). 36/ QFs include certain cogenerators and small power producers. PURPA also added sections 210, 211, and 212 to the FPA, providing the Commission with authority to approve applications for interconnections and, in limited circumstances, wheeling. However, under section 211, as enacted in PURPA, the Commission could approve an application for wheeling only if it found, inter alia, that the order "would reasonably preserve existing competitive relationships." Because of this and other limitations in sections 211 and 212 as originally enacted, the provision was virtually ineffective. Only one section 211 order was ever issued pursuant to the original provision, and it was pursuant to a settlement. See Public Service Company of Oklahoma, 38 FERC  61,050 (1987). As discussed infra, section 211 was subsequently revised by the Energy Policy Act of 1992. 37/ 456 U.S. at 750. Congress recognized that encouragement was needed in part because utilities had been reluctant to purchase electric power from, and sell power to, nonutility generators. Id. at 750-51. Docket Nos. RM95-8-000 - 23 - and RM94-7-001 criteria, PURPA set limits on who could own QFs. 38/ Notwithstanding these limitations, QFs proliferated. In 1989, there were 576 QF facilities. By 1993, there were more than 1,200 such facilities. 39/ For the same time period, installed QF capacity increased from 27,429 megawatts to 47,774 megawatts. 40/ The rapid expansion and performance of the QF industry demonstrated that traditional, vertically integrated public utilities need not be the only sources of reliable power. During this period, the profile of generation investment began to change, and a market for non-traditional power supply beyond the purchases required by PURPA began to emerge. QFs were limited to cogenerators and small power producers. 41/ 38/ For example, PURPA provided that a cogeneration facility or small power production facility could not be owned by a person primarily engaged in the generation or sale of electric power (other than from cogeneration or small power production facilities). See 16 U.S.C.  796(17) and (18). 39/ Energy Information Administration, Electric Power Annual 1993 (December 1994) 124 (Table 77). 40/ Id. EIA data for 1989 through 1991 was for facilities of 5 megawatts or more and for 1992 and 1993 was for facilities of 1 megawatt or more. A comparison with Table 74 on page 121 for the years 1992 and 1993 reveals that this mixing of data bases is likely of minimal effect. 41/ Generally, the law has imposed an 80 MW cap on small power producers. A limited exception enacted in 1990 permitted small power facilities that could exceed 80 MW and still qualify as QFs under PURPA. This exception was limited to certain solar, wind, waste, and geothermal small power production facilities and only covered applications for certification of facilities as qualifying small power production facilities that were submitted no later than December 31, 1994 and for which construction commences no later than December 31, 1999. See Solar, Wind, Waste, and (continued...) Docket Nos. RM95-8-000 - 24 - and RM94-7-001 However, other non-traditional power producers who could not meet the QF criteria began to build new capacity to compete in bulk power markets, without such PURPA benefits as the mandatory purchase requirements. These producers, known as independent power producers (IPPs), were predominantly single-asset generation companies that did not own any transmission or distribution facilities. While traditional utilities were generally reluctant at that time to invest in new generating facilities under cost of service regulation, utilities increasingly became interested in participating in this new generation sector. They organized affiliated power producers (APPs), with assets not included in utility rate base, and sought to sell power in their own service territories and the territories of other utilities. At the same time, power marketers arose. These entities -- owning no transmission or generation -- buy and sell power. 42/ There were two major impediments to the development of IPPs and APPs. First, the ownership restrictions of the Public Utility Holding Company Act (PUHCA) 43/ severely inhibited 41/(...continued) Geothermal Power Production Incentives Act of 1990, Pub. L. No. 101-575, 104 Stat. 2834 (1990), amended, Pub. L. No. 102-46, 105 Stat. 249 (1991). 42/ The first power marketer in the electric industry was Citizens Energy Corporation. See Citizens Energy Corporation, 35 FERC  61,198 (1986). Power marketers take title to electric energy. Power brokers, on the other hand, do not take title and are limited to a matchmaking role. 43/ 15 U.S.C.  79 et seq. Docket Nos. RM95-8-000 - 25 - and RM94-7-001 these new entities from entering the generation business. 44/ Second, these entities needed transmission service in order to compete in electricity markets. While the Commission had no authority to remove PUHCA restrictions, 45/ it encouraged the development of IPPs and APPs, as well as emerging power marketers, by authorizing market- based rates for their power sales on a case-by-case basis and by encouraging more widely available transmission access. From 1989 through 1993, facilities owned by IPPs and other non-traditional generators (other than QFs) increased from 249 to 634 and their installed capacity increased from 9,216 megawatts to 13,004 megawatts. 46/ Indeed, "[i]n 1992, for the first time, generating capacity added by independent producers exceeded capacity added by utilities." 47/ Market-based rates helped to develop competitive bulk power markets. A generating utility allowed to sell its power at market-based rates could move more quickly to take advantage of short-term or even long-term market opportunities than those 44/ As discussed infra, Congress eventually provided a means to avoid the PUHCA restrictions by creating exempt wholesale generators (EWGs) in the Energy Policy Act. 45/ The industry was successful to some extent in developing ownership structures that permitted such investment. See, e.g., Commonwealth Atlantic Limited Partnership, 51 FERC  61,368 at 62,240 and n.20 (1990). 46/ Energy Information Administration, Electric Power Annual 1993 (December 1994) 124 (Table 77). 47/ Black & Pierce, supra at 1349 n.25. Docket Nos. RM95-8-000 - 26 - and RM94-7-001 laboring under traditional cost-of-service tariffs, which entail procedural delays in achieving tariff approvals and changes. In approving these market-based rates, the Commission required, inter alia, that the seller and any of its affiliates lack market power or mitigate any market power that they may have possessed. 48/ The major concern of the Commission was whether the seller or its affiliates could limit competition and thereby drive up prices. A key inquiry became whether the seller or its affiliates owned or controlled transmission facilities in the relevant service area and therefore, by denying access or imposing discriminatory terms or conditions on transmission service, could foreclose other generators from competing. 49/ As we have previously explained: The most likely route to market power in today's electric utility industry lies through ownership or control of transmission facilities. Usually, the source of market power is dominant or exclusive ownership of the facilities. However, market power also may be gained without ownership. Contracts can confer the same rights of control. Entities with contractual control over transmission facilities can withhold supply and extract monopoly prices just as 48/ See, e.g., Ocean State Power, 44 FERC  61,261 (1988); Commonwealth Atlantic Limited Partnership, 51 FERC  61,368 (1990); Citizens Power & Light Company, 48 FERC  61,210 (1989); Orange and Rockland Utilities, Inc., 42 FERC  61,012 (1988); Doswell Limited Partnership, 50 FERC  61,251 (1990) (Doswell); and Dartmouth Power Associates Limited Partnership, 53 FERC  61,117 (1990). 49/ See, e.g., Doswell, 50 FERC at 61,757. Docket Nos. RM95-8-000 - 27 - and RM94-7-001 effectively as those who control facilities through ownership. [50/] As entry into wholesale power generation markets increased, the ability of customers to gain access to the transmission services necessary to reach competing suppliers became increasingly important. 51/ In addition, beginning in the late 1980s, in order to mitigate their market power to meet Commission conditions, public utilities seeking Commission approval of mergers or consolidations under section 203 of the FPA or Commission authorization for blanket approval of market- based rates for generation services under section 205 of the FPA, filed "open access" transmission tariffs of general 50/ Citizens Power & Light Corporation, 48 FERC  61,210 at 61,777 (1989) (emphasis in original); see also Utah Power & Light Company, PacifiCorp and PC/UP&L Merging Corporation, 45 FERC  61,095 at 61,287-89 (1988), order on reh'g, 47 FERC  61,209, order on reh'g, 48 FERC  61,035 (1989), remanded in part sub nom. Environmental Action, Inc. v. FERC, 939 F.2d 1057 (D.C. Cir. 1991), order on remand, 57 FERC  61,363 (1991). 51/ In earlier years, a few customers were able to obtain access as a result of litigation, beginning with the Supreme Court's decision in Otter Tail Power Company v. United States, 410 U.S. 366 (1973). Additionally, some customers gained access by virtue of Nuclear Regulatory Commission license conditions and voluntary preference power transmission arrangements associated with federal power marketing agencies. See, e.g., Consumers Power Company, 6 NRC 887, 1036-44 (1977) and The Toledo Edison Company and Cleveland Electric Illuminating Company, 10 NRC 265, 327-34 (1979). See Florida Municipal Power Agency v. Florida Power and Light Company, 839 F. Supp. 1563 (M.D. Fla. 1993). See also Electricity Transmission: Realities, Theory and Policy Alternatives, The Transmission Task Force Report to the Commission, October 1989, 197. Docket Nos. RM95-8-000 - 28 - and RM94-7-001 applicability. 52/ The Commission applied its market rate analysis to IOUs, as well as IPPs, APPs, and marketers, and allowed IOUs to sell at market-based rates only if they opened their transmission systems to competitors. 53/ The Commission also approved proposed mergers on the condition that the merging companies remedy anticompetitive effects potentially caused by the merger by filing "open access" tariffs. These early "open access" tariffs required only that the companies provide point- to-point transmission services, which is a much narrower requirement than that being imposed in this Rule and did not require transmission owners to provide to others the same quality of service that they themselves enjoyed. Following PURPA, the economic and technological changes in the transmission and generation sectors helped give impetus to the many new entrants in the generating markets who could sell 52/ See, e.g., Public Service Company of Colorado, 59 FERC  61,311 (1992), reh'g denied, 62 FERC  61,013 (1993); Utah Power & Light Company, et al., Opinion No. 318, 45 FERC  61,095 (1988), order on reh'g, Opinion No. 318-A, 47 FERC  61,209 (1989), order on reh'g, Opinion No. 318-B, 48 FERC  61,035 (1989), aff'd in relevant part sub nom. Environmental Action Inc. v. FERC, 939 F.2d 1057 (D.C. Cir. 1991); Northeast Utilities Service Company (Public Service Company of New Hampshire), Opinion No. 364-A, 58 FERC  61,070, reh'g denied, Opinion No. 364-B, 59 FERC  61,042, order granting motion to vacate and dismissing request for rehearing, 59 FERC  61,089 (1992), affirmed in relevant part sub nom. Northeast Utilities Service Company v. FERC, 993 F.2d 937 (1st Cir. 1993). 53/ See, e.g., Public Service of Indiana, Inc., 51 FERC  61,367 (1990), reh'g denied, 52 FERC  61,260 (1990), appeal dismissed sub nom. Northern Indiana Public Service Company v. FERC, 954 F.2d 736 (D.C.Cir. 1992). Docket Nos. RM95-8-000 - 29 - and RM94-7-001 electric energy profitably with smaller scale technology at a lower price than many utilities selling from their existing generation facilities at rates reflecting cost. However, it became increasingly clear that the potential consumer benefits that could be derived from these technological advances could be realized only if more efficient generating plants could obtain access to the regional transmission grids. Because many traditional vertically integrated utilities still did not provide open access to third parties and still favored their own generation if and when they provided transmission access to third parties, barriers continued to exist to cheaper, more efficient generation sources. D. The Energy Policy Act In response to the competitive developments following PURPA, and the fact that PUHCA and lack of transmission access remained major barriers to new generators, Congress enacted Title VII of the Energy Policy Act of 1992 (Energy Policy Act). 54/ A goal of the Energy Policy Act was to promote greater competition in bulk power markets by encouraging new generation entrants, known as exempt wholesale generators (EWGs), and by expanding the 54/ Pub. L. No. 102-486, 106 Stat. 2776 (1992), codified at, among other places, 15 U.S.C.  79z-5a and 16 U.S.C.  796(22-25), 824j-l. Docket Nos. RM95-8-000 - 30 - and RM94-7-001 Commission's authority under sections 211 and 212 of the FPA to approve applications for transmission services. 55/ An EWG is defined as any person determined by the Federal Energy Regulatory Commission to be engaged directly, or indirectly through one or more affiliates as defined in [PUHCA] section 2(a)(11)(B), and exclusively in the business of owning or operating, or both owning and operating, all or part of one or more eligible facilities and selling electric energy at wholesale. [56/] If the Commission, upon an application, determines that a person is an EWG, that person will be exempt from PUHCA. 57/ This provision removed a significant impediment to the development of IPPs and APPs by allowing them to develop projects as EWGs free from the strictures of PUHCA or the QF PURPA limitations. While sections 211 and 212, as enacted by PURPA, were intended to provide greater access to the transmission grid, the limitations placed on these sections made them unusable in virtually all circumstances. 58/ However, as amended by the Energy Policy Act, these sections now give the Commission broader 55/ See El Paso Electric Company and Central and South West Services Inc., 68 FERC  61,181 at 61,914 (1994) (CSW); see also Paul Kemezis, FERC's Competitive Muscle: The Comparability Standard, Electrical World 45 (Jan. 1995) ("In EPAct, Congress made it clear that the electric-power industry was to move toward a fully competitive market system, but left most of the implementation to FERC."). 56/ 15 U.S.C.  79z-5a. 57/ 15 U.S.C.  79z-5a(e). 58/ See supra note 36. Docket Nos. RM95-8-000 - 31 - and RM94-7-001 authority to order transmitting utilities to provide wholesale transmission services, upon application, to any electric utility, Federal power marketing agency, or any other person generating electric energy for sale for resale. The Energy Policy Act also added section 213 to the FPA. Section 213(a) requires a transmitting utility that does not agree to provide wholesale transmission service in accordance with a good faith request to provide a written explanation of its proposed rates, terms, and conditions and its analysis of any physical or other constraints. 59/ Section 213(b) required the Commission to enact a rule requiring transmitting utilities to submit annual information concerning potentially available transmission capacity and known constraints. 60/ E. The Present Competitive Environment Following the Energy Policy Act, the Commission established rules: (1) for certain generators to obtain EWG status and thus 59/ See Policy Statement Regarding Good Faith Requests for Transmission Services and Responses by Transmitting Utilities Under Sections 211(a) and 213(a) of the Federal Power Act, as Amended and Added by the Energy Policy Act of 1992, 58 FR 38964 (July 21, 1993), FERC Stats. & Regs., Regulations Preambles  30,975 (1993) (Policy Statement Regarding Good Faith Requests for Transmission Services). 60/ See New Reporting Requirements Implementing Section 213(b) of the Federal Power Act and Supporting Expanded Regulatory Responsibilities Under the Energy Policy Act of 1992, and Conforming and Other Changes to Form No. FERC-714, 58 FR 52420 (October 8, 1993), FERC Stats. & Regs., Regulations Preambles  30,980 (Order No. 558), reh'g denied, Order No. 558-A, 65 FERC  61,324 (1993), regulations modified, 59 FR 15333 (April 1, 1994), FERC Stats. & Regs., Regulations Preambles  30,993. Docket Nos. RM95-8-000 - 32 - and RM94-7-001 an exemption from PUHCA; 61/ and (2) that required transmission information availability. The Commission also pursued a number of initiatives aimed at fostering the development of more competitive bulk power markets, including aggressive implementation of section 211, a new look at undue discrimination under the FPA, easing of market entry for sellers of generation from new facilities, and initiation of a number of industry-wide reforms. As stated by the Commission, in recognition of the Congressional goal in the Energy Policy Act of creating competitive bulk power markets: Our goal is to facilitate the development of competitively priced generation supply options, and to ensure that wholesale purchasers of electric energy can reach alternative power suppliers and vice versa. [62/] 61/ See Order No. 550, Filing Requirements and Ministerial Procedures for Persons Seeking Exempt Wholesale Generator Status, 58 FR 8897 (February 18, 1993), FERC Stats. & Regs., Regulations Preambles  30,964, order on reh'g, Order No. 550-A, 58 FR 21250 (April 20, 1993), FERC Stats. & Regs., Regulations Preambles  30,969 (1993). As recognized by Congress and the Commission, availability of transmission information is critical in developing competitive markets. See supra notes 59 and 60. This opened the "black box" of information that previously was available only to transmission owners. 62/ See Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Notice of Proposed Rulemaking, 59 FR 35274 (July 11, 1994), FERC Stats. & Regs., Proposed Regulations  32,507 at 32,866 (Stranded Cost NOPR); American Electric Power Service Corporation, 67 FERC  61,168, clarified, 67 FERC  61,317 (1994). Docket Nos. RM95-8-000 - 33 - and RM94-7-001 1. Use of Sections 211 and 212 to Obtain Transmission Access The Commission has aggressively implemented sections 211 and 212 of the FPA, as amended by the Energy Policy Act, in order to promote competitive markets. 63/ When wheeling requests under sections 211 and 212 have been made, the Commission has required wheeling in almost all of the requests it has processed. To date, the Commission has issued orders (proposed or final) requiring wheeling in 12 of the 14 cases it has acted on. 64/ As a general matter, section 211 has permitted some inroads to be made by customers in obtaining transmission service from public utilities that historically have declined to provide access to their systems, or have offered service only on a discriminatory basis. Under section 211, the Commission has granted requests for the broader type of service that most utilities historically have refused to provide -- network service. Although transmission owners have provided limited amounts of unbundled point-to-point transmission service, third- party customers have not been able to obtain the flexibility of service that transmission owners enjoy. 63/ 16 U.S.C.A.  824j-824k (West 1985 and Supp. 1994). 64/ See, e.g., final orders issued in City of Bedford, 68 FERC  61,003 (1994), reh'g denied, 73 FERC  61,322 (1995); Florida Municipal Power Agency v. Florida Power & Light Company, 67 FERC  61,167 (1994), order on reh'g, 74 FERC  61,006 (1996); Minnesota Municipal Power Agency, 68 FERC  61,060 (1994); and Tex-La Electric Cooperative of Texas, 69 FERC  61,269 (1994); see also Appendix A. Docket Nos. RM95-8-000 - 34 - and RM94-7-001 In Florida Municipal, a section 211 case, the Commission ordered "network," rather than the narrower "point-to-point," service. 65/ Network service permits the applicant to fully integrate load and resources on an instantaneous basis in a manner similar to the transmission owner's integration of its own load and resources. At the same time, the Commission made the generic finding that the availability of transmission service will enhance competition in the market for power supplies and lead to lower costs for consumers. The Commission explained that as long as the transmitting utility is fully and fairly compensated and there is no unreasonable impairment of reliability, transmission service is in the public interest. 66/ As discussed infra, based on the mounting competitive pressures in the industry and rapidly evolving markets, we have concluded that section 211 alone is not enough to eliminate undue 65/ See Florida Municipal Power Agency v. Florida Power & Light Company, 65 FERC  61,125, reh'g dismissed, 65 FERC  61,372 (1993), final order, 67 FERC  61,167 (1994), order on reh'g , 74 FERC  61,006 (1996). The Commission has "characterized point-to-point service as involving designated points of entry into and exit from the transmitting utility's system, with a designated amount of transfer capability at each point." El Paso Electric Company v. Southwestern Public Service Company, 68 FERC  61,182 at 61,926 n.9 (1994) (citing Entergy Services, Inc., 58 FERC  61,234 at 61,768 (1993), reh'g dismissed, 68 FERC  61,399 (1994)). Network service allows more flexibility by allowing a transmission customer to use the entire transmission network to provide generation service for specified resources and specified loads without having to pay multiple charges for each resource-load pairing. 66/ Florida Municipal, 67 FERC at 61,477. Docket Nos. RM95-8-000 - 35 - and RM94-7-001 discrimination. The comments received on the proposed rules, discussed in detail infra, confirm this conclusion. The significant time delays involved in filing an individual service request for bilateral service under section 211 place the customer at a severe disadvantage compared to the transmission owner and can result in discriminatory treatment in the use of the transmission system. It is an inadequate procedural substitute for readily available service under a filed non- discriminatory open access tariff. As the Commission noted in Hermiston Generating Company, "[t]he ability to spend time and resources litigating the rates, terms and conditions of transmission access is not equivalent to an enforceable voluntary offer to provide comparable service under known rates, terms and conditions." 67/ 2. Commission's Comparability Standard In the Spring of 1994, the Commission began to address the problem of the disparity in transmission service that utilities provided to third parties in comparison to their own uses of the transmission system. In the seminal case in this area, American Electric Power Service Corporation (AEP), the company voluntarily proposed a tariff of general applicability that would offer firm, 67/ 69 FERC  61,035 at 61,165 (1994), reh'g denied, 72 FERC  61,071 (1995); see also Southwest Regional Transmission Association, 69 FERC  61,100 at 61,398 (1994), order on compliance filing, 73 FERC  61,147 (1995) (SWRTA). Docket Nos. RM95-8-000 - 36 - and RM94-7-001 point-to-point transmission service for a minimum of one month. 68/ The Commission accepted the proposed transmission tariff for filing and suspended its effectiveness for one day, subject to refund. 69/ Rehearing requests challenged the Commission's summary approval of the restriction of service to point-to-point as being discriminatory and anticompetitive. 70/ The rehearing requests argued that the tariff should be expanded to include network services such as those used by the transmission owner. On rehearing, the Commission announced a new standard for evaluating claims of undue discrimination. The Commission found that a voluntarily offered, new open access transmission tariff that did not provide for services comparable to those that the transmission owner provided itself was unduly discriminatory and anticompetitive. 71/ In 68/ 64 FERC  61,279 (1993), reh'g granted, 67 FERC  61,168, clarified, 67 FERC  61,317 (1994). 69/ The Commission explained that AEP could limit the service it was offering because it was "providing the service voluntarily under a tariff of general applicability." 64 FERC at 62,978. 70/ AEP, 67 FERC at 61,489. 71/ With respect to anticompetitive effects, the Commission explained that it has "adhered to the Supreme Court's determination that the Commission's 'important and broad regulatory power . . . carries with it the responsibility to consider, in appropriate circumstances, the anticompetitive effects of regulated aspects of interstate utility operations pursuant to  202 and 203, and under like directives contained in  205, 206 and 207.' Gulf States Utilities Company v. FPC, 411 U.S. 747, 758-59 (1972)." Id. at 61,490 (footnote omitted). The Commission reaffirmed that it would examine how best to fulfill this (continued...) Docket Nos. RM95-8-000 - 37 - and RM94-7-001 reaching that conclusion, the Commission broadened its undue discrimination analysis (which traditionally had focused on the rates, terms, and conditions faced by similarly situated third- party customers) to include a focus on the rates, terms, and conditions of a utility's own uses of the transmission system: [A]n open access tariff that is not unduly discriminatory or anticompetitive should offer third parties access on the same or comparable basis, and under the same or comparable terms and conditions, as the transmission provider's uses of its system. [72/] Refocusing the analysis was necessitated by the changing conditions in the electric utility industry, including the emergence of non-traditional suppliers and greater competition in bulk power markets. Because a transmission provider may use its system in different ways (e.g., to integrate load and resources when serving retail native load, to make off-system sales or purchases, or to serve wholesale requirements customers), the Commission set for hearing the factual issues associated with identifying those uses, as well as any potential impediments or consequences to providing comparable services to third parties. 73/ 71/(...continued) responsibility, as well as its responsibility to prevent undue discrimination, in light of the changing conditions in the electric utility industry. Id. 72/ Id. at 61,490. 73/ Id. at 61,490-91. Docket Nos. RM95-8-000 - 38 - and RM94-7-001 After AEP, the Commission applied this comparability standard to a proposed open access transmission tariff that was filed by Kansas City Power & Light Company (KCP&L) in support of a proposal to sell generation at market-based rates. 74/ The Commission explained that, in light of AEP, the utility's proposed open access transmission tariff (which provided only for point-to-point service) did not adequately mitigate its transmission market power so as to justify allowing the requested market-based rates. KCP&L could charge market-based rates for sales only if it modified its proposed transmission tariff to reflect the AEP comparability standard. Since then, the Commission has required comparable service in a variety of contexts, and has set for hearing the factual issues associated with comparable service. For example, the Commission found that market power can be adequately mitigated only if a merged company offers transmission services in accordance with the AEP comparability standard. 75/ The Commission further held that, even if a merger does not result in an increase in market power, the merger would not be consistent with the public interest under section 203 of the FPA unless the merged company offers comparable transmission services, as 74/ See Kansas City Power & Light Company, 67 FERC  61,183 (1994), reh'g pending. 75/ E.g., CSW, supra, 68 FERC at 61,914. Docket Nos. RM95-8-000 - 39 - and RM94-7-001 defined in AEP. 76/ The Commission therefore announced a transmission comparability requirement for all new mergers: Given the transition of the electric utility industry as a whole, we conclude that, absent other compelling public interest considerations, coordination in the public interest can best be secured only if merging utilities offer comparable transmission services. [77/] In Heartland Energy Services, Inc., 78/ the Commission applied its comparability standard to an affiliated electric power marketer seeking blanket authorization to sell electricity at market-based rates. The Commission explained that for all future cases involving blanket approval of market-based rates an offer of comparable transmission services will be required before the Commission will be able to find that transmission market power has been adequately mitigated. In the context of an affiliated power marketer, this means that all of its affiliated utilities must have a comparable transmission tariff on file. [79/] 76/ Id. 77/ Id. at 61,915 (footnote omitted). 78/ 68 FERC  61,223 (1994). 79/ Id. at 62,060. In InterCoast Power Marketing Company, 68 FERC  61,248, clarified, 68 FERC  61,324 (1994), the Commission rejected an affiliated marketer's proposal to sell at market rates without its affiliate utility offering comparable transmission services. The Commission stated that the only way to ensure that InterCoast does not have transmission market power is to require its affiliated public utility to offer comparable transmission services. See also LG&E Power Marketing Inc., 68 FERC  61,247 at 62,120-21 (1994). The Commission added that this is consistent with encouraging competitive bulk power markets as envisioned by the Energy Policy Act of 1992. Id. at 62,132. Docket Nos. RM95-8-000 - 40 - and RM94-7-001 The Commission also denied a request by a company affiliated with a transmission-owning utility seeking permission to sell power at market-based rates to a particular customer. The denial was without prejudice to refiling such a request in a new section 205 proceeding, but only after the affiliated transmission-owning utility filed a comparable transmission service tariff. 80/ The Commission added that it will require comparability in any situation in which a seller seeking market-based rates is affiliated with an owner or controller of transmission facilities. [81/] The Commission has also stated that "it will henceforth apply the transmission comparability standard announced in the AEP case to all transmitting utility members of an RTG." 82/ 80/ See Hermiston Generating Company, 69 FERC  61,035 at 61,164 (1994), reh'g pending. The Commission subsequently accepted the rates on a cost basis. See Letter Order dated November 10, 1994. 81/ Id. at 61,165. 82/ See SWRTA, 69 FERC at 61,397; see also PacifiCorp, the California Municipal Utilities Association, and the Independent Energy Producers (on behalf of Western Regional Transmission Association), 69 FERC  61,099, order on reh'g, 69 FERC  61,352 (1994), order on compliance filing, 71 FERC  61,158 (1995) (WRTA). An RTG is a regional transmission group. It is defined as "a voluntary organization of transmission owners, transmission users, and other entities interested in coordinating transmission planning (and expansion), operation and use on a regional (and inter- regional." Policy Statement Regarding Regional Transmission Groups, 58 FR 41626 (August 5, 1993), FERC Stats. & Regs., Regulations Preambles  30,976 at 30,870 n.4 (RTG Policy Statement). Docket Nos. RM95-8-000 - 41 - and RM94-7-001 The Commission further declared that comparable services must be provided through "open access" tariffs rather than only on a contract-by-contract basis: [T]ariffs are essential to the provision of comparable services. Tariffs set out the services that are available and the terms and conditions under which those services will be made available....[In contrast], a negotiation process creates uncertainty and imposes on customers delay and other transaction costs that the transmitting utility members of an RTG do not incur when using the transmission for their own benefit. Moreover, the ability to execute separate transmission agreements with different but similarly situated customers is the ability to unduly discriminate among them. A tariff ensures against such discrimination in the RTG. [83/] Thus, the Commission required the RTGs to amend their bylaws to commit all transmitting utility members to offer comparable transmission services to other RTG members pursuant to a transmission tariff or tariffs. As discussed below, since the AEP comparability standard was announced, the Commission has set for hearing 44 open access tariffs to determine what constitutes comparable service. This number includes tariffs filed subsequent to the Open Access NOPR. All tariffs have now been made subject to the outcome of the Final Rule. 3. Lack of Market Power in New Generation In 1994 in the KCP&L case, discussed in the prior section, the Commission continued to recognize that transmission remains a 83/ SWRTA, 69 FERC at 61,398. Docket Nos. RM95-8-000 - 42 - and RM94-7-001 natural monopoly. However, it found that, in light of the industry and statutory changes that now allow ease of market entry, no wholesale seller of generation has market power in generation from new facilities. 84/ In particular, the Commission explained that it had previously noted in Entergy Services, Inc. that there was significant evidence that non- traditional power project developers, including qualifying facilities and independent power projects, are becoming viable competitors in long-run markets. [85/] The Commission further explained that since Entergy, Congress had enacted the Energy Policy Act, which had lowered barriers to the entry of new suppliers by creating a new class of power suppliers -- EWGs -- that are exempt from the provisions of PUHCA. 86/ The Commission concluded that, in considering market-based rate proposals for generation sales, it need only focus on market power in transmission, generation market power in short-run markets, and other barriers to entry. 87/ 84/ KCP&L, 67 FERC  61,183 (1994). 85/ Id. at 61,557 (citing Entergy Services, Inc., 58 FERC  61,234 at 61,756 and nn.63 and 65 (Entergy)). 86/ Id. The Commission added that "after examining generation dominance in many different cases over the years, we have yet to find an instance of generation dominance in long-run bulk power markets." Id. 87/ Id. Docket Nos. RM95-8-000 - 43 - and RM94-7-001 4. Further Commission Action Addressing a More Competitive Electric Industry To address the fact that the electric industry is becoming more competitive, and to remove barriers that might inhibit a more competitive industry, the Commission has initiated a number of proceedings: (1) Stranded Cost NOPR, 88/ (2) Transmission Pricing Policy Statement, 89/ (3) Pooling Notice of Inquiry, 90/ (4) Regional Transmission Group (RTG) Policy Statement, 91/ and (5) Notice of Inquiry on Merger Policy. 92/ In the Stranded Cost NOPR the Commission recognized that the trend toward greater transmission access and the transition to a fully competitive bulk power market could cause some utilities to incur stranded costs as wholesale requirements customers (or retail customers) use their supplier's transmission to purchase power elsewhere. As the Commission noted, a utility may have built facilities or entered into long- term fuel or purchased power supply contracts with the reasonable 88/ FERC Stats. & Regs.  32,507 (1994). 89/ Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities Under the Federal Power Act, 59 FR 55031 (November 3, 1994), FERC Stats. & Regs., Regulations Preambles  31,005 (Transmission Pricing Policy Statement). 90/ Inquiry Concerning Alternative Power Pooling Institutions Under the Federal Power Act, 59 FR 54851 (October 26, 1994), FERC Stats. & Regs., Notices  35,529 (1995) (Pooling Notice of Inquiry). 91/ FERC Stats. & Regs.  30,976 (RTG Policy Statement). 92/ FERC Stats. & Regs.  35,531 (1996). Docket Nos. RM95-8-000 - 44 - and RM94-7-001 expectation that its customers would renew their contracts and would pay their share of long-term investments and other incurred costs. If the customer obtains another power supplier, the utility may have stranded costs. If the utility cannot locate an alternative buyer or somehow mitigate the stranded costs, the Commission explained that "the costs must be recovered from either the departing customer or the remaining customers or borne by the utility's shareholders." 93/ Accordingly, the Commission proposed to establish provisions concerning the recovery of wholesale and retail stranded costs by public utilities and transmitting utilities. In the Transmission Pricing Policy Statement, the Commission announced a new policy providing greater flexibility in the pricing of transmission services provided by public utilities and transmitting utilities. The Commission traditionally had allowed only postage-stamp, contract-path pricing. 94/ Under the new policy, we will permit a variety of proposals, including distance sensitive and flow-based pricing, which may be more suitable for 93/ FERC Stats. & Regs.  32,507 at 32,864. 94/ Most transmission contracts set a single price for energy flow over a utility's transmission system. This single- price policy is called "postage stamp" pricing because the rate does not depend on how far the power moves within a company's transmission system. If power flows through several companies, traditional industry practice is to specify that power flows along a "contract path" consisting of the transmission-owning utilities between the ultimate receipt and delivery points. See Indiana Michigan Power Company, 64 FERC  61,184 at 62,545 (1993). Docket Nos. RM95-8-000 - 45 - and RM94-7-001 competitive wholesale power markets. 95/ The Commission explained that this "[g]reater pricing flexibility is appropriate in light of the significant competitive changes occurring in wholesale generation markets, and in light of our expanded wheeling authority under the Energy Policy Act of 1992." 96/ However, the Commission explained that any new transmission pricing proposal must meet the Commission's AEP comparability standard. The Commission further explained that comparability of service applies to price as well as to terms and conditions. 97/ The Commission issued the Pooling Notice of Inquiry to receive comments on traditional power pools and on alternative power pooling institutions that are being explored in today's more competitive environment. The Commission expressed concern that [g]iven the ongoing changes in the competitive environment of the electric utility industry -- in particular, the potential for substantially increased access to transmission -- we must consider whether 95/ Unlike with postage stamp pricing, with distance-sensitive pricing the cost of moving power through a company depends on how far the power moves within the company. In contrast to contract path pricing, flow-based pricing establishes a price based on the costs of the various parallel paths actually used when the power flows. Because flow-based pricing can account for all parallel paths used by the transaction, all transmission owners with facilities on any of the parallel paths could be compensated for the transaction. 96/ FERC Stats. & Regs.  31,005 at 31,136. 97/ Id. at 31,142. Docket Nos. RM95-8-000 - 46 - and RM94-7-001 we are appropriately balancing our dual objectives of promoting coordination and competition. [98/] Accordingly, the Commission explained that it wished to look at alternative power pooling institutions and to re-examine the role of more traditional power pools in today's environment of increased competition. In particular the Commission expressed its intent to ensure that its policies "are consistent with the development of a competitive bulk power market." 99/ In the RTG Policy Statement, the Commission announced a policy encouraging the development of RTGs. The Commission explained that a primary purpose of RTGs is to facilitate transmission access for potential users and voluntarily resolve disputes over such service. The Commission has approved the formation of three RTGs. 100/ One of the conditions is that each RTG member must offer comparable transmission services by tariff to other RTG members. In the merger NOI, the Commission indicated that it will review whether its criteria and policy for evaluating mergers need to be modified in light of the changing circumstances occurring in the electric industry. 98/ FERC Stats. & Regs.  35,529 at 35,715. 99/ Id. at 35,714. As explained below, the Commission held technical conferences on issues surrounding power pools and competition. 100/ See WRTA and SWRTA, supra, and Northwest Regional Transmission Association, 71 FERC  61,397 (1995). Docket Nos. RM95-8-000 - 47 - and RM94-7-001 In addition to the Commission's actions, a number of states have initiated proceedings concerning retail wheeling or proposed legislation for retail wheeling, that is, for ultimate consumers to choose their supplier of power, or other restructuring proposals. 101/ 5. Events Since Issuance of Open Access NOPR Since issuance of the Open Access NOPR, public utilities have filed, in some form or another, 47 open access tariffs. In acting on those filings, the Commission has made all of the non- rate terms and conditions of those proposed tariffs subject to the outcome of this Final Rule. 102/ 101/ At least 12 states have retail wheeling proposals, legislation, or pilot programs underway -- Alabama, California, Connecticut, Illinois, Massachusetts, Michigan, New Hampshire, New York, Ohio, Rhode Island, Vermont, and Wisconsin. At least 14 other states are investigating retail wheeling. Currently, according to a report of the NARUC-affiliated National Council on competition and the Electric Industry, 41 States are actively involved in investigating whether and how to restructure their respective electric power markets. Of this total, 29 State regulatory authorities . . . have initiated investigations. In addition, five State legislatures are involved in similar investigations, while seven other States have joint regulatory/legislative proceedings underway. Testimony of the Honorable Cheryl L. Parrino, Chair of the Wisconsin Public Service Commission, on behalf of the National Association of Regulatory Utility Commissioners, before the United States Senate Committee on Energy and Natural Resources (March 6, 1996). 102/ See American Electric Power Service Corporation, et al., 72 FERC  61,287 at 61,238 (1995). Docket Nos. RM95-8-000 - 48 - and RM94-7-001 Over the last year, the Commission also has received and analyzed more than 20,000 pages of comments that were received from over 400 commenters, as well as additional information provided by industry participants at a number of Commission- initiated technical conferences. 103/ Those technical conferences addressed several issues -- ancillary services, pro forma tariffs, power pools, and ISOs -- and provided significant input to the Commission's formulation of this Final Rule. F. Need for Reform The many changes discussed above have converged to create a situation in which new generating capacity can be built and operated at prices substantially lower than many utilities' embedded costs of generation. As discussed above, new generation facilities can produce power on the grid at a cost of less than 3 cents per kWh to 5 cents per kWh, yet the costs for large plants constructed and installed over the last decade were typically in the range of 4 to 7 cents per kWh for coal plants and 9 to 15 cents for nuclear plants. Non-traditional generators are taking advantage of this opportunity to compete. Indeed, the non-traditional generators' share of total U.S. electricity generation increased from 4 103/ Attached to this Final Rule as Appendix B is a list of commenters and the abbreviations used to designate them, including those commenters that filed late. Docket Nos. RM95-8-000 - 49 - and RM94-7-001 percent in 1985 to 10 percent in 1993. 104/ Much of this increased share of generation is the result of competitive bidding for new generation resources that has occurred in 37 states. Since 1984, almost 4,000 projects, representing over 400,000 MW, have been offered in response to requests. Over 350 projects have been selected to supply 20,000 MW, and, of these, 126 are now online producing almost 7,800 MW of power. 105/ In addition, the cost of utility-generated electricity differs widely across the major regions of the United States. Average utility rates range from 3 to 5 cents in the Northwest to 9 to 11 cents in California. Electricity consumers are demanding access to lower cost supplies available in other regions of the United States, and access to the newer, lower cost generation resources. Therefore, it is important that the non-traditional generators of cheaper power be able to gain access to the transmission grid on a non-discriminatory open access basis. The Commission's goal is to ensure that customers have the benefits of competitively priced generation. However, we must do so without abandoning our traditional obligation to ensure that utilities have a fair opportunity to recover prudently incurred costs and that they maintain power supply reliability. As well, the benefits of competition should not come at the expense of 104/ Energy Information Administration, Performance Issues for a Changing Electric Power Industry (January 1995) 10 and (Figure 5). 105/ Current Competition, November 1994, Vol. 5, No. 8, at 8. Docket Nos. RM95-8-000 - 50 - and RM94-7-001 other customers. The Commission believes that requiring utilities to provide non-discriminatory open access transmission tariffs, while simultaneously resolving the extremely difficult issue of recovery of transition costs (discussed infra), is the key to reconciling these competing demands. Non-discriminatory open access to transmission services is critical to the full development of competitive wholesale generation markets and the lower consumer prices achievable through such competition. 106/ Transmitting utilities own the transportation system over which bulk power competition occurs and transmission service continues to be a natural monopoly. Denials of access (whether they are blatant or subtle), and the potential for future denials of access, require the Commission to revisit and reform its regulation of transmission in interstate commerce. As discussed in detail in Section IV.B., such action is required by the FPA's mandate that the Commission remedy undue discrimination. Since the time the NOPR issued, the Commission staff has completed an FEIS that provides a quantitative estimate of some of the cost savings expected from this Rule: approximately $3.8 to $5.4 billion per year. Other non-quantifiable benefits are also expected from this Rule and include: (1) better use of 106/ As discussed above, a significant number of public utilities still do not have any form of an "open access" tariff on file with the Commission and no public utility has on file a non-discriminatory open access tariff as defined by this Rule. Docket Nos. RM95-8-000 - 51 - and RM94-7-001 existing assets and institutions; (2) new market mechanisms; (3) technical innovation; and (4) less rate distortion. These potential benefits to the Nation's electricity consumers and the economy as a whole confirm the need to take generic action to remove barriers to competition. In what follows, we set out the changes necessary to remedy undue discrimination and to ensure a fair transition to a more competitive regulatory regime. IV. DISCUSSION A. Scope of the Rule 1. Introduction The Commission has determined that non-discriminatory open access transmission services (including access to transmission information) and stranded cost recovery are the most critical components of a successful transition to competitive wholesale electricity markets. These issues are the focal point of this Rule, the accompanying rule on open access same-time information systems, and the accompanying proposed rule on capacity reservation tariffs. In undertaking these initiatives, however, we are mindful that they are part of a broader picture of evolving issues affecting the electric industry and that other Commission policies will play an important role in ensuring the full development of competitive markets. Among the many issues that are important to competitive bulk power markets are: independent system operators (ISOs); regional transmission groups; generation market power; utility merger policy; and the development of Docket Nos. RM95-8-000 - 52 - and RM94-7-001 innovative transmission pricing alternatives, such as flow-based, distance-sensitive transmission pricing methodologies that reflect incremental costs. In particular, we believe that ISOs have great potential to assist us and the industry to help provide regional efficiencies, to facilitate economically efficient pricing, and, especially in the context of power pools, to remedy undue discrimination and mitigate market power. Although we discuss some of these issues in this Rule, we will further develop our policies in other proceedings as well to accommodate and encourage more efficient market structures. We now address the comments received on the scope of the proposed rulemaking. 2. Functional Unbundling In the NOPR, the Commission preliminarily found that functional unbundling of wholesale generation and transmission services is necessary to implement non-discriminatory open access transmission. 107/ At the same time, the Commission explained that the proposed rule would accommodate, but not require, corporate unbundling (which could include selling generation or transmission assets to a non-affiliate (divestiture) or the less aggressive step of establishing separate corporate affiliates to manage a utility's transmission and generation assets). However, we invited comments on functional unbundling and asked whether it is a strong enough 107/ FERC Stats. & Regs.  32,514 at 33,080. Docket Nos. RM95-8-000 - 53 - and RM94-7-001 measure to ensure non-discriminatory open access transmission without some form of corporate restructuring. Comments Commenters take both sides on whether functional unbundling is sufficient to assure non-discriminatory open access transmission or whether a stronger measure, such as corporate unbundling, is needed. Supporting functional unbundling Various commenters, including utilities and state commissions, generally support functional unbundling as sufficient to assure non-discriminatory open access transmission and oppose requiring corporate unbundling or divestiture. 108/ Several commenters state that functional unbundling will remedy discrimination without creating the inefficiencies and additional costs that corporate restructuring would create. 109/ A number of other commenters argue that the Commission has no authority under the FPA to require divestiture of transmission assets. 110/ Several of these commenters assert that, even 108/ E.g., Ohio Edison, UtiliCorp, Pennsylvania P&L, Atlantic City, Montana Power, IL Com, Seattle, OK Com, TX Industrials, MidAmerican, Southwestern, Southern, DOD, Public Service Co of CO, SC Public Service Authority, Florida Power Corp, DOE, WP&L, Com Ed, SBA, Consumers Power, CA Com, UT Com, Houston L&P, KCPL, EEI. 109/ E.g., Florida Power Corp, El Paso, PSNM, and SC Public Service Authority. 110/ E.g., Southwestern, PECO, El Paso, Florida Power Corp, NSP, Public Service E&G, MidAmerican. Docket Nos. RM95-8-000 - 54 - and RM94-7-001 if the Commission has the authority, the electric industry, unlike the natural gas industry, is not ready for mandated corporate unbundling because electric utilities still serve a high percentage of retail customers and own large amounts of the generating capacity. They assert that transmission system operation requires the operator to have control over much of the generating capacity. Various other commenters also support functional unbundling, but believe that safeguards are needed to make it work. 111/ Power Marketing Association, for example, suggests a number of safeguards: adoption of cost allocation mechanisms to ensure that utilities do not shift costs from generation to transmission; random audits of utility books; a requirement that each utility file a code of conduct that provides for maximum separation of generation and transmission functions; and active oversight and complaint procedures with strong penalties for abuse. OK Com and GA Com believe that functional unbundling along with the safeguard of the Commission's complaint process will provide sufficient incentive for non-discriminatory open access transmission. 111/ E.g., NRECA, IN Com, Power Marketing Association, TDU Systems, NorAm, Turlock, Texaco, Utility Shareholders, NSP, El Paso, Utility Investors Analysts, PECO, Florida Power Corp, UT Com, Sierra, Carolina P&L, SoCal Gas, OK Com, FL Com, Southern. Docket Nos. RM95-8-000 - 55 - and RM94-7-001 Supporting corporate unbundling A number of commenters see weaknesses in functional unbundling and argue that some form of corporate unbundling is necessary to assure non-discriminatory open access transmission. 112/ American Forest & Paper says that there is affiliate abuse in the gas industry and argues that the electric industry presents even more serious potential for abuse because it is still dominated by vertically integrated utilities. 113/ UAMPS asserts that functional unbundling is insufficient because the utility will still favor itself on issues related to transmission planning, capital investment, and operation and maintenance and replacement costs. NIEP argues that divestiture of generation assets from transmission and distribution is the preferred mechanism for mitigating market power. It further suggests that if corporate divestiture is not feasible the Commission should seek to achieve "virtual divestiture" by requiring that the utility generation function be separated from transmission and distribution functions in a separate corporate affiliate, or business unit, and that affiliate transaction rules be established to guard against possible abuses. [114/] 112/ E.g., American Forest & Power, American National Power, ND Com, IL Com, UAMPS, NIEP, APPA, Public Power Council, Municipal Energy Agency Nebraska, Missouri Basin MPA, Texaco, Direct Services Industries, Calpine, CCEM, Wisconsin Coalition, VT DPS. 113/ See also American National Power, ND Com, Calpine. 114/ NIEP Initial Comments at 4. Docket Nos. RM95-8-000 - 56 - and RM94-7-001 It maintains that the Commission has broad authority to protect against undue discrimination and anticompetitive behavior and can order divestiture if such action is required to remedy such behavior. 115/ FTC and DOJ argue that operational unbundling, an example of which is the formation of an independent system operator (ISO), likely would be more effective than functional unbundling and less costly than industry-wide divestiture. 116/ FTC describes operational unbundling as "structural institutional arrangements, short of divestiture, that would separate operation of the transmission grid and access to it from economic interests in generation." It gives as an example the California proposal under which utilities would continue to own transmission lines, but an independent system operator would have operational control. DOJ also suggests "a separate authority" to manage the grid and access to the grid, joint ventures, and voluntary pooling arrangements. These commenters argue that operational unbundling would be easier to enforce than functional unbundling. DOE states that separation of the control of transmission from vertically-integrated companies does not necessarily require a poolco or any particular market mechanism. It suggests the possibility of an ISO that is functionally separate from any 115/ See also Municipal Energy Agency Nebraska, Direct Services Industries. 116/ Others oppose operational unbundling. See, e.g., Carolina P&L, Salt River. Docket Nos. RM95-8-000 - 57 - and RM94-7-001 buyer or seller of generation, but would not perform all the functions of a poolco. United Illuminating supports "operational unbundling" that would either (1) eliminate vertical integration and divestiture of transmission assets, leading to the formation of a regional transmission company, or (2) develop a regional contractual approach to transmission services that eliminates the transmission owner's market power and fairly allocates support of the transmission facilities between native load and third-party users of the system. Commission Conclusion We conclude that functional unbundling of wholesale services is necessary to implement non-discriminatory open access transmission and that corporate unbundling should not now be required. As we explained in the NOPR, functional unbundling means three things: (1) a public utility must take transmission services (including ancillary services) for all of its new wholesale sales and purchases of energy under the same tariff of general applicability as do others; (2) a public utility must state separate rates for wholesale generation, transmission, and ancillary services; (3) a public utility must rely on the same electronic information network that its transmission customers rely on to obtain information about its transmission system when buying or selling power. Docket Nos. RM95-8-000 - 58 - and RM94-7-001 We believe that these requirements are necessary to ensure that public utilities provide non-discriminatory service. 117/ These requirements also will give public utilities an incentive to file fair and efficient rates, terms, and conditions, since they will be subject to those same rates, terms, and conditions. However, we recognize that additional safeguards are necessary to protect against market power abuses. Functional unbundling will work only if a strong code of conduct (including a requirement to separate employees involved in transmission functions from those involved in wholesale power merchant functions) is in place. In the RINs NOPR, the Commission proposed a code of conduct that would apply to all public utility transmission providers. As the Commission explained, [t]his code of conduct would require, among other matters, a separation of the utilities' transmission system operations and wholesale marketing functions, and would define permissible and impermissible contacts between employees that conduct wholesale generation marketing functions and employees that handle transmission system operations and reliability in the system control center or at other facilities or locations. 118/ 117/ When and how functional unbundling is to be achieved for requirements transactions and for various types of coordination arrangements, including power pools, is discussed at Sections IV.A.5 and IV.F. Functional unbundling of ancillary services is discussed in Section IV.D. 118/ Real-Time Information Networks and Standards of Conduct, Notice of Proposed Rulemaking, 60 FR 66182 (December 21, 1995), FERC Stats. & Regs., Proposed Regulations  32,516 at 33,170 (1995). Docket Nos. RM95-8-000 - 59 - and RM94-7-001 Adoption of this code of conduct, discussed in detail in the accompanying final rule on OASIS, 119/ is needed to ensure that the transmission owner's wholesale marketing personnel and the transmission customer's marketing personnel have comparable access to information about the transmission system. As noted by OK Com and GA Com, a further safeguard -- section 206 -- is available if a public utility seeks to circumvent the functional unbundling requirements. Under section 206, any person is free to file a complaint with the Commission detailing any alleged misbehavior on the part of the public utility or its affiliates concerning matters subject to our jurisdiction under the FPA. Similarly, the Commission may, on its own motion, initiate a proceeding to investigate the practices of the public utility and its affiliates. We believe 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, we are not prepared to adopt a more intrusive and potentially more costly mechanism -- corporate unbundling -- at this time. Several commenters discuss the need to encourage or even to require ISOs in the context of functional unbundling. We believe that ISOs have the potential to provide significant benefits 119/ The final rule on information systems no longer uses the terminology RINs. The new terminology used is OASIS -- Open Access Same-time Information System -- which we will use in this Final Rule. Docket Nos. RM95-8-000 - 60 - and RM94-7-001 (e.g., to help provide regional efficiencies, to facilitate economically efficient pricing, and, especially in the context of power pools, to remedy undue discrimination and mitigate market power) and will further our goal of achieving a workably competitive market. As we learned at our technical conference on power pools, many utilities are examining ISOs and corporate unbundling in various shapes and forms, particularly in the context of power pools. We discuss ISOs extensively in our section on power pools where we believe they will have an important role to play. However, in the context of individual utility transactions, we believe that the less intrusive functional unbundling approach outlined above is all that we must require at this time. Nevertheless, we see many benefits in ISOs, and encourage utilities to consider ISOs as a tool to meet the demands of the competitive marketplace. As a further precaution against discriminatory behavior, we will continue to monitor electricity markets to ensure that functional unbundling adequately protects transmission customers. At the same time, we will analyze all alternative proposals, including formation of ISOs, and, if it becomes apparent that functional unbundling is inadequate or unworkable in assuring non-discriminatory open access transmission, we will reevaluate our position and decide whether other mechanisms, such as ISOs, should be required. Finally, while we are not now requiring any form of corporate unbundling, we again encourage utilities to explore Docket Nos. RM95-8-000 - 61 - and RM94-7-001 whether corporate unbundling or other restructuring mechanisms may be appropriate in particular circumstances. Thus, we intend to accommodate other mechanisms that public utilities may submit, including voluntary corporate restructurings (e.g., ISOs, separate corporate divisions, divestiture, poolcos), to ensure that open access transmission occurs on a non-discriminatory basis. We also will continue to monitor -- and stand ready to work with parties engaging in -- innovative restructuring proposals occurring around the country. 3. Market-based Rates a. Market-based Rates for New Generation In the NOPR, the Commission proposed to codify its determination in Kansas City Power & Light Company 120/ that the generation dominance standard for market-based sales from new capacity be dropped. 121/ The proposed new section 35.27 would provide: Notwithstanding any other requirements, any public utility seeking authorization to engage in sales for resale of electric energy at market-based rates shall not be required to demonstrate any lack of market power in generation with respect to sales from capacity first placed in service on or after [INSERT DATE 30 DAYS AFTER THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER]. [122/] 120/ 67 FERC  61,183 at 61,557 (1994), reh'g pending (KCP&L). 121/ FERC Stats. & Regs.  32,514 at 33,050. 122/ Id. at 33,154. Docket Nos. RM95-8-000 - 62 - and RM94-7-001 However, this proposal would not affect the Commission's continuing authority to look at whether an applicant and its affiliates could erect other barriers to entry and whether there may be affiliate abuse or reciprocal dealing. 123/ Comments A number of commenters support the Commission's determination in KCP&L 124/ and several of them explicitly support the Commission's proposed codification. 125/ EEI asserts that more than 50 percent of new generation is from non- utility sources and that recent competitive solicitations for new capacity have been greatly over-subscribed. Entergy argues that there is no evidence in any proceeding thus far of a market power problem in long-run markets. Other commenters, however, oppose codifying KCP&L. 126/ They believe that market power in long-run markets exists for both new and old generation due to, for example, constraints on interface capabilities and unduly long notice periods for replacement of purchases. They argue that there is not enough of a distinction between new and old generation to treat them differently. TDU Systems also notes that the Commission in KCP&L 123/ 67 FERC at 61,557. 124/ E.g., Entergy, EEI, Atlantic City, Duke Centerior, Houston L&P, Montana-Dakota Utilities, Canadian Petroleum Producers, DOE, Florida Power Corp, PSNM. 125/ E.g., EEI, Centerior, Houston L&P, NYSEG. 126/ E.g., TDU Systems, ELCON, NRECA, Environmental Action, NIEP, APPA, Power Marketing Association, EGA. Docket Nos. RM95-8-000 - 63 - and RM94-7-001 did not take into account the differences between firm and non- firm bulk power. NIEP and ELCON conclude that the Commission erroneously found in KCP&L that no wholesale seller of generation has market power in generation from new facilities. NIEP asserts that in each service area there is usually only one wholesale buyer -- the utility -- who also is virtually always a wholesale seller of generation. Under these circumstances, NIEP argues that there cannot be arm's-length bargaining. Environmental Action complains that the Commission's proposal to codify KCP&L ignores significant factors that impede entry to generation markets, such as utility resistance to purchased power, state government-created barriers to non-utility generation, pancaking of rates under the contract path approach, sunk investment, and scale economies. Commission Conclusion In reviewing applications to sell at market-based rates, whether from new (unbuilt) capacity or existing capacity, we require that the seller (and each of its affiliates) must not have, or must have mitigated, market power in generation and transmission and not control other barriers to entry. In order to demonstrate the requisite absence or mitigation of transmission market power, a transmission-owning public utility seeking to sell at market-based rates must have on file with the Commission an open access transmission tariff for the provision of comparable service. In addition, the Commission considers Docket Nos. RM95-8-000 - 64 - and RM94-7-001 whether there is evidence of affiliate abuse or reciprocal dealing. 127/ In KCP&L, we stated that "in light of industry and statutory changes which allow ease of market entry, we therefore will no longer require rate applicants to submit evidence of generation dominance in long-run bulk power markets." 128/ We further explained that we had examined "generation dominance in many different cases over the years" and had "yet to find an instance of generation dominance in long-run bulk power markets." 129/ Commenters have criticized our findings in KCP&L, but no commenter has provided any evidence of generation dominance in long-run bulk power markets. Moreover, we have seen no such evidence in any of the market-based rate cases we have considered since KCP&L. Based on the comments received, we will codify the Commission's determination in KCP&L that the generation dominance standard for market-based sales from new capacity should be dropped. Because the Commission's findings in KCP&L applied to long-run markets, we will revise proposed section 35.27 to apply 127/ See, e.g., MidAmerican Energy Company, 74 FERC  61,211 (1996). 128/ KCP&L, 67 FERC at 61,557. See also discussion in proposed rule, FERC Stats. & Regs. at 33,067-68. 129/ Id. Docket Nos. RM95-8-000 - 65 - and RM94-7-001 to sales from capacity for which construction has commenced on or after the effective date of this Rule. 130/ The Commission wishes to clarify 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. In other words, the fact that an applicant need not demonstrate its lack of generation dominance with respect to new capacity cannot be used to "bootstrap" the authorization of market-based rates for its existing capacity. Moreover, our evaluation of market-based rates for existing capacity will include consideration of new capacity. In addition, the fact that we are codifying KCP&L does not mean that we will ignore specific evidence presented by an intervenor that a seller requesting market-based rates for sales from new generation nevertheless possesses generation dominance. For example, if the evidence indicated that the new generator, due to its proximity to an existing transmission constraint, could significantly influence the ability to move power across the constraint, we would consider such evidence in determining 130/ The NOPR's proposed language that a public utility would not have to demonstrate a lack of market power in generation for sales from capacity first placed in service on or after the date 30 days after the final rule is published in the Federal Register does not properly reflect the finding in KCP&L. Because KCP&L addressed new or unbuilt generation, the proposed language is being revised as indicated above and as set forth in the regulatory text included with this Final Rule. Docket Nos. RM95-8-000 - 66 - and RM94-7-001 whether to grant the applicant's request. 131/ If such evidence is presented, the Commission will evaluate whether the evidence disproves the premise that the seller lacks generation dominance with respect to its new capacity. If the applicant has existing generation, the sales from which are authorized to be made on a market basis, the Commission would consider whether the new generation (when added to the existing generation with market-based authority) results in the applicant having generation dominance. On the other hand, if the applicant has existing generation, the sales from which are subject to cost-of-service regulation, the Commission would not include this generation in its analysis of the applicant's request for market-based rates for its new generation. The question of whether or not the applicant lacks generation dominance with respect to its existing capacity is relevant only if, and when, the seller applies to the Commission for authority to make wholesale sales for its existing capacity at market-based rates. If evidence regarding an applicant's generation dominance with respect to its new capacity is submitted, the applicant would be required to provide a satisfactory rebuttal. b. Market-based Rates for Existing Generation In the NOPR, the Commission explained that increased competition resulting from open access transmission may reduce or 131/ Cf. Wisconsin Electric Power Company, et al., 74 FERC  61,069 at 61,193 (1996). Docket Nos. RM95-8-000 - 67 - and RM94-7-001 even eliminate generation-related market power in the short-run market (sales from existing capacity). 132/ Because market power has been the primary concern of the Commission in analyzing requests for market-based rates for such sales, we sought comments on the effect of industry-wide non-discriminatory open access on our criteria for authorizing power sales at market- based rates. The Commission also sought comments on whether the generation dominance standard should be dropped for market-based sales from existing capacity. Comments Many commenters support, but many also oppose, market-based rates for existing generation without a case-specific analysis of generation dominance. Supporting market-based rates for existing generation. Many commenters (primarily IOUs and a number of state commissions) assert that existing generators will not possess market power after implementation of non-discriminatory open access transmission and that market-based rates should be permitted generically for sales from existing generation. 133/ 132/ FERC Stats. & Regs.  32,514 at 33,093-94. 133/ E.g., EEI, CINergy, Central Illinois Public Service, Citizens Utilities, Com Ed, Ohio Edison, Allegheny, Southern, Portland, NRRI, Pennsylvania P&L, PECO, Dayton P&L, Utilities For Improved Transition, Centerior, Houston L&P, Duke, ConEd, IPALCO, Salt River, PJM, NU, NYSEG, Oklahoma G&E, PA Com, OK Com, CT DPUC, CA Com, MT Com. Docket Nos. RM95-8-000 - 68 - and RM94-7-001 EEI asserts that market power concerns generally would be transitory, limited to the time needed to build new facilities. Thus, it recommends that all markets be declared competitive by a date certain and that market-based rates then be allowed, with customers permitted to file complaints. Florida Power Corp believes that existing procedures under sections 205 and 206 will adequately protect consumers. Other commenters also urge the Commission to eliminate its generation dominance standard, but assert that the Commission should allow a showing of market dominance in a complaint or show cause proceeding. 134/ CT DPUC notes that the Commission should be able to rely on rules of conduct, market mechanisms, and monitoring to curb any market power that may exist. Utilities For Improved Transition argues that if utilities cannot get market-based rates, the new players in the market will have an unfair advantage, since they do not have to carry the traditional utilities' burden of older, less efficient plants. Entergy proposes a screening test that would permit the Commission to "deregulate" wholesale sales to certain short-run markets. CINergy recommends that after industry-wide open access tariffs become effective, the Commission adopt a rebuttable presumption that all markets are workably competitive; that 134/ E.g., Consumers Power, Portland, Dayton P&L, CSW. Docket Nos. RM95-8-000 - 69 - and RM94-7-001 presumption could be rebutted in a section 206 proceeding. 135/ UtiliCorp, while it believes that market power will probably be fully mitigated by open access, also argues that the Commission should examine generation dominance on a region-by- region basis. 136/ Montana-Dakota Utilities argues that the Commission should allow all suppliers in a power pool or RTG to have market-based rates after a Commission finding that there is sufficient generation competition within the region. Duke states that it would be highly inconsistent for the Commission to require open access, but not allow utilities to compete in the market. It further states that the relevant market should be determined using standard antitrust techniques; the Commission should examine the options available to customers and determine whether the utility possesses monopoly power in a relevant market. Opposing market-based rates for existing generation Many commenters are concerned that even with open access tariffs certain generators will be able to exercise market dominance. 137/ For example, NARUC argues that utilities 135/ See also Citizens Utilities. 136/ See also CSW, Industrial Energy Applications, Public Service Co of CO, Coalition for Economic Competition. 137/ E.g., NRECA, TDU Systems, MT Com, SMUD, NEPCO, Orange & Rockland, El Paso, American Forest & Paper, NIPSCO, AEC & SMEPA, OH Com, IL Com, IN Com, Legal Environmental Assistance, LG&E, Cajun, Industrial Energy Applications, (continued...) Docket Nos. RM95-8-000 - 70 - and RM94-7-001 retain market power through their ownership of existing generation and transmission facilities, favorable long-term contracts for fuel and other inputs, and access to superior generation sites. 138/ NRECA believes that the universe of generation providers is still too narrow to assume a competitive market and that other factors, such as transmission constraints and pancaking of rates, will inhibit the development of competitive markets. 139/ FTC says that, although comparable transmission access could broaden the relevant geographic market for generation, the Commission should not assume that there will be no market power. It says that the Commission must continue to evaluate each case. 140/ TDU Systems argues that the Commission cannot move to market-based rates without a Congressional determination that deregulation of wholesale electric rates should be implemented. It further asserts that 137/(...continued) LEPA, MA DPU, MI Com, FTC, Minnesota P&L, SC Public Service Authority, WP&L, NARUC, Canadian Petroleum Producers, DOD, CCEM, Environmental Action, American Wind, Cajun, NIEP, EGA, TAPS, ELCON, Consolidated Natural Gas. 138/ See also NIEP, Pacificorp, CA Energy Com. 139/ See also MT Com, TDU Systems, Soyland. 140/ See also AEC & SMEPA, NIPSCO, El Paso (discusses a particular transmission constraint that it states limits its access to suppliers). NRECA is also concerned that mergers may create a handful of "mega-public utilities" that may affect a regional generation market and that the Commission should apply more traditional antitrust principles in analyzing the impacts of mergers. Docket Nos. RM95-8-000 - 71 - and RM94-7-001 the Commission does not have a factual basis for a reasoned conclusion that regulated utilities do not have market dominance -- full open access is only a goal at this time, and the success of open access will depend upon the transmission rate structures the Commission approves. LEPA raises concerns that the small bulk power suppliers, QFs, co-generators, EWGs, IPPs, and marketers (who provide non- requirements power) may not be able to bring competition to the wholesale market. LEPA concludes that "barriers will exist unless buyers have full access to requirements power itself, rather than just to the chance to acquire the individual components of requirements power." 141/ TDU Systems raises concerns about the limited number of generation providers and the effect of possible future mergers. It also argues that pancaked rates raise the cost of transmission to third parties, thereby restricting the geographic scope of markets. As a result, TDU Systems asserts that individual generators in highly concentrated regions will still be able to exert market power. OH Com expresses concerns that restrictions on siting of generation and transmission will favor nearby generators. SC Public Service Authority argues that if the Commission allows utilities to recover stranded costs their market power will not be mitigated, 141/ LEPA Initial Comments Affidavit of William G. Shepherd at 4. Docket Nos. RM95-8-000 - 72 - and RM94-7-001 since customers will have to pay exit fees to switch suppliers. 142/ CCEM notes that in Order No. 636 gas pipelines were not allowed market-based rates for merchant sales until after transmission had been completely unbundled and non-discriminatory open access had been fully implemented. DOE and DOJ assert that open access should not be assumed to mitigate market power sufficiently to justify deregulation of existing generation -- structural changes, such as control of the regional grid by an independent entity, are required. DOE requests that the Commission continue to look for affiliate abuse when reviewing market-based rates for new generation. Similarly, EPA is concerned that even with open access, individual generators may still exert market power by their domination of a particular geographic market. It is also concerned that low-cost plants that are subject to weaker environmental standards could have a market advantage. NEPOOL Review Committee requests that the Commission not approve any market prices "where the market into which the seller proposes to sell is not effectively competitive due to the absence of regional transmission products and prices." 143/ 142/ See also DOD and WP&L. IL Com suggests that the Commission allow market-based rates to a utility on the condition that the utility forego stranded cost recovery. 143/ NEPOOL Review Committee Initial Comments at 28. Docket Nos. RM95-8-000 - 73 - and RM94-7-001 Commission Conclusion While the Commission expects this Rule to facilitate the development of competitive bulk power markets, we find 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. We continue to have concerns about how to define the relevant markets and believe that a more rigorous analysis is needed than can be achieved with the limited market data that is now available. We will continue our case-by-case approach that allows market-based rates based on an analysis of generation market power in first tier and second tier markets. 144/ In particular cases, however, the effect of the mandatory open access prescribed by this Final Rule may lead to the consideration of geographic markets for the applicant's generation products that are broader in scope than the first-tier and second-tier markets currently considered. 145/ By the same token, in some cases, evidence of the effects of 144/ See, e.g., Southwestern Public Service Company, 72 FERC  61,208 at 61,996 (1995). 145/ The Commission's practice is to define the relevant markets as those utilities directly interconnected to the applicant (first-tier markets). For each first-tier market, we consider all utilities interconnected to the first-tier utility and all utilities interconnected to the applicant as competitors in that relevant market. Thus, the competitors include the second-tier utilities directly interconnected to the relevant market and those other first-tier utilities that can reach the market by virtue of the applicant's open access transmission tariff. See, e.g., Kansas City Power & Light Company, 67 FERC  61,183 at 61,556; and Heartland Energy Services, Inc., 68 FERC  61,223 at 62,061. Docket Nos. RM95-8-000 - 74 - and RM94-7-001 transmission constraints may circumscribe the scope of the relevant geographic market for the applicant's generation products. While we will continue to apply the first-tier/second-tier analysis, we 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. Thus, for instance, applicants may present evidence that the relevant market is in fact broader than the first or second tier. In support of such a contention, an applicant would need to show more than the existence of open access. For example, an applicant might attempt to demonstrate the lack of significant transmission constraints in the more broadly defined market and that cumulative transmission rates would not significantly affect the ability of more distant suppliers to compete in the relevant market. Similarly, an intervenor may present evidence that, due to the existence of significant transmission constraints within the first- and second-tier markets, the relevant market is in fact more limited in scope. 146/ Finally, we will maintain our current practice of allowing market-based rates for existing generation to go into effect subject to refund. To the extent that either the applicant or intervenors in individual cases offer specific evidence that the 146/ See Wisconsin Public Service Corporation, 75 FERC  61,___, slip op. at 6-7 (1996). Docket Nos. RM95-8-000 - 75 - and RM94-7-001 relevant geographic market ought to be defined differently than under the existing test, we will examine such arguments through formal or paper hearings. Because our goal is to develop more competitive bulk power markets, we will continue to monitor markets to assess the competitiveness of the market in existing generation, and we will modify our market rate criteria if and when appropriate. However, any changes we might make to our analysis for authorizing market-based rates in the future will not upset transactions entered into pursuant to existing market-based rate authority. The policies we put in place today to develop a smoothly functioning transmission access regime will provide useful experience and information for assessing the effects of generation concentration. 4. Merger Policy In the NOPR, the Commission did not address possible ramifications of the NOPR with regard to its existing merger policy. Comments A number of commenters suggest that the Commission should reevaluate its merger policy in light of the NOPR. 147/ They further suggest a number of changes that they believe need to be made to the Commission's existing merger policy. 147/ E.g., NRECA, TAPS, Wisconsin Coalition, APPA. Docket Nos. RM95-8-000 - 76 - and RM94-7-001 Most commenters raising this issue express concerns that mergers will lessen competition and hinder achievement of competitive bulk power markets. 148/ For example, NRECA indicates that the Commission's merger policy is at a crossroads. It believes that it is essential for the Commission to reevaluate its merger policy in concert with the proposed rulemakings. 149/ Similarly, TAPS recommends that the Commission reevaluate its merger criteria to ensure that in a more competitive era, mergers are found to be consistent with the public interest only if they are pro-competitive. Several commenters argue that the Commission should continue to conduct a case-by-case investigation of the product and geographic markets that will be affected by a proposed merger. 150/ A number of commenters also suggest certain changes that they would like to see in the Commission's merger policy. 151/ APPA recommends that, at a minimum, all merger approvals considered by the Commission should be conditioned on: (1) filing an open access transmission tariff, (2) demonstrating no market power in generation or ancillary services, and (3) granting all existing requirements customers of the merged entity the right to convert existing contracts to rights to equivalent 148/ E.g., Wisconsin, Rosebud, NRECA, IN Com, Wisconsin Coalition, NIEP, Minnesota P&L, APPA. 149/ See also APPA. 150/ E.g., Wisconsin Coalition, MMWEC. 151/ E.g., APPA, Wisconsin Coalition, Minnesota P&L, IN Com. Docket Nos. RM95-8-000 - 77 - and RM94-7-001 transmission capacity. Several commenters suggest adopting the U.S. Department of Justice Merger Guidelines in analyzing merger proposals. 152/ Environmental Action and others contend that merging utilities must be required to demonstrate real net benefits to retail and wholesale customers that could not otherwise be achieved but for the proposed merger. 153/ Commenters also argue that the Commission should use its merger conditioning authority to order divestiture of transmission and generation when required to ensure competition. 154/ Environmental Action and NEPOOL Review Committee suggest conditioning merger applications on the existence of regional transmission pricing arrangements to mitigate any generation market power gained by the merging entities. Commission Conclusion The Commission appreciates the concerns and suggestions raised with respect to our merger policy. However, since the time the NOPR was issued (and comments received thereon), we issued a Notice of Inquiry on the Commission's merger policy in Docket No. RM96-6-000. 155/ There we indicated that we will review whether our criteria and policies for evaluating mergers 152/ E.g., Wisconsin Coalition. 153/ E.g., TAPS, Wisconsin Coalition. 154/ E.g., NIEP, Wisconsin Coalition, TAPS, Environmental Action. 155/ FERC Stats. & Regs.  35,531 (1996). Docket Nos. RM95-8-000 - 78 - and RM94-7-001 need to be modified in light of the changing circumstances, including this final rule, that are occurring in the electric industry. The NOI proceeding will permit us to consider comments from all interested participants and, at the same time, allow us to review our merger criteria and policies in light of this final rule. We are committed to reviewing our merger policy in a timely manner in the ongoing NOI proceeding. 156/ 5. Contract Reform In the NOPR, the Commission explained that it believed that it could remedy unduly discriminatory practices and achieve more competitive bulk power markets without abrogating existing wholesale power supply contracts that bundle generation and transmission services and existing wholesale transmission contracts. 157/ Thus, we proposed to apply the functional unbundling requirement only to transmission services under new requirements contracts, new coordination contracts, and new transactions under existing coordination contracts. However, the Commission did invite comment on whether it would be contrary to the public interest to allow all or some of the above types of existing contracts to remain in effect. 156/ Our decision to review our merger policy in a separate NOI proceeding is not intended to affect a utility's business decision of whether a merger may be in the economic interest of its ratepayers and stockholders. The NOI proceeding will not prevent us from reviewing merger applications in as timely a manner as possible. 157/ FERC Stats. & Regs.  32,514 at 33,093. Docket Nos. RM95-8-000 - 79 - and RM94-7-001 Comments Requirements and Transmission Contracts Many of the commenters (including utility customers and third-party power suppliers) addressing this issue oppose abrogating existing contracts on a generic basis. 158/ A number of the commenters contend that existing contracts should be retained because they are the result of mutually beneficial bargaining. 159/ SMUD and TANC are concerned that existing contracts providing for transmission service that is superior to the pro forma tariffs not be abrogated. 160/ Ohio Edison argues that existing contracts have contributed to the emergence of competition, meet the specific needs of the parties, have been approved by the Commission, and have not been found to be unduly discriminatory or violative of the public interest, and that their preservation is consistent with the Energy Policy Act, most notably amended section 211 of the FPA. PacifiCorp and AEP express concern that contract abrogation would create competitive instability. American Forest & Paper argues that the Commission 158/ E.g., Dayton P&L, NSP, Montaup, Southwestern, Ohio Edison, Consumers Power, Allegheny, Public Generating Pool, NEPCO, Pennsylvania P&L, Southwest TDU Group, Arizona, DOD, El Paso, Florida Power Corp, AEC & SMEPA, Atlantic City, Texaco, Tampa, CSW, Central Illinois Public Service, CA Cogen, ConEd, GA Com, Consolidated Natural Gas, Ohio Valley, Pacific Northwest Coop, Salt River, Oglethorpe, Minnesota P&L, NYSEG, Brazos, Southern, Washington Water Power, CINergy, SoCal Edison, Hoosier EC. 159/ E.g., AEC & SMEPA, Cajun, Carolina P&L, NSP, Pennsylvania P&L, UNITIL, Southwestern, CSW. 160/ See also Dairyland, DE Muni, Arkansas Cities, Ohio Valley. Docket Nos. RM95-8-000 - 80 - and RM94-7-001 cannot refuse to honor existing contracts if it expects a competitive bulk power market to emerge. Numerous commenters further argue that contract abrogation requires a fact-based, contract-specific evaluation, and they oppose any generic declaration that existing contracts are contrary to the public interest. 161/ Some suggest that generic contract abrogation cannot be justified under the public interest standard. 162/ Missouri Basin MPA argues that the Commission should allow abrogation of existing wholesale power and transmission arrangements if the customer can demonstrate the undue competitive disadvantage caused by the arrangement. A few commenters support some form of generic contract abrogation. 163/ CCEM asserts that existing wholesale requirements customers must be given the right to convert to transmission service under non-discriminatory open access 161/ E.g., AEP, Associated EC, DOD, El Paso, NEPCO, Ohio Edison, PSNM, Southwest TDU Group, Utilities For Improved Transition, NYSEG, Citizens Utilities, NM Com, EGA. See also NRECA, TDU Systems, Blue Ridge, CCEM, Industrial Energy Applications, APPA, Cajun, Springfield, DE Muni, Missouri Basin MPA, TANC, Wolverine Coop Members, FL Com, Citizens Utilities, Soyland (support contract abrogation on a case- by-case basis). 162/ E.g., Utilities For Improved Transition, NSP, Southwestern, DE Muni. 163/ E.g., NRECA, CCEM, ELCON, DE Muni, Oglethorpe. Portland maintains that it would be in the public interest to abrogate existing contracts completely, but recommends that such action be taken only on a case-by-case basis. Docket Nos. RM95-8-000 - 81 - and RM94-7-001 tariffs. 164/ CCEM notes that this is the same relief from undue discrimination that the Commission afforded to pipeline customers in Order Nos. 436 and 500. 165/ CCEM emphasizes that here, in contrast to what occurred in the gas industry, "[c]onversion rights should be understood as the logical quid pro quo for introducing extra-contractual stranded-cost recovery rights into the wholesale requirements contracts of electric utilities." 166/ NRECA asserts that it would be unduly discriminatory to allow new transmission customers to use the open access transmission tariffs, but not allow existing customers the same access. 167/ TAPS says that if those who now have discriminatory contracts are forced to live with those contracts, a fully competitive market will be delayed considerably. 168/ Moreover, TAPS argues, the Commission has a statutory duty to remedy the undue discrimination that it is only now recognizing. Even if the Commission will not abrogate these contracts across 164/ See also VT DPS, NYMEX. 165/ See also VT DPS, Portland. 166/ CCEM Initial Comments at 26. See also ELCON, VT DPS, Blue Ridge, NYMEX, OK Com, Missouri Basin MPA, Texas-New Mexico, TDU Systems. 167/ See also TDU Systems, Texas-New Mexico, TAPS, Wisconsin Municipals. 168/ See also NorAm. UtiliCorp argues that existing contracts should not be allowed to extend indefinitely (as through "evergreen" clauses) without adopting comparability. See also Texaco, Wisconsin Municipals, Phelps Dodge. Docket Nos. RM95-8-000 - 82 - and RM94-7-001 the board, TAPS asserts that we should use our section 206 authority to do so on a contract-by-contract basis. San Francisco requests that the Commission clarify that a holder of capacity rights under an existing contract can extend contractual rights to transmission access at least coterminous with the life of the project and under a roll-over or renewal contract on the same basis as provided in the existing contract. Anoka EC proposes that when a wholesale purchaser's contract expires, it should have a right of first refusal to contract for the transmission capacity to which it previously had a right. Knoxville urges the Commission to require renegotiation of the notice and/or term of all existing contracts for which the voluntary termination period exceeds the time frame for implementation of the final rule. NEPCO suggests that we require existing power contracts that allow rate changes to be separated into their generation and transmission components, without otherwise disturbing their terms; this would allow comparisons between the transmission service the utility provides to its power customers and the service it offers to others. 169/ Coordination Agreements CINergy argues that coordination agreements should not be excluded from the comparability standard and that the Commission should use its authority under section 206 to require amendments 169/ See also Industrial Energy Applications. Docket Nos. RM95-8-000 - 83 - and RM94-7-001 to such agreements, just as it did in Order 636 in requiring unbundling of pipeline supply contracts. CINergy suggests that public utilities should be given up to three years to file the amendments to avoid hardship on the industry and the Commission's staff. CINergy further asserts that future transactions conducted under coordination agreements should be unbundled and the transmission component subjected to the comparable transmission service requirement. Others argue that purchases under existing coordination agreements made on behalf of retail native load should not be unbundled. 170/ NY Com and IL Com recommend that proposed section 35.28(c) be modified to state that the functional unbundling requirement "exclude[s] those wholesale purchases made by the utility to serve existing or expected native retail load." Utilities For Improved Transition disagrees with the idea that new transactions under existing coordination agreements should be subject to the rule. 171/ It argues that the sanctity of coordination contracts should be the same as for other contracts. Coordination contracts are not simply agreements to agree in the future, according to Utilities For Improved Transition; they set forth terms and rates and merely leave the timing of transactions to be resolved in the future. Moreover, it argues that the Commission has given no reason to 170/ E.g., Con Ed, Detroit Edison, IL Com. 171/ See also Utility Workers Union, VEPCO. Docket Nos. RM95-8-000 - 84 - and RM94-7-001 abandon its practice of encouraging coordination sales by allowing price flexibility. Commission Conclusion Requirements and Transmission Contracts We do not believe it is appropriate to order generic abrogation of existing requirements and transmission contracts. While the Commission did generically find it appropriate to modify natural gas contracts to complete the move to a competitive commodity market in natural gas, we face a different situation here. 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. 172/ In other words, there was a market failure in the industry that required the extraordinary measure of generically allowing all customers to break their contracts with pipelines. In contrast, there is no such market failure in the electric industry. Although changes in the industry have been and continue to be dramatic, we do not believe they compel generic abrogation of requirements and transmission contracts. 173/ 172/ See Pierce, Richard J., Reconstituting the Natural Gas Industry from Wellhead to Burnertip, 9 Energy L.J. 1 (1988). 173/ In addition, we do not believe that unfavorable requirements contracts will derail the attainment of competitive wholesale power markets. Indeed, many of the commenters support this position and seek to retain their existing requirements contracts. Docket Nos. RM95-8-000 - 85 - and RM94-7-001 While we have concluded that current conditions in the wholesale power market do not warrant the generic modification of requirements contracts, we conclude nonetheless that the modification of certain requirements contracts on a case-by-case basis may be appropriate. We conclude further that, even if customers under such contracts are bound by so-called Mobile- Sierra clauses, they nonetheless ought to have the opportunity to demonstrate that their contracts no longer are just and reasonable. The Commission finds that it would be against the public interest to permit a Mobile-Sierra clause in an existing wholesale requirements contract to preclude the parties to such a contract from the opportunity to realize the benefits of the competitive wholesale power markets. For purposes of this finding, the Commission defines existing requirements contracts as contracts executed on or before July 11, 1994. 174/ By operation of this finding, 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. 174/ This is consistent with the definition of existing requirements contracts we have used for purposes of stranded cost recovery. Docket Nos. RM95-8-000 - 86 - and RM94-7-001 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 this Rule. 175/ The Commission's complementary Mobile-Sierra findings are not mutually exclusive. Any contract modification approved under this Section shall provide for the utility's recovery of any costs stranded consistent with the contract modification. The stranded costs must be prudently incurred, legitimate and verifiable, as provided in Section IV.J. Further, the Commission has 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. The Commission believes that the most productive way to analyze contract modification issues is to consider simultaneously both the selling public utility's claims, if any, that it had a reasonable expectation of continuing to serve the customer beyond the term of the contract and the customer's claim, if any, that the contract no longer is just and reasonable and therefore ought to be modified. Thus, if the selling public utility intends to claim stranded costs, it must present that 175/ See Section IV.J.5. Docket Nos. RM95-8-000 - 87 - and RM94-7-001 claim in any section 206 proceeding brought by the customer to shorten or terminate the contract. Similarly, if the customer intends to claim that the notice or termination provision of its existing requirements contract is unjust and unreasonable, it must present that claim in any proceeding brought by the selling public utility to seek recovery of stranded costs. This will promote administrative efficiency and will permit the Commission to consider how the contracting parties' claims bear on one another. The Commission does not take contract modification lightly. Whether a utility is seeking a contract amendment to permit stranded cost recovery based on expectations beyond the stated term of the contract, or a customer is seeking to shorten or eliminate the term of an existing contract, we believe that each has a heavy burden in demonstrating that the contract ought to be modified. Still, we believe that given the industry circumstances now facing us, both selling utilities and their customers ought to have an opportunity to make the case that their existing requirements contracts ought to be modified. By providing both buyers and sellers this opportunity, the Commission attempts to strike a reasonable balance of the interests of all market participants. The Commission expects that many of the arguments presented by buyers and sellers in such proceedings will be fact specific. We note that because we are not abrogating existing requirements and transmission contracts generically and because Docket Nos. RM95-8-000 - 88 - and RM94-7-001 the functional unbundling requirement of the Final Rule 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. However, if a customer's existing bundled service (transmission and generation) contract or transmission-only contract expires, and the customer takes any new transmission service from its former supplier, the terms and conditions of the Final Rule tariff would then apply to the transmission service that the customer receives. A further issue concerning firm contract customers is their right to transmission capacity (and the rate for such capacity) when their contracts expire by their own terms or become subject to renewal or rollover. We have 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. The limitations 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 offered by the potential customer. Docket Nos. RM95-8-000 - 89 - and RM94-7-001 176/ This means that there is no right to grandfather the historical price of the transmission service. Thus, if not enough capacity is available to meet all requests for service, the right of first refusal gives the capacity to the existing customer who had contractually been using the capacity on a long- term, firm basis, assuming that it meets the conditions set forth above. Moreover, this limited right of first refusal is not a one-time right of first refusal for contracts existing as of the date of the final rule, but is an ongoing right that may be exercised at the end of all firm contract (including all future unbundled transmission contracts) terms. A customer converting existing bundled service to the Final Rule pro forma tariff would not have a reservation priority for capacity expansions, unless the existing contract provides for future transmission to the customer that requires capacity expansion. 177/ Finally, with respect to all existing requirements contracts and tariffs that provide for bundled rates, we will require all public utilities to make informational filings setting forth the unbundled power and transmission rates reflected in those 176/ 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. 177/ The above discussion on a right of first refusal addresses firm contract customers. However, the same logic applies to retail customers. Docket Nos. RM95-8-000 - 90 - and RM94-7-001 contracts and tariffs. These informational rates must be submitted to the Commission within 60 days of publication of the Final Rule in the Federal Register and must also be included as a line item on all bills submitted to wholesale customers in the third month following the effective date of this final rule. The unbundled informational rates will permit wholesale customers to compare rates in anticipation of their contracts expiring so that they can evaluate alternative contracts. Coordination Agreements The situation as to coordination agreements requires a slightly different approach. 178/ While we also believe that as a general matter it is important not to generically abrogate any coordination agreements, this is particularly true for non- economy energy coordination agreements that may reflect complementary long-term obligations among the parties. This type of agreement presents special problems and, as discussed below, 178/ For purposes of this discussion, we define coordination agreements as all power sales agreements, except requirements service agreements. In addition, for purposes of implementing the non-discriminatory, open access requirements of the Final Rule, we are dividing bilateral coordination agreements into two general categories: (1) economy energy coordination agreements are contracts and service schedules thereunder that provide for trading of electric energy on an "if, as, and when available" basis, but do not require either the seller or buyer to engage in a particular transaction; and (2) non-economy energy coordination agreements are any non-requirements service agreements, except economy energy coordination agreements. Docket Nos. RM95-8-000 - 91 - and RM94-7-001 we will not generically require this type of coordination agreement to be modified. 179/ Hundreds of coordination agreements exist in the industry today. Many are open-ended agreements that permit new transactions to occur well into the future. Because these contracts may not expire of their own terms in a reasonable time, they may present a larger and more enduring obstacle to non- discriminatory open access and more competitive bulk power markets. Thus, to assure that non-discriminatory open access becomes a reality in the relatively near future, we will partially modify existing economy energy coordination agreements. We will condition future sales and purchase transactions under existing economy energy coordination agreements 180/ to require that the transmission service associated with those transactions be provided pursuant to this Rule's requirements of non-discriminatory open access, no later than December 31, 1996. 181/ We also will require that for 179/ The requirements for power pools and other multilateral arrangements are discussed in detail in Section IV.F. 180/ Those executed prior to 60 days after publication of the Open Access Rule in the Federal Register. 181/ The requirement to unbundle future transactions under existing economy energy coordination agreements means that if the transmission owner uses its transmission system to make economy energy coordination sales or purchases, it must take service for these transactions under its own transmission tariff after December 31, 1996. Docket Nos. RM95-8-000 - 92 - and RM94-7-001 new economy energy coordination agreements 182/ 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. 183/ Finally, we will treat non-economy energy coordination agreements differently. We will not require their modification. However, this does not insulate such agreements from complaints that transmission service provided under such agreements be provided pursuant to the Final Rule pro forma tariff. With respect to coordination pricing practices, we conclude that non-discriminatory open access consistent with the requirements of this Rule is necessary if we are to allow utilities to continue to use market-driven pricing, such as split-the-savings pricing, for coordination sales. Absent such non-discriminatory open access, a utility would be able to deny access to others so as to obtain a higher price for its own power sales. 6. Flow-based Contracting and Pricing In the NOPR, the Commission discussed the procedures to be used in establishing Stage One rates. These Stage One rates were 182/ Those executed 60 days after publication of the Open Access Rule in the Federal Register. 183/ Accordingly, 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. RM95-8-000 - 93 - and RM94-7-001 proposed as an administrative convenience. The proposal merely followed the long-established practice of establishing rates on the basis of contract path pricing. 184/ The Commission made no determination with respect to the appropriateness of flow- based pricing or contracting for other purposes. 185/ Comments Most of the commenters addressing this issue recommend that industry or the Commission -- either in this rule or ultimately -- dispense with the traditional contract path basis for pricing and contracting. Most commenters also recommend that the Commission adopt or encourage a regional approach to the solution of transmission pricing problems, though they differ markedly in how to account for flows. 186/ Transmission customers generally seek to rid themselves of "pancaked" transmission rates that are associated with the traditional approach to transmission pricing. 187/ They 184/ A contract path is simply a path that can be designated to form a single continuous electrical path between the parties to an agreement. Because of the laws of physics, it is unlikely that the actual power flow will follow that contract path. 185/ Flow-based pricing or contracting would be designed to account for the actual power flows on a transmission system. It would take into account the "unscheduled flows" that occur under a contract path regime. 186/ E.g., APPA, TAPS, NY Energy Buyers, Arcadia, Brownsville, Detroit Edison Customers, AMP-Ohio, Michigan Systems. 187/ E.g., AMP-Ohio, NRECA, APPA, Detroit Edison Wholesale Customers, MMWEC, Missouri Basin MPA, Air Liquide, American Wind Energy, Associated Power, CCEM. Docket Nos. RM95-8-000 - 94 - and RM94-7-001 propose the development of regionwide transmission rates, perhaps determined on a pool or RTG basis. Most, however, do not discuss how to account for unscheduled flows. 188/ Many transmission providers, some regulatory authorities, and some individuals strongly support flow-based pricing. Most of these commenters recognize a need for a regional approach to resolve transmission pricing concerns. 189/ However, many of them also appear to accept contract pricing in the near term because of the need to implement open access quickly. 190/ NERC recommends that the Commission maintain an open position on the transfer scheduling process and supports changes in the process to reflect actual power flows. EEI suggests that the Commission should be willing to deviate from a contract path approach, since competition may be accompanied by greater unscheduled flows and contract pricing is not well equipped to deal with such flows. However, EEI concludes that a single approach to pricing will not be appropriate for all systems. 188/ Some commenters propose the development of a regional rate on a postage stamp basis, without regard to distance travelled or the actual path of power flows. E.g., Air Liquide, American National Power, CA Energy Co. Several commenters do, however, propose ways to account for unscheduled flows. E.g., American Forest & Paper, DE Muni, Lower Colorado River Authority. 189/ E.g., CSW, EDS Utilities, Dominion, CINergy, KS Com, CT DPUC, Com Ed, Hogan. 190/ NYMEX favors contract path pricing because of its familiarity and believes that the issue should primarily be resolved by the transmitting utilities. AEP believes that the primary responsibility lies with industry to develop alternative pricing structures. Docket Nos. RM95-8-000 - 95 - and RM94-7-001 Other commenters, however, do raise concerns with respect to flow-based pricing. AEC & SMEPA considers flow-based pricing to be flawed because that method makes an individual customer responsible for load flow effects caused by a third party's development of the third-party's transmission system over which the customer and its transmission provider had no control. Dayton P&L fears that competition would be lessened under flow- based pricing because utilities with large transmission systems would dominate the market. Several commenters oppose Southern's and United Illuminating's flow-based proposals, arguing that the methodologies are based on estimates of actual flows or a set of conditions with limited applicability. Various commenters also believe that a single rate is flawed and could cause just as many problems as contract path pricing. 191/ Most commenters appear to believe that the Commission endorsed contract path pricing in the NOPR. Hogan expresses concern that many industry participants' understanding of the pro forma tariffs is based on the fiction of the contract path. The MT Dept of Environmental Quality believes that despite the Commission's pledge to consider innovative pricing proposals, 192/ such proposals will receive heavy scrutiny, while conventional contract path pricing proposals will receive nearly 191/ E.g., NU, NEPCO, BECO, Florida Power Corp. 192/ See FERC Stats. & Regs.  31,005. Docket Nos. RM95-8-000 - 96 - and RM94-7-001 automatic approval. Dominion is concerned that relying on the initiative of individual transmission owners to develop flow- based pricing will yield slow and patchy results. Commission Conclusion We will not, at this time, require that flow-based pricing and contracting be used in the electric industry. In reaching this conclusion, we recognize that there may be difficulties in using a traditional contract path approach in a non- discriminatory open access transmission environment, as described by Hogan and others. At the same time, however, 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. To require now 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, we believe it is premature for the Commission to impose generically a new pricing regime without the benefit of any experience with such pricing. We welcome new and innovative proposals, but we will not impose them in this Rule. While we are not requiring the use of any form of flow-based pricing, we recognize that some versions of flow-based pricing could have benefits. For example, some versions of flow-based pricing could more accurately reflect and price the actual power flows on transmission systems and thus could produce efficiency Docket Nos. RM95-8-000 - 97 - and RM94-7-001 gains, better generation siting decisions, and benefits for customers and utilities alike. Other versions could more accurately assign capacity rights in accordance with a party's contribution to capacity costs. These potential benefits, however, will not simply come about in the abstract. Flow-based pricing methodologies that will achieve the benefits sought by most of the participants in the industry are in a development stage and require further work and refinement to address some of the difficulties associated with flow-based approaches. Concurrent work on OASIS and resolving available transmission capability issues may help resolve flow-based issues. However, as demonstrated by the paucity of possible methodologies presented in the comments, developing workable methodologies will be difficult. As we explained in our Transmission Pricing Policy Statement, we are receptive to proposals for alternative rate methodologies, such as distance-sensitive and flow-based pricing, as long as the proposals are well supported. However, we have yet to receive a formal rate application for a flow-based pricing methodology that has been tested enough that it can be required on a generic basis. Thus, we have decided to go forward to achieve open access and more competitive wholesale bulk power markets without waiting for the development of a generic flow-based pricing methodology. We wish to emphasize further that in taking this approach we are not endorsing the traditional contract path approach as the Docket Nos. RM95-8-000 - 98 - and RM94-7-001 only available approach. We continue to approve contract path pricing because it is the long-established pricing method that comes to us in rate filings by the electric industry, is administratively convenient and feasible, and thus is a practical way to move forward now. We remain open to alternative methodologies, but need to see better developed approaches from the industry before we can consider generic adoption of alternative pricing. We also believe the adoption of flow-based pricing will be more practical on a regional, instead of individual utility, basis. Some forms of flow-based pricing may even require a regional approach. To this extent, regional ISOs could be a valuable mechanism for implementing such pricing reforms. B. Legal Authority The Commission reaffirms its conclusion in the NOPR that we have the authority under the FPA to order wholesale transmission services in interstate commerce to remedy undue discrimination by public utilities. We analyze below the relevant cases examining our wheeling authority, then discuss and respond to the legal arguments raised by the commenters. 1. Bases for Legal Authority a. Undue Discrimination/Anticompetitive Effects In upholding the Commission's order requiring non- discriminatory open access in the natural gas industry, the court in Associated Gas Distributors v. FERC stated that the Natural Docket Nos. RM95-8-000 - 99 - and RM94-7-001 Gas Act "fairly bristles" with concern for undue discrimination. 193/ The same is true of the FPA. The Commission has a mandate under sections 205 and 206 of the FPA to ensure that, with respect to any transmission in interstate commerce or any sale of electric energy for resale in interstate commerce by a public utility, no person is subject to any undue prejudice or disadvantage. We must determine whether any rule, regulation, practice or contract affecting rates for such transmission or sale for resale is unduly discriminatory or preferential, and must prevent those contracts and practices that do not meet this standard. As discussed below, AGD demonstrates that our remedial power is very broad and includes the ability to order industry- wide non-discriminatory open access 194/ as a remedy for undue discrimination. The AGD court reached this decision even in the face of prior cases that acknowledged that Congress did not mandate common carriage or explicitly empower the Commission to order direct access for either gas transporters or electric utilities. Moreover, the Commission's power under the FPA "clearly carries with it the responsibility to consider, in appropriate circumstances, the anticompetitive effects of regulated aspects of interstate utility operations pursuant to 193/ Associated Gas Distributors v. FERC, 824 F.2d 981, 998 (D.C.Cir. 1987), cert. denied, 485 U.S. 1006 (1988) (AGD). 194/ We use the term "open access" to refer to a public utility's obligation to put a tariff on file offering service to eligible customers. Access is not open to all. Specifically, the tariff is not an offer to serve retail customers if state law does not permit retail wheeling. Docket Nos. RM95-8-000 - 100 - and RM94-7-001 [FPA]  202 and 203, and under like directives contained in  205, 206, and 207." 195/ Therefore, based on the mandates of sections 205 and 206 of the FPA and the case law interpreting the Commission's authority over transmission in interstate commerce, we conclude that we have ample legal authority -- indeed, a responsibility -- under section 206 of the FPA to order the filing of non-discriminatory open access transmission tariffs if we find such order necessary as a remedy for undue discrimination or anticompetitive effects. 196/ We discuss below the primary court decisions that touch on our wheeling authority under sections 205 and 206. The Commission's authority to order access as a remedy for undue discrimination under the Natural Gas Act (NGA) was upheld and discussed in detail in AGD. In AGD, the court upheld in relevant part the Commission's Order No. 436. 197/ That order found the prevailing natural gas company practices to be "unduly discriminatory" within the meaning of section 5 of the 195/ Gulf States Utilities Company v. FPC, 411 U.S. 747, 758-59 (1973). 196/ In most situations, discrimination that precludes transmission access or gives inferior access will have at least potential anticompetitive effects because it limits access to generation markets and thereby limits competition in generation. Similarly, it is probable that any transmission provision that has anticompetitive effects would also be found to be unduly discriminatory or preferential because the anticompetitive provision would most likely favor the transmission owner vis-a-vis others. 197/ Order No. 436, Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, FERC Stats. & Regs., Regulations Preambles  30,665 (1985). Docket Nos. RM95-8-000 - 101 - and RM94-7-001 NGA (the parallel to section 206 of the FPA) and held that if pipelines wanted blanket certification for their transportation services, they must commit to transport gas for others on a non- discriminatory basis; in other words, they must provide non- discriminatory open access. In upholding the Commission's authority to require open access, the court first noted that the opponents' arguments against such authority must proceed "uphill." The statute contains no language forbidding the Commission to impose common carrier status on pipelines, let alone forbidding the Commission to impose "a specific duty that happens to be a typical or even core component of such status." The court found that the legislative history cited by the opponents came nowhere near overcoming this statutory silence. Rather, the legislative history supported only the proposition that Congress itself declined to impose common carrier status. 198/ Emphasizing Congress' deep concern with undue discrimination, the court found that the Commission had ample authority to "stamp out" such discrimination: The issue seems to come down to this: Although Congress explicitly gave the Commission the power and the duty to achieve one of the prime goals of common carriage regulation (the eradication of undue discrimination), the Commission's attempted exercise of that power is invalid because Congress in 1906 and 1914 and 1935 and 1938 itself refrained from affixing common carrier status directly onto the pipelines and from 198/ AGD, supra, 824 F.2d at 997. Docket Nos. RM95-8-000 - 102 - and RM94-7-001 authorizing the Commission to do so. And this proposition is said to control no matter how sound the Order may be as a response to the facts before the Commission. We think this turns statutory construction upside down, letting the failure to grant a general power prevail over the affirmative grant of a specific one. [199/] The AGD court found that court decisions under the FPA did not support the view that the Commission's authority to "stamp out" undue discrimination is hamstrung by an inability to require non- discriminatory open access as a remedy. These decisions are discussed below. One of the earliest cases on wheeling is Otter Tail Power Company v. United States (Otter Tail). 200/ In that case, the Supreme Court rejected the argument that the District Court, in a civil antitrust suit, could not order wheeling because to do so would conflict with the FPC's purported wheeling authority. 201/ The Court explained that Congress had decided not to impose a common carrier obligation on the electric power industry and noted that the Commission was not at that time expressly granted power to order wheeling. 202/ In effect, it concluded that because Congress did not include common carrier provisions in the FPA, the Commission must not have any express authority to order wheeling that would preclude the District 199/ Id. at 998. 200/ 410 U.S. 366 (1974). 201/ 410 U.S. at 375-76. 202/ Id. at 374-76. Docket Nos. RM95-8-000 - 103 - and RM94-7-001 Court from imposing a wheeling remedy. Nowhere, however, did the Court say that the Commission lacked authority under section 206 to remedy undue discrimination. Indeed, that was simply not a matter before the Court or of any consequence to its decision. 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. 203/ 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 our achieving one of the primary goals of the FPA -- eradicating undue discrimination in transmission in interstate commerce in the electric power industry. In Richmond Power & Light Company v. FERC (Richmond), 204/ the FPC, in reaction to the 1973 oil embargo, was attempting to reduce dependence on oil. The FPC requested that utilities with excess capacity wheel power to the New England Power Pool (NEPOOL). In response, several suppliers and 203/ See AGD, 824 F.2d at 998. 204/ 574 F.2d 610 (D.C. Cir. 1978). Docket Nos. RM95-8-000 - 104 - and RM94-7-001 transmission owners filed rate schedules with the FPC that provided for voluntary wheeling. Richmond Power & Light Company (Richmond) objected to these filings, claiming that they were unreasonable because they did not guarantee transmission access. The FPC refused to compel the utilities to wheel Richmond's power, stating that it did not have the authority to order a public utility to act as a common carrier. The D.C. Circuit upheld the Commission. It acknowledged that Richmond's argument was persuasive in some respects, but stated that any conditions the Commission might impose could not contravene the FPA. The court examined the legislative history of the FPA and stated that "[i]f Congress had intended that utilities could inadvertently bootstrap themselves into common- carrier status by filing rates for voluntary service, it would not have bothered to reject mandatory wheeling. . . ." 205/ However, the D.C. Circuit in no way indicated that the Commission was foreclosed from ordering transmission as a remedy for undue discrimination. Richmond also had argued that the alleged refusal of the American Electric Power Company (AEP) and its affiliate, Indiana & Michigan Electric Company (Indiana), to wheel Richmond's excess energy was unlawful discrimination because AEP and Indiana wheeled higher-priced electricity from other AEP affiliates. The court acknowledged that Richmond's claim of unlawful discrimination was theoretically valid, but 205/ Id. at 620. Docket Nos. RM95-8-000 - 105 - and RM94-7-001 found that Richmond had failed to prove its case. It noted that if Richmond had argued that the rates were unjustifiably discriminatory, or that Indiana's failure to use its transmission capability fully or to purchase less expensive electricity for wheeling resulted in unnecessarily high rates, a different case would be before the court. 206/ The case thus does not in any way limit the Commission's authority to remedy undue discrimination. In Central Iowa Power Cooperative v. FERC, 207/ the FPC 208/ reviewed the terms of the Mid-Continent Area Power Pool (MAPP) Agreement under its section 205 and 206 authority. The agreement contained two membership limitations. First, the agreement established two classes of membership, with one class being entitled to more privileges than the other. Second, the agreement excluded non-generating distribution systems from pool services. The FPC found the first limitation on membership -- the two-class system -- to be unduly discriminatory and not reasonably related to MAPP's objectives. The FPC conditioned approval of the agreement under section 206 on the removal of the unduly discriminatory provision. The FPC found that the second limitation, the exclusion of non-generating distribution systems, 206/ Id. at 623, nn.53 and 57. 207/ 606 F.2d 1156 (D.C. Cir. 1979). 208/ While Central Iowa was pending, certain of the functions of the FPC were transferred to the FERC under the DOE Organization Act. Accordingly, the FERC was substituted for the FPC as the respondent in the case. Docket Nos. RM95-8-000 - 106 - and RM94-7-001 was not anticompetitive and did not render the agreement inconsistent with the public interest. On appeal, the D.C. Circuit affirmed the FPC's decision. The court found that the FPC did have authority to order changes in the scope of the MAPP agreement, if the agreement was unjust,unreasonable, unduly discriminatory or preferential under section 206 of the FPA. The court stated: The Commission had authority, . . . under section 206 of the Act, . . . to order changes in the limited scope of the Agreement, including the addition of pool services, if, in the absence of such modifications, the Agreement presented "any rule, regulation, practice or contract [that was] unjust, unreasonable, unduly discriminatory or preferential." [209/] However, the court agreed with the FPC's conclusion that the limited scope of MAPP was not unjust, unreasonable, or unduly discriminatory. The court recognized that a pool was not invalid under section 206 merely because a more comprehensive arrangement was possible. The D.C. Circuit upheld the Commission's refusal to eliminate the second limitation on membership by ordering MAPP participants to wheel to non-generating electric systems. 210/ However, neither the Commission nor the court was presented with the argument that wheeling was necessary as a remedy for undue discrimination. 209/ 606 F.2d at 1168. 210/ Id. at 1169; see also Municipalities of Groton v. FERC, 587 F.2d 1296 (D.C. Cir. 1978). Docket Nos. RM95-8-000 - 107 - and RM94-7-001 In Florida Power & Light Company v. FERC (Florida), 211/ the Commission ordered Florida Power & Light Company (FP&L) to file a tariff setting forth FP&L's policy relating to the availability of transmission service. 212/ FP&L objected to including such a policy statement in its tariff and argued that the filing of such a policy would convert FP&L into a common carrier by obligating it to offer service to all customers. 213/ There was no finding that the action ordered was necessary to remedy undue discrimination. The Fifth Circuit Court of Appeals agreed with FP&L that the mandatory filing of the policy statement would require FP&L to provide transmission service beyond its voluntary commitment because such a requirement would change its duties and 211/ 660 F.2d 668 (5th Cir. 1981), cert. denied sub nom. Fort Pierce Utilities Authority v. FERC, 459 U.S. 1156 (1983). 212/ FP&L provided transmission service when four conditions were met: (1) the specific potential seller and buyer were contractually identified; (2) the magnitude, time and duration of the transaction were specified prior to the commencement of the transmission; (3) it could be determined that the transmission capacity would be available for the term of the contract; and (4) the rate was sufficient to cover FP&L's costs. 213/ All utilities requesting wheeling services, subject to availability, would be entitled to receive transmission service under the filed terms. Any changes to a filed rate must be filed with the Commission. This is the so-called "filed rate doctrine." See Northwestern Public Service Company v. Montana-Dakota Utilities Company, 181 F.2d 19, 22 (8th Cir. 1980), aff'd, 341 U.S. 246 (1951). Docket Nos. RM95-8-000 - 108 - and RM94-7-001 liabilities. 214/ The Commission order would impose common carrier status on FP&L, the court found. 215/ The court noted that the Commission did not rely on a finding of anticompetitive behavior and therefore the court did not address the Commission's power to remedy antitrust violations. 216/ The AGD court explicitly rejected the claim that the above line of cases establishes that the Commission lacks authority to require non-discriminatory open access. 217/ Opponents of the Commission's order argued in AGD that Richmond and Florida, supra, stand for the proposition that the Commission cannot indirectly do what it allegedly cannot do directly, that is, impose common carriage. The AGD court rejected these arguments, stating that the petitioners read the electric cases far too broadly: 214/ Under the filed rate doctrine, a refusal to wheel would be unduly discriminatory under section 206 of the FPA. As the court acknowledged, a customer refused service could petition the Commission to find that FP&L's policy of availability was unduly discriminatory under section 206(a) of the FPA. The court said that in the absence of a tariff on file, a utility refused wheeling services would be unable to claim discrimination under section 206(a) of the FPA. 660 F.2d at 675 (expressing "serious doubts that such a petition would be successful in the absence of a tariff"). 215/ Id. at 676. 216/ Id. at 678. 217/ The AGD court did not address New York State Electric & Gas Corporation v. FERC, 638 F.2d 388 (2d Cir. 1980), cert. denied, 454 U.S. 821 (1981) (NYSEG), presumably because that case did not concern whether the Commission could order wheeling as a remedy for undue discrimination. Docket Nos. RM95-8-000 - 109 - and RM94-7-001 [n]either Richmond nor Florida comes anywhere near stating that the Commission is barred from imposing an open-access condition in all circumstances. [218/] The court noted that the Florida case had expressly left open the question of whether the Commission would be entitled to use an open access condition as a remedy for anticompetitive conduct, and that in Richmond the D.C. Circuit had said little more than that unwillingness to transmit for all could not be automatically deemed undue discrimination. The court also noted the Central Iowa case, supra, in which it had upheld a Commission order that found a power pooling agreement discriminatory on its face because the agreement gave one class of membership privileged status over another. The court stated that the Central Iowa case "upholds the power of the Commission to subject approval of a set of voluntary transactions to a condition that providers open up the class of permissible users." 219/ The court added that it refused to "turn statutory construction upside down" by letting Congress' failure to grant a general power of common carriage prevail over the affirmative grant of the specific power to eradicate undue discrimination. 220/ We conclude that AGD's analysis of undue discrimination under sections 4 and 5 of the Natural Gas Act is equally 218/ 824 F.2d at 999. 219/ Id. at 999. 220/ Id. at 1006. Docket Nos. RM95-8-000 - 110 - and RM94-7-001 applicable to an undue discrimination analysis under sections 205 and 206 of the FPA. The Commission and courts have long recognized that the NGA was patterned after the FPA and that the two statutes should be interpreted in the same manner. 221/ Thus, we conclude that we have the authority to remedy undue discrimination and anticompetitive effects by requiring all public utilities that own, control or operate transmission facilities to file non-discriminatory open access transmission tariffs. b. Section 211 of the Federal Power Act In concluding that we must invoke our section 206 authority to remedy undue discrimination and anticompetitive effects in the electric industry, we have carefully considered the goals of Title VII of the Energy Policy Act, and whether section 211 of the FPA, by itself, is sufficient to remedy undue discrimination in public utility transmission services. Title VII of the Energy Policy Act, which amended section 211 of the FPA to give the Commission broader authority to order wheeling in the public interest on a case-by-case basis, reflects the intent of Congress to encourage competitive wholesale electric markets. Section 211 provides a means for wholesale power sellers and buyers to obtain 221/ See, e.g., FPC v. Sierra Pacific Power Company, 350 U.S. 348, 353 (1956); Arkansas Louisiana Gas Company v. Hall, 453 U.S. 571, 577 n.7 (1981); and Kentucky Utilities Company v. FERC, 760 F.2d 1321, 1325 n.6 (D.C. Cir. 1985). Section 206 of the FPA was recently revised and now differs from section 5 of the NGA, but not in a manner significant to our discussion here. See 16 U.S.C.  824e(b) and (c). Docket Nos. RM95-8-000 - 111 - and RM94-7-001 transmission services necessary to compete in, or to reach, competitive markets, and is a valuable tool to encourage competitive markets. However, in amending section 211, Congress left unaltered the authorities and obligations of the Commission under sections 205 and 206 (similar to our authorities and obligations under sections 4 and 5 of the NGA) to remedy undue discrimination. In addition, as discussed below, reliance on section 211 alone in some circumstances can result in the perpetuation of, rather than the elimination of, undue discrimination and anticompetitive effects. First, there are inherent delays in the procedures for obtaining service under section 211. However, for competitive reasons, many transactions must be negotiated relatively quickly. Many competitive opportunities will be lost by the time the Commission can issue a final order under section 211. Case-by- case section 211 proceedings are not a substitute for tariffs of general applicability that permit timely, non-discriminatory access on request. Second, discrimination is inherent in the current industry environment in which some customers and sellers are served by open access systems, and others have to rely on negotiated bilateral arrangements or the mandatory section 211 process. The end result is discrimination in the ability to obtain transmission services, as well as in the quality and prices of the services. This national patchwork of open and closed Docket Nos. RM95-8-000 - 112 - and RM94-7-001 transmission systems, with disparate terms and conditions of service, cannot be cured effectively through section 211. The Commission believes that its actions under sections 205 and 206 will complement the section 211 procedures to achieve both the Energy Policy Act's goals of creating more competitive bulk power markets and lower rates for consumers and the Federal Power Act's explicit direction in section 205(b) that no public utility shall, with respect to any transmission in interstate commerce, grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage. 2. Response to Commenters Opposing our Legal Authority a. Authority to Order Open Access Tariffs Comments Initial Comments Supporting Commission Authority A number of commenters support or state that they do not oppose the Commission's authority to order open access tariffs. 222/ NIEP and CCEM explain that the AGD decision supports the Commission's action in this proceeding. ELCON asserts that the Commission's "extensive treatment of the relevant case law demonstrating FERC's authority to remedy this discrimination is legally sound." UtiliCorp argues that section 211 supports, rather than undermines, the Commission's authority for the NOPR 222/ NIEP, ELCON, CINergy, UtiliCorp, TAPS, SBA, Entergy, NY Energy Buyers, Sierra. Docket Nos. RM95-8-000 - 113 - and RM94-7-001 because it reflects Congress's intention to encourage more competitive bulk power markets. Initial Comments Opposing Commission Authority Other commenters assert that the Commission has improperly relied on sections 205 and 206 of the FPA to require open access. 223/ They argue, for instance, that Otter Tail should be read as a broad constraint on the Commission's authority to order wheeling for any purpose and that the AGD decision does not undermine that holding or the cases following Otter Tail. 224/ In support, some of these commenters discuss Richmond Power & Light, New York State Electric & Gas Corporation, and Florida Power & Light Company, the same cases discussed by the Commission in the NOPR. 225/ For example, EEI highlights the AGD court's discussion noting the difference between the legislative history of the NGA and that of the FPA, which the court stated was not as strong as that of the NGA. Moreover, EEI argues that the court found that section 7 of the NGA provided support for the Commission's actions in Order No. 436 and that such section 7 conditioning authority is lacking under the FPA. Allegheny notes that AGD did 223/ E.g., EEI, Atlantic City, Allegheny, VA Com, PA Com, Ohio Edison, Southern, Utilities For Improved Transition, Dayton P&L, SCE&G, Centerior, BG&E, Central Hudson, NY Com, Salt River, Carolina P&L, Union Electric, VEPCO, Utility Workers Union. 224/ EEI, VA Com, Union Electric. 225/ E.g., EEI, VA Com, NY Com, PA Com, Salt River, Southern, Dayton P&L, Detroit Edison, BG&E. Docket Nos. RM95-8-000 - 114 - and RM94-7-001 not overrule Otter Tail. Dayton P&L states that, in the gas case, the Commission was responding to voluntary filings by pipelines. It also says that before the NOPR, the Commission itself saw its authority as more limited. SCE&G points to differences between Commission jurisdiction over public utilities and gas pipelines and criticizes the Commission's alleged assumption that the circumstances involved in the gas and electric industries are virtually identical. PA Com argues that the attempt to analogize to the NGA and the cases that refer to that Act is inconsistent with the technical and engineering realities of the electric transmission grid and that extensive comparisons between the natural gas industry and the electric industry are misleading. 226/ FL Com argues that, in relying on sections 205 and 206 to establish generic open access transmission tariffs for all public utilities, the Commission violates the court's decision in Cajun Electric Power Cooperative v. FERC, 28 F.3d 173 at 179 (D.C. Cir. 1994), where, FL Com argues, the court refused to allow the Commission to use a non-evidentiary ruling when there were material facts at issue. Reply Comments CCEM responds that EEI and others confuse the obligations of a common carrier with the duty of public utilities not to unduly discriminate. It says that AGD supports the Commission's 226/ See also NY Com (NGA has no parallel provision to section 211 of the FPA), Salt River. Docket Nos. RM95-8-000 - 115 - and RM94-7-001 authority because the legislative history of the FPA and the NGA are similar with respect to common carriage. According to CCEM, early versions of both statutes would have made the regulated industries operate as common carriers (citing Otter Tail, the legislative history of the FPA, the legislative history of the Public Utility Holding Company Act, and the legislative history of the Mineral Leasing Act), but that Congress chose not to impose the common carrier obligations. CCEM also says that the duties the Commission imposed on the gas industry and those in the NOPR are not common carriage in any event. According to CCEM, a common carrier must carry all goods offered (citing Am. Trucking Assoc. v. Atchison, T. & S.F. Ry. Co., 387 U.S. 397, 406 (1967)). Finally, CCEM cites Stephenson v. Binford, 287 U.S. 251, 265-66 (1932), where the Supreme Court held that obligations that are typical of common carriers can be imposed on contract motor carriers. CCEM further disagrees with EEI's argument that the enactment of section 211 was a disavowal of any other Commission authority to order transmission. ELCON also disagrees with EEI's claim that the Energy Policy Act undermines the Commission's pre-existing section 205 and 206 authority. It states that the savings clause in section 212(e) of the FPA, as amended, explicitly expresses Congress' intention not to undermine the Commission's pre-existing authority and that the legislative history contains nothing to suggest otherwise. Docket Nos. RM95-8-000 - 116 - and RM94-7-001 Similarly, in response to those who argue that section 211 is the only source of authority for the Commission to order transmission, NIEP argues that sections 211 and 212 serve purposes different from section 206. It says that the Commission's authority to order transmission in the "public interest" under sections 211 and 212 is not synonymous with its authority to order transmission as a remedy for undue discrimination under section 206; the two standards are complementary but distinct: Although broadly applicable, the Commission's ability to order wheeling under Sections 211 and 212 is carefully limited by a number of procedural provisions. Foremost among these is the requirement that the wheeling may be ordered only upon a specific application for transmission services. FERC's authority to act in the public interest is thus confined to the individual case. By contrast, FERC's remedial powers under Section 206 can be exercised upon a finding of unjust, unreasonable or unduly discriminatory or preferential practices. Once that finding has been made, however, the form and substance of the remedy is left entirely to the FERC's discretion. If FERC deems it necessary, FERC may adopt generally applicable rules or practices as a countermeasure to discriminatory acts, including ordering utilities to file generally applicable transmission tariffs. [227/] NIEP also points out that the legislative history does not address the Commission's authority to order transmission as a remedy for undue discrimination. It challenges the 227/ NIEP Reply Comments at 8. Docket Nos. RM95-8-000 - 117 - and RM94-7-001 interpretation of the legislative history advanced by some commenters. 228/ Next, NIEP defends the Commission's proposed findings that there is generally undue discrimination in the provision of transmission service. It notes that when an agency acts on an industry-wide basis, the agency does not have to make a finding as to each particular case. Finally, NIEP responds to those who argue that AGD is not on point. It notes that the AGD court discussed electric cases and emphasizes the court's statement that the NGA "fairly bristles with concern for undue discrimination" -- a statement that is equally true of the FPA. TDU Systems responds to the argument that Otter Tail is a broad constraint on the Commission's authority to order 228/ NIEP explains that [w]hile much has been made of the Senate report accompanying S.2114, which subsequently became part of PURPA in 1978, that report does not illustrate an intent to limit FERC's authority to remedy undue discrimination under Section 206. That report characterizes the Supreme Court's decision in Otter Tail as holding that "the Federal Power Act leaves open a gap in its failure to assign the FPC general authority to order wheeling in this situation...." The "situation" to which the Report refers is not discrimination, however. Instead, the statement appears to make reference to circumstances in which general public interest concerns, such as reliability, efficiency and competition, are at stake. Thus, Senate Report 2114 is simply not a limitation on the Commission's remedial powers under Sections 206. NIEP Reply Comments at 8-9 (citations omitted). Docket Nos. RM95-8-000 - 118 - and RM94-7-001 transmission. 229/ At issue in that case, it argues, was the reach of the Sherman Act, not of FPA sections 205 and 206. Similarly, it argues, the Florida Power case is not on point, and the court there specifically said that it was not deciding whether the Commission could have ordered wheeling as a remedy for anticompetitive activities. Moreover, TDU Systems asserts that EEI's use of a quote from a single Senator should carry no weight, since it is a well-established principle of statutory construction that such statements have little value. Finally, it points out that the AGD court itself did not view Otter Tail or other electric precedent as forbidding the Commission to order wheeling as a remedy for undue discrimination. Entergy asserts that Congress's refusal to require utilities to provide transmission as common carriers or whenever it is in the public interest was merely a decision not to give the Commission general authority to order wheeling, without regard to undue discrimination. Thus, the Otter Tail language concerning the absence of a common carrier requirement does not demonstrate that Congress meant to limit the Commission's authority to remedy undue discrimination. ELCON disputes EEI's reading of NYSEG, noting that the NYSEG court explicitly stated: Nor do we suggest that the Commission is powerless to review a wheeling agreement 229/ See also Entergy. Docket Nos. RM95-8-000 - 119 - and RM94-7-001 under  206 without following the requirements of  211 and 212. [230/] TAPS discusses numerous cases, including the primary cases relied upon by the Commission, and disposes of NYSEG by stating that it is no longer good law, if it ever was. Commission Conclusion There can be no question that the Commission has the authority to remedy undue discrimination. Sections 205 and 206 of the FPA mandate that we ensure that, with respect to any transmission in interstate commerce or any sale of electric energy for resale in interstate commerce by a public utility, no person is subject to any undue prejudice or disadvantage. Under these sections, we must determine whether any rule, regulation, practice, or contract affecting rates for such transmission or sale for resale is unduly discriminatory or preferential, and we must disapprove those contracts and practices that do not meet this standard. Our discretion is at its zenith in fashioning remedies for undue discrimination. 231/ Some commenters, however, challenge our authority to order industry-wide non-discriminatory open access as a remedy for the undue discrimination we have found in the industry. As summarized above, they essentially assert that we are prohibited by court precedent, the legislative history of the FPA, and 230/ ELCON Initial Comments at 7 (quoting NYSEG at 403). 231/ See, e.g., Niagara Mohawk Power Corporation v. FPC, 379 F.2d 153, 159 (D.C. Cir. 1967). Docket Nos. RM95-8-000 - 120 - and RM94-7-001 sections 211 and 212 of the FPA from ordering wheeling as a remedy for undue discrimination. We disagree and conclude that we have the authority -- indeed, a responsibility -- to require non-discriminatory open access transmission as a remedy for undue discrimination. AGD and Legislative History The court decision in Associated Gas Distributors v. FERC provides powerful support for our ability to order industry-wide non-discriminatory open access transmission in the electric industry as a remedy for undue discrimination. As discussed in detail above, AGD, which is the only decision to have addressed the Commission's authority to remedy undue discrimination by requiring open access, upheld our authority under section 5 of the NGA (the parallel to section 206 of the FPA) to require open access in the natural gas industry. The rationale supplied by the AGD court applies equally to the FPA and our responsibility to eliminate undue discrimination in the electric industry. Those who challenge the Commission's legal authority to remedy undue discrimination face the same difficulty that parties faced in seeking to overturn open access in the natural gas industry -- they "can point to no language in the [FPA] barring the Commission from imposing common carrier status on [public utilities], and certainly none barring it from imposing upon the [public utilities] a specific duty that happens to be a typical Docket Nos. RM95-8-000 - 121 - and RM94-7-001 or even core component of such status." 232/ Instead, as was unsuccessfully attempted in the AGD proceeding, they seek to overcome the statutory silence primarily by means of legislative history. However, as the AGD court explained, legislative history is not even relevant, because courts have no authority to enforce principles gleaned solely from legislative history that has no statutory reference point. [233/] Here, as the court found with respect to the NGA, the legislative history of the FPA "provides strong support only for the point that Congress declined itself to impose common carrier status on [public utilities]. . . . It affords weak -- almost invisible -- support for the idea that the Commission could under no circumstances whatsoever impose obligations encompassing the core of a common carriage duty." 234/ Commenters focus on the following statement in the AGD decision to support the argument that, because Congress did not expressly reject common carriage under the NGA, but did reject it under the FPA, a different outcome in this proceeding is required: we note that the legislative history of the two acts is, on this point, materially different. In its deliberations on the bill that ultimately emerged as the Federal Power 232/ AGD, 824 F.2d at 997. 233/ Id. (quoting IBEW, Local No. 474 v. NLRB, 814 F.2d 697, 712 (D.C. Cir. 1987)(emphasis deleted by court from original)). 234/ Id. (emphasis added). Docket Nos. RM95-8-000 - 122 - and RM94-7-001 Act, Congress considered and rejected a provision that would have "empowered the Federal Power Commission to order wheeling if it found such action to be 'necessary or desirable in the public interest.'" [citing Otter Tail] (quoting S. 1725, 74th Cong., 1st Sess.). The evidence as to the NGA (surveyed above) is less direct: it consists exclusively of various occasions on which Congress did not adopt proposals actually making the natural gas pipelines into common carriers. [235/] The above statement, however, does not preclude the AGD court's decision on our broad authority to remedy undue discrimination in the gas industry from applying equally in the electric industry. Clearly, the court did not say that. As discussed below, we believe the statement focuses on a distinction in the legislative histories that is not meaningful. First, whether or not a material difference exists in the respective legislative histories of the NGA and FPA, the fact remains that the crucial findings of the AGD court were that: (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." 236/ These findings apply equally to the FPA. Simply 235/ Id. at 998-99. 236/ Id. at 997. We also note that the contract carriage obligation we are imposing is easily distinguished from the common carrier obligation Congress chose not to adopt. As discussed infra, the common carrier provisions rejected by Congress would have required transmission for "any person" upon reasonable request. This would have included retail purchasers. Docket Nos. RM95-8-000 - 123 - and RM94-7-001 stated, statutory silence cannot be overcome by means of legislative history -- even if the legislative history in fact indicated that Congress "rejected" legislative imposition of common carrier status under the FPA, but "did not adopt" it under the NGA. In either event, nothing in the statute or legislative history suggests that Congress concluded that the Commission could under no circumstances impose open access as a remedy to undue discrimination. Moreover, the legislative history of the bills containing the FPA and the NGA, taken as a whole, suggests that the distinction drawn in AGD between the legislative histories of the NGA and the FPA is not meaningful. The legislation that was to become the FPA originally included provisions regulating both electric power and natural gas. As originally proposed, the legislation contained identical common carriage language for both public utilities and natural gas pipelines. With respect to the FPA, the Supreme Court explained in Otter Tail that [a]s originally conceived, Part II would have included a "common carrier" provision making it "the duty of every public utility to . . . transmit energy for any person upon reasonable request. . . ." In addition, it would have empowered the Federal Power Commission to order wheeling if it found such action to be "necessary or desirable in the public interest." H.R. 5423, 74th Cong., 1st Sess.; S. 1725, 74th Cong. 1st Sess. These provisions were eliminated to preserve "the voluntary action of the utilities." S.Rep. Docket Nos. RM95-8-000 - 124 - and RM94-7-001 No. 621, 74th Cong., 1st Sess., 19. [237/] The language paraphrased by the Supreme Court was from Title II of the initial bill proposing the Public Utility Holding Company Act. The entire sections from which the paraphrased language came are as follows: SEC. 202. (a) It shall be the duty of every public utility to furnish energy to, exchange energy with, and transmit energy for any person upon reasonable request therefor; and to furnish and maintain such services and facilities as shall promote the safety, comfort, and convenience of all its customers, employees, and the public, and shall be in all respects adequate, efficient, and reasonable. * * * SEC. 203. (b) Whenever the Commission after notice and opportunity for hearing finds such action necessary or desirable in the public interest, it may by order direct a public utility to make additions, extensions, repairs, or improvements to or changes in its facilities, to establish physical connection with the facilities of one or more other persons, to permit the use of its facilities by one or more other persons, or to utilize the facilities of, sell energy to, purchase energy from, transmit energy for, or exchange energy with, one or more other persons. Where any such order affects two or more persons, the Commission may prescribe the terms and conditions of the arrangement to be made between such persons, including the apportionment of cost between them and the compensation or reimbursement reasonably due to any of them. [238/] 237/ Otter Tail, 410 U.S. at 374. 238/ H.R. 5423, 74th Cong., 1st Sess., 32 (emphasis added). Docket Nos. RM95-8-000 - 125 - and RM94-7-001 This initial bill proposing the Public Utility Holding Company Act also included a Title III that was intended to regulate the transmission and sale of natural gas. Sections 303(a) and 304 of Title III included the identical common carrier language paraphrased by the Supreme Court and included in sections 202(a) and 203(b) of Title II. 239/ After further deliberations, Congress rejected the above-quoted language in Title II and eventually adopted a Title II that did not include any common carrier language. On the other hand, Title III (addressing regulation of natural gas) was not reported out of committee, but reemerged in the next year. 240/ The bill that reemerged did not contain the common carrier language that was in the original Title III. However, as Congress had just debated the common carrier issue in enacting electric power 239/ Id. at 44. 240/ In the debate on the subsequent bill to regulate natural gas, Congressman Cole explained: Mr. Chairman, the House should realize that the measure we are dealing with today is of extreme importance, more so than the attendance and the time taken in the discussion would seem to indicate. It is the culmination of one of the most far-reaching, intensive studies of the Federal Trade Commission I assume that that Commission ever conducted, and last year found a place in not identical language but very similar in the Rayburn bill, the famous holding-company bill, as part 3 thereof. Our committee eliminated part 3, as members will recall, and saved it for a separate measure reported out as it was last year, which was not considered by the House, but is here today in improved form. 81 Cong. Rec. H6724 (daily ed. July 1, 1937). Docket Nos. RM95-8-000 - 126 - and RM94-7-001 regulation, it is not surprising that Congress did not engage in debating the very same issue in enacting natural gas regulation. Because of the timing of the legislation involving the FPA and the NGA and the logical nexus between the two acts, we conclude that there is in fact no material difference as to this issue in the legislative histories of the two acts. Both initially included identical common carrier language, and the language was removed from both. As to both acts, Congress chose not to impose common carrier obligations on the electric or natural gas industries, but gave the Commission the authority and responsibility to eliminate undue discrimination in both industries. Consequently, as open access was found to be a proper remedy for undue discrimination in the natural gas industry, it is also a proper remedy for undue discrimination in the electric industry. As the AGD court noted with respect to the Commission's powers and duties under the NGA, Congress explicitly gave the Commission the authority to eradicate undue discrimination under the FPA. That explicit power and duty provided by Congress cannot be invalidated solely on the ground that Congress chose not to impose statutory common carrier status on public utilities or did not explicitly authorize the Commission to do so. 241/ As the AGD court explained, this would "turn[] statutory construction upside down, letting the failure to grant a general 241/ AGD, 824 F.2d at 998. Docket Nos. RM95-8-000 - 127 - and RM94-7-001 power prevail over the affirmative grant of a specific one." 242/ Other Case Law A number of commenters argue that the Commission misinterpreted the other cases discussed in the NOPR with respect to our authority to order non-discriminatory open access transmission. We disagree. As demonstrated above, not one of the cases put forth by commenters holds that we cannot remedy undue discrimination by requiring public utilities to provide non-discriminatory open access transmission. 243/ AGD is the only case in which a court specifically addressed our authority to order open access transmission as a remedy for undue discrimination. Its favorable finding with respect to our action under section 5 of the NGA directly supports our ordering non-discriminatory open access transmission under section 206 of the FPA. Authority to Act by Rule We disagree with those commenters that assert that we may find and remedy undue discrimination only through case-by-case adjudications and are prohibited from making a generic determination of undue discrimination through a rulemaking. 242/ Id. 243/ See FERC Stats. & Regs. at 33,053-56. We further note that the AGD court did not discuss the NYSEG decision at all. Indeed, the NYSEG case did not involve any allegations of undue discrimination and any discussion of section 206 by the court was dictum. Docket Nos. RM95-8-000 - 128 - and RM94-7-001 First, there is no question that it is within our discretion whether we act through rule or through case-by-case adjudications. 244/ The AGD court specifically rejected a similar argument that the Commission erred in requiring open access transportation tariffs without first finding that each individual pipeline's rates were unlawful. The AGD court held that "[t]he Commission is not required to make individual findings if it exercises its  5 authority by means of a generic rule." 245/ We have identified a fundamental generic problem in the electric industry: owners, controllers and operators of monopoly transmission facilities that also own power generation facilities have the incentive to engage, and have engaged, in unduly discriminatory practices in the provision of transmission services by denying to third parties transmission services that are comparable to the transmission services that they are providing, or are capable of providing, for their own power sales and purchases. These practices drive up the price of electricity and hurt consumers. Furthermore, the incentive to engage in such 244/ See, e.g., NLRB v. Bell Aerospace Company, 416 U.S. 267, 293 (1974) (citing SEC v. Chenery Corporation, 332 U.S. 194, 202-03 (1947). See also Heckler v. Campbell, 461 U.S. 458, 467 (1983) (even where enabling statute requires a hearing to be held, agency may rely on its rulemaking authority); Panhandle Eastern Pipeline Company v. FERC, 907 F.2d 185, 187-88 (D.C. Cir. 1990). Under section 403 of the DOE Act, 42 U.S.C.  7173, the Commission is authorized at its discretion to initiate rulemaking proceedings. 245/ AGD, 824 F.2d at 1008. Docket Nos. RM95-8-000 - 129 - and RM94-7-001 practices is increasing significantly as competitive pressures grow in the industry. It is within our discretion to conclude that a generic rulemaking, not case-by-case adjudications, is the most efficient approach to take to resolve the industry-wide problem facing us. b. Undue Discrimination/Anticompetitive Effects Initial Comments A number of commenters allege that the Commission has failed to meet its burden of proving industry-wide discrimination. 246/ They assert that the Commission has provided only a few unsubstantiated allegations of discrimination, which do not represent the current conditions in the electric industry, or that the Commission has not shown that all electric utilities have unduly discriminated. Some attack the NOPR's incorporation by reference of the unsubstantiated allegations of discrimination set forth in a petition for rulemaking filed on February 16, 1995 by the Coalition for a Competitive Electric Market (CCEM). 247/ EEI argues that the allegations of discrimination in the NOPR must be considered in light of the fact that: (1) all tariffs currently on file have been found by the Commission not to be discriminatory; (2) more than 30 utilities have voluntarily filed open access tariffs, which belies any assertion of 246/ E.g., EEI, Ohio Edison, PA Com, BG&E, NY Com, Minnesota P&L, Carolina P&L. 247/ E.g., EEI, BG&E. Docket Nos. RM95-8-000 - 130 - and RM94-7-001 widespread discrimination in the industry; and (3) transmission disputes are rare, with only 19 section 211 proceedings having been filed in the last three years. 248/ EEI concludes that the Commission's allegations of discrimination do not rise to the level of "extreme circumstances" found by the court in the natural gas industry in AGD. EEI adds that the Commission's proposal to act under section 206 is itself discriminatory because it applies only to public utilities and does not reach all transmission-owning utilities. 249/ If reciprocity is designed to resolve this problem, EEI believes that reciprocity should also be "effective for public utilities." Furthermore, EEI argues that the failure of a public utility to provide to others a service that it does not provide itself is not evidence of discrimination, and that inclusion of such a provision actually results in preferential treatment for transmission users. NE Public Power District alleges that the NOPR does not contain a single reference to any actual discrimination or anticompetitive conduct by any publicly owned utility. Salt River asserts that the Commission is required to consider all elements of an antitrust analysis before reaching a conclusion that market power exists in the transmission system 248/ See also Ohio Edison. 249/ See also SCE&G. Docket Nos. RM95-8-000 - 131 - and RM94-7-001 and that we have failed to do so. 250/ It concludes that the NOPR "constitutes an attempt to legislate a remedy for an evil that has not been, and cannot be, lawfully found to exist on a wholesale basis among utilities that own and operate integrated generation and transmission systems." 251/ PA Com argues that the Commission's request for examples of discriminatory behavior is a "tacit admission as to the paucity of evidence of discriminatory practices by transmission owning utilities." NY Com argues that the "Commission's lack of a record basis for its proposed findings is legally suspect because courts in two cases have held that the Commission cannot proceed with open access transmission tariffs absent record findings of specific anticompetitive conduct." 252/ Finally, EEI claims that even if the Commission has proven its allegations of discrimination, we have failed to meet the requirements of section 206 of the FPA. 253/ According to EEI, the Commission cannot find, without an adjudicatory hearing, that the rates on file are unlawful and order replacement rates. 254/ The Commission's proposed procedure would unlawfully place the burden of justifying existing rates on the utilities. 250/ Salt River Initial Comments at 5-6 (referencing an attached legal memorandum of Donald A. Kaplan). 251/ Salt River Initial Comments at 6. 252/ NY Com Initial Comments at 16-18 (discussing FPL and Cajun). 253/ See also Southern. 254/ See also Southern. Docket Nos. RM95-8-000 - 132 - and RM94-7-001 Reply Comments A number of commenters provide instances of discriminatory behavior they have faced over the years. NCMPA describes difficulties it has faced in dealing with CP&L, including a situation where CP&L allegedly impeded NCMPA's use of transmission access through CP&L's control of dispatching. 255/ AMP-Ohio alleges that Toledo Edison refused to transmit emergency power on a buy-sell basis to certain AMP-Ohio members even though Toledo Edison's system was not constrained. Instead, AMP-Ohio alleges, Toledo Edison bought the power and resold it to AMP-Ohio at a higher rate. APPA challenges EEI's claim that there is no substantial evidence of undue discrimination in transmission. It suggests that nineteen instances of transmission disputes being filed since the Energy Policy Act was enacted is ample evidence of undue discrimination. Moreover, according to APPA, reported abuses are only the tip of the iceberg. CCEM responds to the argument raised by EEI and others that there is no showing of extreme circumstances of discrimination in the electric industry such as the AGD court noted in the gas industry. It says that these circumstances are present and gives numerous examples; it does not identify the specific utilities because "it is the experience of . . . [our] members that nearly 255/ We note that CP&L raised legal objections to our authority to implement this rule. Docket Nos. RM95-8-000 - 133 - and RM94-7-001 all transmission owners retaliate . . ." against anyone who complains. Moreover, in answer to EEI's statement that transmission disputes are rare, CCEM states that since most of the competition is in the short-term market, it has not been worthwhile to file complaints. The examples provided by CCEM include: (1) refusal by a California public utility to offer firm service; (2) refusal by control area utilities in Texas to offer ancillary services to a power marketer, with the result that one of the utilities won the bid, even though it did not have the lowest price; (3) non-utilities in ERCOT being unable to compete to meet short-term requests for economy energy because they were required to schedule by noon of the preceding day, while utilities did not subject themselves to such a scheduling requirement; (4) power pool or control area information requirements, particularly in the northwest part of WSPP, that force non-utilities to reveal commercially sensitive information; the transportation operator has then revealed the information to its own or its affiliate's sales arm, which "steals" the deal; (5) a northeast power pool that refused to wheel out even though capacity was available on the grounds that sending power out of the pool would drive up prices in the pool (hoarding); (6) a power marketer that asked a utility to provide transmission, whereupon the utility bought up certain transmission capacity necessary for the marketer to reach its buyer, thus blocking the path -- this was possible because the utility was able to locate the purchaser based on commercially sensitive information the Docket Nos. RM95-8-000 - 134 - and RM94-7-001 marketer had to give the utility when the marketer asked for transmission; (7) a common contracting practice among utilities restricting the use of interconnections to themselves, particularly in the Southwest Power Pool, MAPP, and MAIN; (8) utilities overstating the cost of improvements (gold-plating) and thus discouraging service. CCEM also responds to each of EEI's criticisms of CCEM's examples of undue discrimination submitted in its February 16, 1995 petition and argues that its examples of undue discrimination are unrebutted. Brownsville asserts that while PUB [Brownsville] must pay multiple distance-based and pancaked transmission rates to engage in transactions with the non- ERCOT universe, El Paso Electric would have received transmission payments from its merger partners while gaining free transmission access to buy and sell within ERCOT. CSW presently walls other ERCOT utilities off from participation in the Western Systems Power Pool, while its ERCOT subsidiaries, CPL and WTU, share in the benefits of their non-ERCOT affiliates' WSPP memberships via the preferential terms of the CSW Operating Agreement. CSW treats its own inter-affiliate central dispatch as having a higher priority than third-party economy energy transactions, with the result that CPL not infrequently crowds PUB out of the economy market. [256/] Wisconsin Municipals states that its members have been fighting transmission battles for years and sets forth five examples of the sort of difficulties it has experienced in attempting to obtain transmission rights. For example, it 256/ Brownsville Reply Comments at 2-3 (emphasis in original). Docket Nos. RM95-8-000 - 135 - and RM94-7-001 explains that Wisconsin public utilities have resisted an effort by the state commission to achieve comparability of use of transmission. Wisconsin Municipals also explains a situation where "if WPPI continued to purchase its power from WPSC, it would pay WPSC $843,840 annually for transmission service: if it purchases power off system from WP&L (one of WPSC's competitors), WPPI would pay WPSC $1,774,224 for transmission service to the exact same load." TAPS sets forth additional examples of undue discrimination, including refusals to wheel even in the face of Nuclear Regulatory Commission (NRC) nuclear license conditions requiring wheeling, and Northeast Utilities' refusal to provide transmission to a QF even though it had indicated to the Commission that it would provide such transmission in order to obtain Commission approval of its proposed merger with Public Service Company of New Hampshire. NIEP sets forth ten examples of undue discrimination that its members have experienced in seeking access to transmission service at reasonable terms and conditions. Some commenters challenge these claims of undue discrimination. For example, Carolina P&L responds to NCMPA #1's example of obstruction by Duke in accommodating energy sales from the jointly owned Catawba Plant. Carolina P&L explains that NCMPA #1's proposal "would require Duke to provide its own generation resources on behalf of NCMPA #1 in order to support a bulk power sale when NCMPA #1's own resource capacity and energy Docket Nos. RM95-8-000 - 136 - and RM94-7-001 are not sufficient for the sale." Carolina P&L argues that this is backstanding that goes beyond the scope of any ancillary service the Commission has proposed and would be entirely inappropriate "to compel the Transmission Provider to sell power to its Transmission Customer for resale on the bulk power market." Duke also responds to NCMPA #1's claim of discrimination and asserts that NCMPA #1's claim is not relevant to the NOPR proceeding, but is a specific contractual claim that should be pursued pursuant to the terms of its contract. Commission Conclusion We conclude that unduly discriminatory and anticompetitive practices exist today in the electric industry and, more importantly, that such practices will increase as competitive pressures continue to grow in the industry, unless the Commission acts now to prevent such practices. 257/ It is in the economic self-interest of transmission monopolists, particularly those with high-cost generation assets, to deny transmission or to offer transmission on a basis that is inferior to that which they provide themselves. The inherent characteristics of monopolists make it inevitable that they will act in their own self-interest to the detriment of others by refusing transmission 257/ While many public utilities have filed some form of open access tariff (often in response to our proposed rule), we believe that many of the remaining utilities will not voluntarily open their systems absent a final rule. See also note 266. Docket Nos. RM95-8-000 - 137 - and RM94-7-001 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." 258/ We set forth examples in the NOPR of undue discrimination that we believe are occurring in the electric industry and invited commenters to identify any discrimination that they may have experienced. In response, commenters presented numerous additional examples of undue discrimination, which are summarized above, and we set forth below further examples of undue discrimination that have been raised in cases before the Commission. Many of the examples of discriminatory behavior that have been brought to our attention do not name the specific utilities involved, and many are allegations that are not proven. However, we do not believe that this undermines our finding of unduly discriminatory practices by transmission owners and controllers. We believe that it is only natural that potential transmission customers with an interest in participating in electric markets will be reluctant to name names for fear of being shut out of those markets. CCEM, which identified a wide array of 258/ AGD, 824 F.2d at 1008. Docket Nos. RM95-8-000 - 138 - and RM94-7-001 discriminatory behavior its members have experienced, explained that [w]e do not identify the specific utilities in each example because it is the experience of CCEM members that nearly all transmission owners retaliate by cutting off all communications with anyone that challenges or complains about the rates, terms or conditions at which the owner offers access to its system. Inasmuch as most of the competitive commerce in electric power today is in short-term markets, it is typically not worth the effort of CCEM members or other transmission-dependent entities to file a complaint with the Commission's enforcement staff or in the courts in connection with a transmission owner's discriminatory practices. The deal is lost well before a complaint can be processed and ruled upon. [259/] Other examples of discriminatory behavior have also been raised in proceedings before the Commission. As we explained in detail in the NOPR, transmission-owning utilities have discriminated against others seeking transmission access in a variety of ways, most often subtly and indirectly. 260/ For example, delaying tactics have been used to frustrate access. The history of Pacific Gas and Electric Company's (PG&E) attempt to avoid its commitments made to the California owners of the California-Oregon Transmission Project (COTP) is a prime example. The owners had originally planned the COTP to have its southern terminus at the Midway station with Southern California Edison. 259/ CCEM Initial Comments at 18-19. See also NIEP Reply Comments at 13 n.31. 260/ FERC Stats. & Regs. at 33,072. Docket Nos. RM95-8-000 - 139 - and RM94-7-001 PG&E convinced them to terminate the project instead at PG&E's Tesla station and indicated that PG&E would provide transmission service the rest of the way south to Midway. PG&E promised this service in 1989 (in Principles). PG&E spent the next four years filing substitute provisions for what it had promised in the Principles. 261/ Additional allegations of discriminatory behavior are set forth in Appendix C, which includes allegations made under oath in proceedings at the Commission and allegations made in pleadings and other documents before the Commission. In addition, to date, the Commission has received 28 section 211 transmission requests. 262/ Applicants submit section 211 transmission requests when the transmission provider refuses to provide the requested transmission service. For example, American Municipal Power-Ohio, Inc. (AMP-Ohio) requested Ohio Edison Company (Ohio Edison) to establish additional delivery points to certain of AMP-Ohio's members and to permit the addition of delivery points in the future upon AMP-Ohio's request. Ohio Edison refused AMP-Ohio's request, claiming that it was not a proper request under section 211 because it already provided wholesale transmission to the municipal utilities at issue. In a proposed order, the Commission disagreed with Ohio 261/ See Pacific Gas and Electric Company, 65 FERC  61,312 at 62,428-30 and n.22, remanded on other grounds, Pacific Gas & Electric Company v. FERC, No. 94-70037 (9th Cir. June 23, 1994)(unpublished opinion), order on remand, 69 FERC 61,006 (1994). 262/ A list of section 211 applications and the status of each is attached as Appendix A. Docket Nos. RM95-8-000 - 140 - and RM94-7-001 Edison and ordered Ohio Edison to provide the requested additional delivery points and to entertain future requests by AMP-Ohio for specific delivery points. 263/ Many of the examples of discriminatory actions we are seeing in the electric industry are similar to those we saw in the gas industry. Given our experience, we find that these examples of discriminatory actions are credible and well-founded. Thus, we conclude that there is more than sufficient reason to believe that transmission monopolists currently engage in unduly discriminatory practices, and that they will continue to engage in unduly discriminatory practices, unless we fashion a remedy to eliminate their ability and incentive to do so. In light of the competitive changes occurring in today's electric industry, we believe that the only effective remedy is non-discriminatory open access transmission, including functional unbundling and OASIS requirements, and that it is within our statutory authority to order that remedy. Further, we disagree with the argument that we are limited to applying a traditional antitrust analysis in determining whether market power exists in the transmission system. While we must take antitrust concerns into consideration in exercising our responsibilities under the FPA, we are not an antitrust court, and our responsibilities are not those of the Department of 263/ American Municipal Power-Ohio, Inc. v. Ohio Edison Company, 74 FERC  61,086 (1996). Docket Nos. RM95-8-000 - 141 - and RM94-7-001 Justice. 264/ We have analyzed the incentives and practices of monopoly transmission owners and controllers in light of the statutory standards and directives of the FPA and, based on our findings, have properly concluded that there is a generic problem that must be remedied. The Commission also recognizes, as some commenters suggest, that we have, in the past, permitted utilities to file tariffs containing restrictions on transmission service that we are now finding to be unduly discriminatory in this rule and that we found unduly discriminatory in cases since our decision in AEP. However, it is entirely appropriate, and indeed necessary, that our application of the FPA's undue discrimination standard evolve over time and adapt to the changing circumstances in the industry. Our prior willingness to tolerate the use of monopoly power over transmission to maintain and aggregate the utility's market power over generation occurred in the context of an industry structured largely as vertically integrated regulated monopolies that supplied all facets of utility service -- power supply, transmission, and distribution -- as a single monopoly service. Competition generally was not meaningfully available as a means to discipline prices and consumer interests were best served by improving efficiencies of the integrated utilities, subject to cost-based regulation. 264/ See, e.g., Gulf States Utilities Company v. FPC, 411 U.S. 747, 758-60 (1973); FPC v. Conway Corporation, 426 U.S. 271, 279 (1976); Northern Natural Gas Company v. FPC, 399 F.2d 953, 960 (D.C. Cir. 1968). Docket Nos. RM95-8-000 - 142 - and RM94-7-001 Today, the circumstances of the industry are radically different. As explained in detail in Section III, a series of significant economic, regulatory, and technical changes in the power industry has introduced the promise of competitively priced power supplies. The profile of electric power suppliers has expanded to include not just the power supply arms of traditional utilities, but also independent power suppliers, affiliated utility power suppliers selling into territories of other franchise utilities, and power marketers. 265/ This offers the promise of an increasingly competitive commodity market in electric power, in which significant benefits to consumers can be achieved. In the context of an emerging competitive market in generation, discriminatory practices that once did not constitute undue discrimination must be reviewed to determine whether they are being used to prevent the benefits of competition in generation from being achieved. Here we find conclusively that they are, and use our remedial authority to ensure that they can no longer occur. 266/ 265/ We note that there are now 14 power marketers that are affiliated with public utilities. 266/ We take note of EEI's comments that, at the time of the comments, 30 utilities had filed open access tariffs. They argue, therefore, that the rule is unnecessary. Since their comment was filed, the number of utilities filing some form of an open access tariff has risen to 106. However, while some of these tariffs are based on the NOPR pro forma tariffs, many of these tariffs fall significantly short of the tariff requirements of both the NOPR and this Rule. Even if the tariffs met these requirements, the Rule is still needed to complete the task of eliminating undue (continued...) Docket Nos. RM95-8-000 - 143 - and RM94-7-001 c. Section 211 Comments Various commenters contend that the enactment of section 211 in essence either removed any authority the Commission might have had under sections 205 and 206 or demonstrates that Congress did not believe the Commission could order wheeling under those provisions. These commenters assert that the legislative history of the FPA indicates that Congress specifically rejected giving the Commission authority to order wheeling under any circumstances. 267/ They further contend that the legislative history of section 211 demonstrates that Congress viewed the authority it granted in section 211 as a strictly limited and entirely new authority for the Commission. 268/ Specifically, EEI states that the legislative history of the Energy Policy Act confirms that the expanded authority provided under section 211 was not intended to grant the Commission blanket authority to order 266/(...continued) discrimination by all public utilities and assuring, to the extent possible, a nationwide open access transmission grid. Indeed, a number of these tariffs were filed for the purposes of securing authority to market power competitively. This underscores markedly our fundamental conclusion that prior practices of using monopoly power over transmission to preserve market power over electricity sales has no place in today's industry and must be eliminated to get the benefits of competition to the customers we are required to protect under the FPA. 267/ E.g., EEI, VA Com, Ohio Edison Southern, Utilities For Improved Transition, BG&E. 268/ See also NM Com. Docket Nos. RM95-8-000 - 144 - and RM94-7-001 wheeling, even as a remedy for anticompetitive conduct. Similarly, Utilities For Improved Transition argues that the legislative history shows that Congress specifically intended to preclude the Commission from ordering tariffs of general applicability under any circumstances. In addition, EEI points to testimony provided by a Commission staff witness before the Subcommittee on Energy and Power of the House Committee on Energy and Commerce in which EEI claims that "she suggested that an affirmative statement that the Commission had the power to require wheeling on its own motion should be included, possibly in section 211." EEI maintains that such suggestion was rejected by Congress in favor of allowing the Commission to order wheeling only upon application. Detroit Edison, asserting that Cajun stands for the proposition that the agency must follow Congressionally mandated procedures, claims that the Commission can order transmission only after going through the procedures of section 211. Detroit Edison also argues that the Commission should incorporate into the final rule the various safeguards of section 211, such as the requirement that the utility receive prior notice, the requirement that transmission service be in the public interest, and the requirement that existing service not be displaced. FL Com further asserts that it was Congressional intent in the Docket Nos. RM95-8-000 - 145 - and RM94-7-001 Energy Policy Act for wheeling to be ordered on a case-by-case basis pursuant to section 211. 269/ EEI argues that the enactment of section 211 eliminated any authority the Commission had under sections 205 and 206 to order wheeling as a remedy for undue discrimination. It alleges that the Commission failed to discuss the NYSEG case concerning the relationship between section 211 and sections 205 and 206 in any meaningful way. According to EEI, the NYSEG court concluded that section 211 "was the only appropriate vehicle under which the Commission could order NYSEG to wheel power for the municipality." 270/ EEI further resorts to canons of statutory construction to conclude that "section 211 must be given effect as the more specific provision and must be 269/ See also Salt River. Moreover, FL Com states that the Commission should modify its hearing process to better accommodate state PUC participation by: (1) holding hearings in the affected state; (2) teleconferencing; (3) making free transcripts available to states; and (4) substantially deferring to a state when the state commission has held a hearing on an issue in the case. 270/ EEI quoted the following language from NYSEG: Nor do we suggest that the Commission is powerless to review a wheeling agreement under  206 without following the requirements of  211 and 212. If, after a hearing as required by  206, the Commission determines that a particular rate, charge or condition is unreasonable, it can order a modification. But where, as here, the modification amounts to an order requiring wheeling, it must be preceded also by determination in accordance with  211 and 212. Simply put, we will not allow the Commission to do indirectly without compliance with the statutory prerequisites, what it could not do directly without such compliance. [citing Richmond Power & Light]. Docket Nos. RM95-8-000 - 146 - and RM94-7-001 interpreted to limit the scope of sections 205 and 206." 271/ In addition, EEI asserts that "Congress had an opportunity to reject the NYSEG court's interpretation of the scope of sections 205, 206 and 211, but instead amended section 211 in a manner that is consistent with the view that mandatory wheeling is to be governed exclusively by section 211." Dayton P&L raises similar arguments. It notes the savings provision in section 212(e), but says that Congress "would have been more specific if it understood that the Commission already had the authority to order wheeling under FPA sections 205 and 206. . . ." 272/ Associated EC argues that the NOPR appears to exceed the Commission's authority in that it proposes that "wholesale buyers and sellers have 'equal access to the transmission grid.'" It asserts that "Section 211(a), however, makes mandatory transmission service available only to '[a]ny electric utility, Federal power marketing agency or any other person generating electric energy for sale for resale.'" 273/ 271/ See also VA Com. 272/ See also Carolina P&L. 273/ This argument is puzzling. First, section 211 does not control to whom access must be provided under sections 205 and 206. However, even if it did, Associated EC appears to misconstrue eligibility under section 211. An electric utility as defined in the FPA is any person or State agency (including any municipality) which sells electric energy. The definition does not say that electric energy must be re- sold at wholesale. Thus, an electric utility could be a wholesale buyer of transmission used to transmit energy for sale at either wholesale or retail. Docket Nos. RM95-8-000 - 147 - and RM94-7-001 NE Public Power District argues that sections 211 and 212 of the FPA appear clearly to contemplate a case-by-case approach. 274/ NE Public Power District adds that if the Commission believes sections 211 and 212 are inconsistent with the public interest, it can ask Congress to modify those provisions. Allegheny adds that the Commission can order wheeling only under sections 211 and 212 on a company-specific basis and can use sections 205 and 206 only to evaluate the reasonableness of terms and conditions of voluntarily filed agreements or tariffs by public utilities. Utilities For Improved Transition also claims that sections 211 and 212 override any authority the Commission might have had under sections 205 and 206 to order industry-wide open access. It cites the savings clause in section 212(e) of the FPA as limiting the Commission's authority to order transmission. 275/ Utilities For Improved Transition argues at some length that the NOPR does not meet the procedural and substantive 274/ See also Allegheny. 275/ It states that Section 212(e), however, provides that Sections 211 and 212 limit or impair the Commission's authority under "other provisions of law" (a phrase including, obviously, Sections 205 and 206). On the face of the statute -- we say again for emphasis: on the face of the statute -- the Commission therefore does not have the authority to order transmission service outside the provisions of Sections 211 and 212. Utilities For Improved Transition Initial Comments at 51 (emphasis in original). Docket Nos. RM95-8-000 - 148 - and RM94-7-001 standards of sections 211 and 212. It goes on to cite various passages from the legislative history of the Energy Policy Act as supporting the view that Congress intended to eliminate the Commission's authority to order industry-wide open access as a remedy for undue discrimination. According to Utilities For Improved Transition, these passages "unmistakably show a clear legislative intent to preclude the mandatory transmission that the Commission attempts here. . . ." Commission Conclusion We disagree with those commenters that argue that the Energy Policy Act either eliminates our authority under section 206 to remedy undue discrimination by requiring non-discriminatory open access transmission or demonstrates that we never had any such authority. Nothing in sections 211 and 212 or in the legislative history of these sections indicates that Congress intended to eliminate the Commission's other, broader authorities under the FPA. Indeed, section 212(e) specifically provides: SAVINGS PROVISIONS. -- (1) No provision of section 210, 211, 214, or this section shall be treated as requiring any person to utilize the authority of any such section in lieu of any other authority of law. Except as provided in section 210, 211, 214, or this section, such sections shall not be construed as limiting or impairing any authority of the Commission under any other provision of law. [276/] Utilities For Improved Transition's argument that the "Except as provided" clause limits or impairs the Commission's 276/ 16 U.S.C  824k (emphasis added). Docket Nos. RM95-8-000 - 149 - and RM94-7-001 authority to order transmission service under sections 205 and 206 would make the savings provision meaningless. Moreover, such a reading would be entirely at odds with the underlying purposes of the Energy Policy Act. It would be ironic indeed to interpret the Energy Policy Act as eliminating our long-standing, broad authority to remedy undue discrimination, given the pro- competitive purpose of the statute. The legislative history also provides no support for the arguments that sections 211 and 212 remove or prove the non- existence of the Commission's authority to remedy undue discrimination by requiring non-discriminatory open access transmission. In fact, virtually every bit of legislative history raised by commenters opposing the NOPR consists of various statements by Senator Wallop, an opponent of expanding transmission access under sections 211 and 212. 277/ Such 277/ In discussing the electricity provisions of the Energy Policy Act, Senator Wallop declared: It would be a mistake to take the presence of transmission access provisions in the Conference Report as a sign of change in position on my part or that of the Senate. I would have strongly preferred PUHCA reform without any transmission access provisions, as was the Senate position. However, in order to obtain the very significant benefits of PUHCA reform contained in the Senate bill, it was necessary to accept some of the House transmission access provisions. 138 Cong. Rec. S17615 (daily ed. October 8, 1992). Docket Nos. RM95-8-000 - 150 - and RM94-7-001 legislative history provides no insight into the meaning of a statute and is given little or no weight by the courts. 278/ The only other legislative history that commenters put forth is the testimony of a Commission staff witness, in 1992 hearings before the Subcommittee on Energy and Power of the House Committee on Energy and Commerce. According to EEI, the witness indicated that an affirmative statement that the Commission could require wheeling on its own motion "would be needed [in the Energy Policy Act] 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." EEI claims that this statement demonstrates that the expanded authority in the Energy Policy Act "was not intended to grant the Commission blanket authority to order wheeling, even as a remedy for anticompetitive conduct." EEI's argument is misleading and disingenuous. It takes the witness's statements out of context, ignoring attendant testimony that "there are strong legal arguments that the Commission's 278/ See, e.g., Shell Oil Company v. Iowa Department of Revenue, 488 U.S. 19, 29 (1988) (Shell). In Shell, the Court declared: This Court does not usually accord much weight to the statements of a bill's opponents. "[T]he fears and doubts of the opposition are no authoritative guide to the construction of legislation." Gulf Offshore Co. v. Mobil Oil Corp., 453 U.S. 473, 483 (1981) (quoting Schwegmann Bros. v. Calvert Distillers Corp., 341 U.S. 384, 394 (1951). See also Sutherland Statutory Construction  48.16 at 366. Docket Nos. RM95-8-000 - 151 - and RM94-7-001 obligation to protect against undue discrimination carries with it the authority to impose transmission requirements as a remedy for undue preference or discrimination," and the extensive legal argument, included in her testimony, in favor of that position -- an argument that closely parallels the legal argument the Commission is relying on in this proceeding. 279/ Indeed, in the face of such explicit testimony from the staff of the agency required to implement the statute, had Congress intended to limit the Commission's remedial authority under section 206 when it amended section 211, we believe it would have explicitly done so in the language of the statute itself, or at least have indicated its intent to do so in the Conference Report on the Energy Policy Act. 280/ 279/ 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 and 61-70. See also id. at 106 ("I believe that we have substantial authority under the existing case law to mandate access where necessary to remedy anticompetitive effects."). 280/ At the time Congress enacted amendments to FPA section 211, it was well aware that the Commission had unexplored authorities under sections 205 and 206 of the FPA to compel wheeling. The only explicit limitations it chose to impose on the Commission's wheeling authorities were those contained in sections 212(g) and (h), which provide that no order "under this Act" may be inconsistent with any State law governing retail marketing areas of electric utilities (section 212(g)), or be conditioned upon or require the transmission of electric energy directly to an ultimate consumer (section 212(h)). Docket Nos. RM95-8-000 - 152 - and RM94-7-001 C. Comparability 1. Eligibility to Receive Non-discriminatory Open Access Transmission In the NOPR, the Commission proposed to define who is eligible to receive service under a non-discriminatory open access tariff as follows: A non-discriminatory open-access tariff must be available to any entity that can request transmission services under section 211. [281/] The Commission further explained that "[u]nder section 211, any electric utility, Federal power marketing agency, or any other person generating electric energy for sale for resale may request transmission services under section 211." 282/ Comments PSNM believes that the NOPR properly defined customer eligibility. NIEP, on the other hand, believes that the proposed definition is too limited. It argues that the Commission should require public utilities to make transmission service available to all entities engaged in wholesale purchases or sales of power, not just to those "generating" power. Utility Working Group requests that the Commission clarify that eligibility is dependent not only on being the type of entity set forth in section 211, but on meeting the requirements of section 212(h) 281/ FERC Stats. & Regs.  32,514 at 33,083 (footnote omitted). 282/ Id. at 33,083 n.195. Docket Nos. RM95-8-000 - 153 - and RM94-7-001 (Prohibition on Mandatory Retail Wheeling and Sham Wholesale Transactions) as well. 283/ We also received several comments related to the applicability of the rule to foreign entities. Canada states that the requirements for comparability and reciprocity should be implemented in a flexible manner to permit Canadian utilities to have fair and competitive access in the U.S. electricity market. Maritime requests that the Commission require Canadian utilities who wish to participate in the U.S. market to offer other utilities the same privileges they receive in the United States. Southwestern argues that transmission to a foreign country is in interstate commerce and that a utility should therefore accommodate this type of transmission request under its open access tariff. El Paso argues that the Commission does not have the authority to condition access to foreign countries, but states that if the Commission nevertheless exercises such authority it should do so on a case-by-case basis. Destec asserts that the posturing of Ontario Hydro before U.S. regulators pleading for open access and non- discriminatory transmission treatment -- even for extra-territorial entities, should be met with a strong reply that such provisions should also be afforded transmission dependent entities on the Canadian side of the border. Ontario Hydro's aggressive pursuit of U.S. market opportunities while simultaneously blocking competitors through 283/ Section 212(h) (Prohibition on Mandatory Retail Wheeling and Sham Wholesale Transactions). Docket Nos. RM95-8-000 - 154 - and RM94-7-001 the control of their transmission assets can not be ignored. Commission Conclusion In the Final Rule pro forma tariff the Commission has modified the definition of "eligible customer" to address concerns that in some respects the NOPR definition was too limited and in other respects it was too broad. This includes amended language to clarify that any entity engaged in wholesale purchases or sales of energy, not just those "generating" electric power, is eligible. It also includes clarification 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. The language also has been modified to provide that foreign entities that otherwise meet the eligibility criteria may obtain transmission services. Further, it has been modified to provide for service to retail customers in circumstances that do not violate FPA section 212(h). 284/ Persons that would be eligible section 211 applicants also would be eligible under the open access tariffs. Section 211 applicants may be any electric utility, Federal power marketing agency, or any other person generating electric energy for sale for resale. 284/ We emphasize that any transmission customer must follow prudent utility practices so as to assure reliability. Docket Nos. RM95-8-000 - 155 - and RM94-7-001 Section 3(22) of the FPA, as amended by the Energy Policy Act, defines "electric utility" to mean any person or State agency (including any municipality) which sells electric energy; such term includes the Tennessee Valley Authority, but does not include any Federal power marketing agency. Thus, as we have previously noted, municipal utilities are electric utilities simply by the terms of the statute. 285/ In addition, we have also found that cooperatives and marketers are electric utilities as defined in the FPA. 286/ Other entities that fall within the definition include IOUs, IPPs, APPs, and QFs that sell electric energy. We do not believe that entities that engage solely in brokering should be eligible. Such brokers do not take title to electricity and therefore do not engage in the sale of electric energy; nor do they generate electric energy for sale for resale. 287/ Although such brokers are not eligible under the tariffs, they will be able to arrange deals because they will have access to the OASIS of all public utilities and will be able to solicit 285/ New Reporting Requirement Implementing Section 213(b) of the Federal Power Act and Supporting Expanded Regulatory Responsibility Under the Energy Policy Act of 1992, and conforming and Other Changes to Form No. FERC-714, Order No. 558-A, 65 FERC  61,324 at 62,451 n.12 (1993). 286/ Order No. 558, FERC Stats. & Regs.  30,980 at 30,895-96, reh'g denied, 65 FERC  61,324 (1993) (cooperatives are electric utilities); AES Power, Inc., 69 FERC  61,345 at 62,297 (1995) (power marketer is an electric utility, i.e., a person "which sells electric energy"). 287/ See, e.g., Citizens Energy Corporation, 35 FERC  61,198 at 61,452-53 (1986). Docket Nos. RM95-8-000 - 156 - and RM94-7-001 information from the relevant transmission service providers under the terms of the applicable tariffs. We clarify that foreign entities that otherwise meet the eligibility criteria must be eligible to receive service under the non-discriminatory open access transmission tariffs. 288/ We are making this determination pursuant to our authority under section 206 of the FPA to remedy undue discrimination. As we explained in the NOPR, market power through the control of transmission can be used discriminatorily to block competition. Customers in the United States should not be denied access to cheaper supplies of electric energy, whether such electric energy is from a domestic source or a foreign source. By making non- discriminatory access available to foreign entities that otherwise meet the eligibility criteria, we are assuring that customers in the United States have access to as many potential suppliers as possible. This should result in increased competition and lead to customers paying the lowest possible prices for their electric energy needs. To the extent that such an entity obtains access, however, we emphasize that it would be subject to all of the terms and conditions of the applicable open access tariff, including the requirement that it provide reciprocal service. 288/ In making this determination, we are not deciding whether these entities are eligible entities under section 211(a) of the FPA. Docket Nos. RM95-8-000 - 157 - and RM94-7-001 Finally, we have reconsidered our NOPR position that would have limited eligibility to wholesale transmission customers. As we explained in the NOPR, the Commission's jurisdiction extends to all unbundled transmission in interstate commerce by public utilities. It is irrelevant to the Commission's jurisdiction whether the customer receiving the unbundled transmission service in interstate commerce is a wholesale or retail customer. Thus, if a public utility voluntarily offers unbundled retail access in interstate commerce or a state retail access program results in unbundled retail access in interstate commerce by a public utility, the affected retail customer must obtain its unbundled transmission service under a non-discriminatory transmission tariff on file with the Commission. Though the Commission may approve a separate retail transmission tariff when some variation is necessary or appropriate to meet local concerns, 289/ we generally see no reason why retail transmission tariffs necessarily must be different from wholesale transmission tariffs. For that reason, we anticipate that in many circumstances the same open access tariff that serves wholesale customers will be equally appropriate for retail transmission customers. Therefore, unless the Commission has specifically permitted a separate retail tariff, eligible customers under the 289/ See Section IV.I. Docket Nos. RM95-8-000 - 158 - and RM94-7-001 Final Rule pro forma tariff must include unbundled retail customers. 290/ We discuss this further in Section IV.I. While the rates, terms, and conditions of all unbundled transmission service will be subject to a Commission-authorized tariff, we will, in appropriate circumstances, give deference to state recommendations regarding rates, terms, and conditions for retail transmission service or regarding the proper transmission cost allocation to be used between retail and wholesale customers when state recommendations are consistent with our open access policies. This is also discussed further in Section IV.I. 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 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. 290/ The Commission has no authority to order retail transmission directly to an ultimate consumer or to order "sham" wholesale transmission. See FPA section 212(h). However, if such access occurs voluntarily or as a result of a state program, the rates, terms, and conditions of the access are within our exclusive jurisdiction if the service is provided by a public utility. Docket Nos. RM95-8-000 - 159 - and RM94-7-001 2. Service that Must be Provided by Transmission Provider In the NOPR, the Commission proposed that a public utility must offer to provide any point-to-point or network transmission service whether or not the utility provides itself that service: The Commission therefore proposes that all public utilities must offer both firm and non-firm point-to- point transmission service and firm network transmission service on a non-discriminatory open access basis in accord with the proposed rule and the attached appendix tariffs. The Commission believes that a utility's tariff must offer to provide any point-to-point transmission service and network transmission service that customers need, even though the utility may not provide itself the specific service requested. [291/] Comments EGA and SMUD agree that a transmission owner should offer any transmission service it is able to provide, even if it does not use the service itself. Public Generating Pool, an association of consumer-owned electric utilities, appears concerned that the Commission may interpret comparability broadly to require a utility to offer the same service provided by another utility or to offer service generally available in a region. Thus, it recommends that a third party seeking more service than a utility provides itself be required to resort to the section 211 process. Commission Conclusion Initially, we note that, with the possible exception of small utilities (which may qualify for a waiver, see infra), we 291/ FERC Stats. & Regs.  32,514 at 33,079. Docket Nos. RM95-8-000 - 160 - and RM94-7-001 have seen no evidence that public utilities are incapable of reasonably providing the services required in the Final Rule pro forma tariff. Nor have we seen evidence that utilities able to provide these services to themselves are choosing to forego such services. In short, we are not convinced that there is an appreciable difference, if any, among the services required in the pro forma tariff, the services utilities are able to provide, and the services they actually provide themselves. To the extent these services do differ, however, we explicitly adopt the proposal set forth in the NOPR. Thus, 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. 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. Moreover, a public utility must offer these transmission services whether or not other utilities may be able to offer the same services and whether or not such services are generally available in the region (waiver of these requirements for small utilities is discussed in Section IV.K.2.). 292/ However, if a customer seeks a customized service not offered in an open access tariff, 292/ Requirements for ancillary services are discussed in Section IV.D. Docket Nos. RM95-8-000 - 161 - and RM94-7-001 a customer may, barring successful negotiation for such service, file a section 211 application. 3. Who Must Provide Non-discriminatory Open Access Transmission In the NOPR, the Commission proposed to require all "public utilities" owning and/or controlling facilities used for transmitting electric energy in interstate commerce to file open access transmission tariffs. 293/ We explained that we could not require all "transmitting utilities" to file open access tariffs under sections 205 and 206 because we do not have jurisdiction over non-public utilities under these sections. Comments Several commenters argue that the open access requirement must be applied to non-jurisdictional utilities that own interstate transmission facilities. 294/ Power Marketing Association recognizes that this raises difficult legal issues and suggests that the Commission support legislation to expand the Commission's authority over non-jurisdictional utilities. Minnesota P&L argues that if the requirement is not applied to all entities that own transmission, jurisdictional and non- jurisdictional entities owning joint transmission facilities will be competitively disadvantaged due to unequal pricing. Union Electric argues that unless the requirement is extended to the 56 293/ FERC Stats. & Regs.  32,514 at 33,049. 294/ E.g., Minnesota P&L, Power Marketing Association. Docket Nos. RM95-8-000 - 162 - and RM94-7-001 non-jurisdictional entities operating control areas, discrimination in the wholesale power markets will increase. A number of municipal commenters assert that the NOPR overlooks transmission assets jointly owned by jurisdictional and non-jurisdictional utilities. 295/ They argue that agreements regarding use of these assets often contain provisions prohibiting third-party power transfers. They further argue that such provisions should be nullified, and the joint owners should be required to develop equitable methodologies to allocate wheeling revenues among themselves. Several cooperatives urge the Commission to clarify that contracts among their constituent cooperatives are not subject to any unbundling of existing contracts. Commission Conclusion Our authority under sections 205 and 206 of the FPA permits us to require only public utilities to file open access tariffs as a remedy for undue discrimination. We have no authority under those sections of the FPA to require non-public utilities to file tariffs with the Commission. However, we are concerned that if non-public utilities do not provide access, there will remain a patchwork of "open" and "closed" transmission systems and the potential for distortions in wholesale bulk power markets. We believe that certain mechanisms exist that will help to alleviate these problems. 295/ E.g., Springfield. Docket Nos. RM95-8-000 - 163 - and RM94-7-001 First, as we explained in the NOPR, broad application of section 211 will provide wider access to bulk power markets. 296/ Under section 211, eligible entities may seek transmission service from "transmitting utilities," which section 3(23) of the FPA defines as "any electric utility, qualifying cogeneration facility, qualifying small power production facility, or Federal power marketing agency which owns or operates electric power transmission facilities which are used for the sale of electric energy at wholesale." We believe that section 211 provides us with authority to require the same quality of transmission service as sections 205 and 206, though the procedural path is more cumbersome. Thus, section 211 provides access to transmission systems owned or operated by non-public utilities. 297/ Second, as we explained in the NOPR, our reciprocity requirement is designed to provide the widest possible use of the nationwide transmission grid: The purpose of this provision is to ensure that a public utility offering transmission access to others can obtain similar service from its transmission customers. It is important that public utilities that are required to have on file tariffs be able to obtain service from transmitting utilities 296/ FERC Stats. & Regs.  32,514 at 33,050 and 33,092-93. 297/ As discussed in the NOPR, sections 211 and 212 require that applicants specify only rates, terms, and conditions of service, not specify transactions. Thus, applicants can file requests for tariffs to accommodate future, currently unspecified transactions, similar to the open access tariffs required by this Rule. Docket Nos. RM95-8-000 - 164 - and RM94-7-001 that are not public utilities, such as municipal power authorities or the federal power marketing administrations that receive transmission service under a public utility's tariff. [298/]. Finally, again as we explained in the NOPR, the formation of RTGs should speed the development of competitive markets and involve more non-public utilities in the provision of non- discriminatory open access transmission. 299/ In approving RTGs, our policy has been to require all members, whether or not they are public utilities, to offer comparable transmission services at least to other members. We recognize that these solutions are not perfect. However, given the difficulties inherent in the statutory scheme, we believe they will go a long way toward effectuating transmission access by non-public utilities. One further issue involving non-public utilities concerns jointly owned transmission facilities. We will not allow public utilities that jointly own interstate transmission facilities with non-jurisdictional entities to escape the requirements of open access. We will require 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. We urge such public utilities to seek 298/ FERC Stats. & Regs.  32,514 at 33,089. 299/ Id. at 33,095. Docket Nos. RM95-8-000 - 165 - and RM94-7-001 mutually agreeable revisions to their agreements to permit third- party access over all, or at least their share, of the facilities. For those joint ownership arrangements that include restrictions on the usage of jointly owned transmission facilities by third parties, we will require 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 its contract with the non- jurisdictional owner(s). This revision must be designed at a minimum to permit third parties to use the public utility's share of the joint facilities in accordance with this Rule and must provide for any needed cost allocation procedures between the public utility and the non-jurisdictional owner(s). 4. Reservation of Transmission Capacity by Transmission Customers In the NOPR, the Commission set forth the information that a requester of transmission service would have to submit with a service request. We recognized that there may have to be a limit, for competitive reasons, on the information required, but also recognized the need to assure that no customer would reserve scarce capacity and then hold it without using it. 300/ To avoid forcing transmission customers to reveal unnecessary details of their purchase or sales transactions, the Commission discussed several less restrictive options: (1) allow the transmission provider to use or sell the capacity while it is 300/ Id. at 33,090. Docket Nos. RM95-8-000 - 166 - and RM94-7-001 unused, (2) have a pool that clears the short-term market, and (3) require the customer to begin using the capacity within some specified period or lose its reservation rights. The Commission requested comments on these and other possible approaches. Comments Unused or unneeded transmission capacity Many commenters recommend a use-it-or-lose-it rule (i.e., a transmission customer must use its reserved transmission capacity or lose its rights to that capacity). 301/ Several commenters also recommend a number of restrictions on capacity reservations to reduce incentives to hoard or to cherry-pick (request to reserve firm capacity only during peak hours of peak seasons) existing transmission capacity. These include: (1) allow requesters to reserve a place in the queue with a right of first refusal over later competing requests; (2) impose a take- or-pay charge on reservations and deny reservation holders the right to revenue sharing if they do not schedule or assign their rights; (3) limit the time period for reservations; (4) limit how far in advance reservations may be made for both non-firm and firm services; (5) maintain a price cap on the resale of transmission; (6) require multi-year reservations to be for sequential periods; and (7) require a nonrefundable fee for 301/ E.g., Consumers Power, Northern States Power, PacifiCorp, Oklahoma G&E, Allegheny Power, ELCON, Public Service Co of CO. Docket Nos. RM95-8-000 - 167 - and RM94-7-001 advance reservations of service. 302/ Southwestern suggests that transmission tariffs include a provision that prevents transmission customers and the transmission provider from reserving and tying up firm transmission capacity for speculative wholesale transactions. 303/ On the other hand, PSNM believes that a use-it-or-lose-it approach is inappropriate because any prudent utility that has reserved capacity would seek to sell the service it is not using so as to recover some portion of its fixed costs. Wisconsin P&L argues that a use-it-or-lose-it approach would not work, would be difficult to administer, and may be anticompetitive. 304/ Central Illinois Public Service asserts that a reservation holder has little incentive to hoard capacity because other customers can use the capacity on a non-firm basis during times when a reservation holder does not schedule power. It warns that giving the transmission operator the ability to schedule unused capacity may result in undue influence and the exercise of market power. CA Energy Com maintains that, while reassignment would help prevent hoarding, it would not assure efficient use of the full transmission network. 302/ E.g., Northern States Power, VEPCO, Utilities For Improved Transition, PacifiCorp, Arizona Public Service, Dairyland, Montaup, Illinois Power, South Carolina E&G, Florida Power Corp, KU. 303/ See also NRECA. 304/ Wisconsin P&L notes, however, that a possible exception exists where a user could block the efficient transfer of power and then market its own power at a premium price. Docket Nos. RM95-8-000 - 168 - and RM94-7-001 Use of pooling arrangements to prevent improper reservations Allegheny Power contends that a pooling arrangement could provide an incentive to hoarders to release capacity during a shortage. It suggests that capacity could be auctioned within a pool of available capacity. However, it acknowledges that an auction would be tantamount to allowing the network owner to sell transmission service at unregulated rates. PacifiCorp does not believe that a pooling arrangement would prevent capacity hoarding unless nonsequential reservations are prohibited. ELCON contends that a use-it-or-lose-it rule would be fairer and more effective than pooling. Commission Conclusion Upon further consideration, we conclude 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. Firm transmission customers that have reserved capacity and paid a reservation charge generally do not use the entire amount of reserved capacity at all times. This does not mean, however, that they must permanently return the unused amount to the utility. In the absence of evidence of hoarding or other anticompetitive practices, we will not limit the amount of transmission capacity that a customer may reserve. Firm transmission customers are in the best position to know the levels of electric energy they will be transmitting and the level of flexibility they need in Docket Nos. RM95-8-000 - 169 - and RM94-7-001 carrying out their transmission activities. Indeed, when they are not using their reserved capacity, firm transmission customers remain obligated to pay the utility a reservation charge that covers all of the utility's fixed costs associated with the reserved capacity. 305/ Moreover, the possibility that a customer will reserve capacity and then hold it without using or reassigning it is mitigated because the utility is free to schedule and sell any unscheduled firm point-to-point transmission capacity on a non- firm basis to any entity eligible to receive such service under the utility's tariff. We also note that it is in the economic self interest of reservation holders to make available unused capacity to the market. 306/ We recognize that situations could arise in which a customer unlawfully withholds capacity. That is, a transmission customer could retain capacity in a way that could have an anticompetitive effect. For example, a transmission customer may reserve certain capacity simply to prevent everyone else from using it and to make its own generation the only alternative available to the market. However, as described above, we believe that the incentives are such that parties are more likely to release unneeded capacity and that a generic remedy is therefore 305/ A reservation charge would assure that the utility fully recovers its fixed costs associated with the transmission customer's reserved transmission capacity. 306/ See Section IV.C.6. Docket Nos. RM95-8-000 - 170 - and RM94-7-001 unnecessary. Any substantial allegations that indicate that a transmission customer is withholding scarce capacity in a way that has an anticompetitive effect would be addressed under section 206. If we found such allegations to be true, we could order the customer to return the capacity reservation right to the transmission operator. This approach should allay concerns that a customer may reserve scarce capacity and not use it, without forcing customers to demonstrate need or to reveal details of individual transactions. 5. Reservation of Transmission Capacity for Future Use by Utility Comments EEI and many IOUs argue that native load and network transmission customers should have first priority to existing capacity for their reasonably forecasted load requirements because that capacity was constructed to provide service to them and was paid for by them. 307/ EEI contends that such priority ensures equity and comparability based on past and future cost responsibility for the system. Similarly, Florida Power Corp and PECO contend that third-party customers should not be allowed to use transmission capacity that native load customers would grow into within a reasonable planning horizon. 307/ E.g., NYPP, Public Service E&G, Sierra Pacific Power, Ohio Edison. Sierra Pacific Power asserts that a utility should be permitted to retain capacity for native load use over the pertinent planning period. El Paso adds that the Commission should allow utilities the opportunity to reserve capacity for anticipated uses that, although not firm, are necessary to maintain reliability. Docket Nos. RM95-8-000 - 171 - and RM94-7-001 Other commenters disagree, asserting that available transmission capacity must be determined in the same manner for all customers and that utilities should not be permitted to reserve capacity for their own uses. 308/ NIEP argues that utilities should not be permitted to lock up available transmission capacity over valuable transmission paths and then require transmission requesters to pay for the cost of incremental transmission upgrades. This would let the utility avoid incremental transmission charges on its system. Oklahoma G&E argues that existing available transmission capacity should be made available until it is needed for native load growth. Utilicorp states that transmission owners should not be permitted to set aside capacity for sales or purchases of economy energy. CCEM argues that the centerpiece of comparability is that all transmission customers, including the merchant operations of the transmission owner, take service from available capacity pursuant to the same tariffs. CCEM adds that allowing utilities to reserve capacity based on forecasted retail and network loads creates an incentive for them to over-forecast their load to the detriment of all others. NRECA suggests that the need to maintain reliability should not perpetuate transmission providers' preferential treatment of their own transactions. It also recommends that, during periods when facilities are 308/ E.g., NIEP, CCEM, Conservation Law Foundation. Docket Nos. RM95-8-000 - 172 - and RM94-7-001 constrained, access be allocated based on a combination of past actual use and planned future use. Commission Conclusion We conclude 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. However, any 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. In response to arguments raised by several commenters that existing requirements customers should have future rights to existing capacity beyond the terms of their contracts because of their historical use, as discussed previously, we believe existing customers should have a right of first refusal to capacity they previously used, if they are willing 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 offered by another potential customer. 309/ 309/ See Section IV.A.5. Docket Nos. RM95-8-000 - 173 - and RM94-7-001 6. Capacity Reassignment In the NOPR, the Commission proposed that a tariff must explicitly permit reassignment of firm service entitlements. 310/ We explained that reassignment of capacity rights could have a number of benefits: (1) helping transmission users manage financial risk, (2) reducing transmission providers' market power by enabling transmission customers to compete with them, and (3) improving capacity allocation when capacity is constrained and some market participants value capacity more than current capacity holders. We requested comments on whether the current price cap on resale should be modified or eliminated and whether the transmission services described in the NOPR are suitable for reassignment. Comments General Many commenters favor capacity reassignment and the development of secondary markets. 311/ However, WP&L notes that reassignments should not be permitted over constrained interfaces if the source or destination of power changes, and LA DWP opposes unrestricted reassignment because it could cause tax- exempt financing problems for many public power utilities. 310/ FERC Stats. & Regs.  32,514 at 33,088. 311/ E.g., PacifiCorp, DOJ, NIEP, ELCON, United Illuminating, DOD, WP&L, FTC. OK Com and FL Com favor reassignment of capacity, but express concerns that reliability not be affected. Docket Nos. RM95-8-000 - 174 - and RM94-7-001 Many IOUs argue that the same terms and conditions of service applied to IOUs should be applied to resellers of transmission services. 312/ Arizona Public Service, however, asserts that all unused transmission rights should not be assignable, but should be made available to others in a manner consistent with the contract supporting the rights. It argues that a network user experiencing an off-system network shutdown should be required during the outage to make available to others the path from the point that the power enters the system to its load. It also contends that firm transmission customers should be required to post their unused rights on an EBB or RIN. Several commenters oppose mandatory reassignment of firm capacity rights. 313/ NEPCO declares that if a customer is willing to pay for its reserved capacity, it should not be forced to reassign unused capacity. Nebraska Public Power District believes that mandatory reassignment could cause problems for publicly-owned utilities. It further asserts that in the gas industry the Commission did not allow the unregulated reassignment regime it proposes for the electric industry. SoCal Edison argues that when a transmission customer resells transmission capacity, it should not be released from its contractual obligation to the transmission provider. It notes 312/ E.g., Northern States Power. 313/ E.g., NEPCO, Nebraska Public Power District. Docket Nos. RM95-8-000 - 175 - and RM94-7-001 that under traditional contract law, a party to a contract cannot escape its obligations by delegating them to another. Price caps Most commenters addressing this issue support retaining the existing price cap on reassignments or resales. 314/ Generally, these commenters believe that the price cap is necessary to prevent customers from speculating or hoarding capacity in anticipation of its value increasing. Public Service Co of CO believes that allowing assignments of capacity at prices greater than cost could prevent a transmission provider from offering firm capacity for legitimate long-term transactions. TDU Systems states that a cap should remain until the secondary market in the relevant geographic market has been shown to be competitive. PA Com states that turning available capacity into a spot market would tie up capacity that might otherwise be used on a day-to-day basis and for emergencies. Still other commenters argue that customers should not be allowed to sell the capacity for more than the transmitting utility could charge. 315/ Allegheny argues that any rule that allows resale of transmission capacity at a higher price than the transmission 314/ E.g., NRECA, Montana Power, PacifiCorp, NYSEG, PA Com, Idaho, Public Service Co of CO, FPC, Entergy, TDU Systems, Duke, Cajun, CVPSC, Oglethorpe, Minnesota DPS. FL Com argues that the price of reassignment should be capped at the contract selling price. WP&L argues that the price cap should be raised to the maximum rate allowed in the tariff under which the user purchased the original service. 315/ See also Minnesota DPS. Docket Nos. RM95-8-000 - 176 - and RM94-7-001 provider can achieve is "patently illogical and probably illegal." Several utilities, including Allegheny and CSW, contend that if resellers can market transmission services at market rates, then transmission owners must be given the same opportunity. Duquesne and United Illuminating argue that the price cap should be modified so that third parties are allowed to resell capacity at the higher of embedded costs or opportunity costs. 316/ Duquesne notes that such a provision would be comparable to the option transmitting utilities now have and would be economically efficient because it would encourage the firm capacity owner with the lowest opportunity cost to resell its capacity. A few commenters argue that the price cap should be eliminated. 317/ IL Com claims that capacity will be made available to the entity that values it most and that an uncapped resale market cannot lead to more market power because an efficient secondary market cannot be monopolized. Con Ed agrees that if the secondary market is competitive, all entities should be allowed to sell at market-based rates. 318/ CT DPUC argues that there should not be a price cap; instead, it would prefer that those holding transmission rights not be allowed to 316/ See also Midwest Commissions, SMUD, CCEM. 317/ E.g., IL Com, NEPCO, Consumers, American Wind. 318/ If the market is not competitive, however, Con Ed maintains that the cap should be retained for all entities. Docket Nos. RM95-8-000 - 177 - and RM94-7-001 withhold use of any portion of their reserved transmission capacity in the actual moment-by-moment operation of the grid. Creditworthiness standards Of those commenting on the appropriate creditworthiness standards for replacement customers (assignees), all favor allowing the transmission provider to use reasonable credit procedures to assure that the replacement customer is financially sound. 319/ NYSEG suggests that, at a minimum, the same creditworthiness criteria should be applied to the replacement customer as are applied to the original customer. Oglethorpe recommends that the assignee be required to commit to comply with all customer obligations and to pay for any additional costs resulting from the assignment. Liability for payment Commenters split on whether the original customer or the replacement customer should be liable to the transmitting utility for payment for the service. One group of commenters believes that the original customer should remain liable for all costs and for the performance of all obligations. 320/ Another group of commenters believes that the original customer should be relieved of financial responsibility, at least under certain circumstances. 321/ For example, NYSEG asserts that the 319/ E.g., PacifiCorp, NYSEG, Oglethorpe. 320/ E.g., Oglethorpe, NSP. 321/ E.g., NYSEG, Entergy, TDU Systems, Turlock, American Wind. Docket Nos. RM95-8-000 - 178 - and RM94-7-001 original customer should be relieved of its obligations upon the execution of a new service agreement between the new customer and the provider. TDU Systems contends that the original customer should be relieved of future liability where the replacement customer meets the transmission provider's creditworthiness standards. Entergy argues that the original customer should remain liable until all obligations are fulfilled. Commission Conclusion After reviewing the comments, we conclude that a public utility's tariff must explicitly permit the voluntary reassignment of all or part of a holder's firm transmission capacity rights 322/ to any eligible customer. 323/ Reassignment may be on a temporary or permanent basis, and must be subject to the conditions and requirements discussed below. Allowing holders of firm transmission capacity rights to reassign capacity will: (1) help them manage the financial risks associated with their long-term transmission commitments, (2) reduce the market power of transmission providers by enabling customers to compete, and (3) foster efficient capacity allocation. We offer below a number of clarifications and 322/ The transmission provider has the same rights as any other potential assignee to obtain capacity that is posted on an OASIS or to negotiate with the assignor for any capacity the assignor seeks to assign. 323/ The public utility's tariff shall not preclude an assignor from including a right of recall in its agreement with an assignee. Docket Nos. RM95-8-000 - 179 - and RM94-7-001 further explanations in response to concerns raised by commenters. (1) Reassignable Transmission Services We conclude that point-to-point transmission service, because it sets forth clearly defined capacity rights, should be reassignable. As for network transmission service, we conclude that there are no specific capacity rights associated with such service, and thus, network transmission service is not reassignable. (2) Terms and Conditions of Reassignments a. General In effecting a reassignment, the assignor does not have to return its capacity entitlement to the original transmission provider, but may deal directly with an assignee without involvement of the transmission provider. However, an assignee must meet the eligibility standard established by this Rule and must comply with the reliability criteria of the original transmission provider. Any such transaction must be posted on the transmission provider's OASIS within a reasonable time after its effective date. Alternatively, the assignor may, if it wishes, request the transmission provider to effect a reassignment on its behalf. 324/ In such a situation, the 324/ The assignor may also request the transmission provider to provide the billing and payment services for the reassignment. The parties would negotiate terms for such an arrangement, including a fee for the transmission provider. If an assignor is a public utility, it will have to have on (continued...) Docket Nos. RM95-8-000 - 180 - and RM94-7-001 transmission provider must immediately post the available capacity on its OASIS. The transmission provider must assure that any revenues associated with the reassignment are credited to the assignor. 325/ b. Contractual Obligations Assignors and assignees may contract directly with each other, but the assignor will remain obligated to the transmission provider. This obligation extends to any penalties or other charges incurred by the assignee in its use of the reassigned capacity. The assignee will be liable solely to the assignor, and should it not meet its obligations, the assignor may cancel the assignment under their contract. If the transmission provider and the original customer mutually agree, we will permit alternatives to the above approach. For example, the transmission provider could agree to relieve the original customer of payment liability for the term of the reassignment and permit the assignee to pay the provider directly. In the case of a permanent reassignment, the transmission provider should not unreasonably refuse to release the assignor from liability if the assignee meets the transmission provider's 324/(...continued) file with the Commission a rate schedule governing reassigned capacity. 325/ Any expenses that the public utility incurs in carrying out the capacity assignment program would simply be included in its cost of service. Docket Nos. RM95-8-000 - 181 - and RM94-7-001 creditworthiness requirements as set forth in its tariff and agrees to pay the price the assignor is obligated to pay the transmission provider. c. Price Cap We conclude 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). We remain convinced that we cannot lift the Price Cap and permit reassignments at market-based rates. Based upon the information available in this proceeding, we are unable to determine that the market for reassigned capacity is sufficiently competitive so that assignors will not be able to exert market power. Thus, we will not permit an assignor to reassign capacity at a rate in excess of the Price Cap. Assignees must agree, in contracting with the assignor, that the firm transmission capacity they will use is subject to the Price Cap. Docket Nos. RM95-8-000 - 182 - and RM94-7-001 7. Information Provided to Transmission Customers Comments Many commenters argue that in an open access, competitive environment, confidential and proprietary information should not be made publicly available through a RIN. 326/ Several utilities assert that the existing reporting requirements are sufficient to support the comparability requirements of the proposed rule, with some modifications. 327/ They note that the Commission's audit authority and complaint process will help enforce comparability requirements. 328/ Central Illinois Public Service states that, with the availability of pricing and transaction information through the RIN, no further reporting requirements are necessary. IL Com states that additional reporting should be required only if clear evidence emerges of discriminatory use of the transmission system. Dominion Resources adds that users have no need for utility planning information and data on generator status and that disclosure of such information would place owners at a competitive disadvantage. VEPCO opposes the disclosure of any commercially sensitive information to marketers, including the utility's power marketing employees. 326/ Similar arguments with respect to the information that public utilities must provide to the Commission in standard reports (e.g., Form No. 1) are addressed later in this Final Rule. 327/ E.g., PacifiCorp, NYSEG, NSP. 328/ See also PA Com. Docket Nos. RM95-8-000 - 183 - and RM94-7-001 On the other hand, several commenters argue that the information submitted by public utilities may not be adequate. For example, APPA argues that the Commission should scrutinize closely cost functionalization by utilities to assure that plant in service is properly booked. Others recommend that the Commission put in place a monthly pass-through of transmission- related operating income for all classes of customers receiving firm transmission service, rather than rely on the current practice of reducing test year cost of service by revenues booked to Accounts 456 and 447. Industrial Energy Applications recommends that utilities be required to file quarterly reports with the Commission that detail the transmission services and the pricing of their off-system power supply transactions, as an incentive to comply with the Commission's rule. Commission Conclusion We conclude that all necessary transmission information, as detailed in the OASIS final rule, must be posted on an OASIS. With respect to generation information, we will require, consistent with the OASIS final rule, that information needed to verify opportunity/redispatch costs be provided, on request, to the transmission customer charged. We will not require this Docket Nos. RM95-8-000 - 184 - and RM94-7-001 information, or any other generation information, 329/ to be posted on an OASIS. 330/ 8. Consequences of Functional Unbundling a. Distribution Function The NOPR proposed functional unbundling of wholesale generation and wholesale transmission so that the public utility as a wholesale seller could not gain an undue advantage from its transmission ownership. We did not propose to further unbundle the retail transmission and distribution functions from the wholesale transmission function. Comments A number of commenters assert that utilities should be required to unbundle -- either functionally or corporately -- the distribution function from the transmission function. ELCON argues that unbundling distribution would help delineate state and Federal jurisdiction, facilitate the establishment of transmission pricing, avoid cross-subsidization, and prepare for 329/ The prices of some ancillary services, which are posted on the OASIS, are based on generation costs, however. 330/ Because the Commission establishes many generation and all transmission rates on a cost basis, the Commission also will continue to need the information that it collects in Form No. 1 and other standard forms from public utilities to assure that the rates are just and reasonable. As we explain later in this Final Rule, the information provided in those forms is public information that is available to any transmission customer. However, because of the competitive changes occurring in the electric industry, we recognize that there may be a need to reexamine the information we collect from public utilities through the Form No. 1. Docket Nos. RM95-8-000 - 185 - and RM94-7-001 the customer choice (retail wheeling) programs that will be implemented by states in the future. It contends that functional distinctions between wholesale and retail service should be minimized. 331/ Other commenters, however, oppose establishing a separate distribution function. DOD asserts that the Commission can address any problems that arise by enforcing the terms of open access tariffs and that the Commission should not intrude into state ratemaking. 332/ Various state commissions question the workability and desirability of a functional test to determine the dividing line between retail transmission and local distribution. 333/ CA Com recommends that, to avoid jurisdictional uncertainty surrounding functional unbundling, the Commission adopt a functional test for local distribution. Under this test, vertically integrated utilities that chose to unbundle into separate operating companies, including a local distribution company that sells only at retail, could establish a workable bright line between state and federal authority without engaging in the arduous task of differentiating transmission from distribution. 331/ See also Environmental Action, Missouri Basin MPA, Texaco, EGA, AEC & SMEPA. 332/ See also TDU Systems, Public Service Co of CO. 333/ E.g., NARUC, AZ Com, CT DPUC, OK Com, FL Com, NC Com, NM Com. Docket Nos. RM95-8-000 - 186 - and RM94-7-001 Certain IOUs echo the jurisdictional concerns raised by the state commissions. 334/ They believe that the unbundling of the distribution function would create significant jurisdictional problems. Pacificorp also argues that unbundling of the distribution function would create significant jurisdictional conflict with respect to cost allocation. Commission Conclusion We conclude 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. Our approach to assuring such open access has two broad requirements: (1) functional unbundling of transmission and generation (which includes separately stated rates for generation, transmission, and ancillary services, and a requirement that a transmission provider take service under its own tariff), except for bundled retail service and (2) an OASIS with standards of conduct. We believe that additional requirements are not needed now. We further address in Section IV.I the concerns raised regarding our proposed tests to distinguish transmission and local distribution. 334/ E.g., Com Ed, Citizens Utilities, PacifiCorp. Docket Nos. RM95-8-000 - 187 - and RM94-7-001 b. Retail Transmission Service Comments The majority of commenters addressing this issue believe that unbundling retail service is unnecessary to establish a competitive market and to achieve non-discriminatory open access transmission. 335/ For example, PSNM argues that the Commission is not as well situated as are state regulators to oversee and supervise local reliability issues for retail customers. Central Illinois Public Service argues that due to the nature of transmission facilities and operations, it is not possible for the transmission provider to discriminate between the provision of wholesale and retail firm service. Several IOUs further contend that because the Commission is specifically precluded from mandating retail wheeling and has no authority over bundled retail service, the Commission cannot require retail service to be provided. 336/ In contrast, some commenters argue that functional unbundling must apply to all transmission service in interstate commerce provided by public utilities, including the transmission component of bundled retail sales. 337/ They believe that this is necessary to achieve comparability. For 335/ E,g,, Allegheny Power, PacifiCorp, MidAmerican, PECO, Public Service Co of CO, Com Ed, NARUC, NRRI, MN DPS, ND Com, FL Com. 336/ E.g., Allegheny Power. 337/ E.g., CCEM, ABATE. Docket Nos. RM95-8-000 - 188 - and RM94-7-001 example, CCEM asserts that if the distribution function is not unbundled, the result will be service under two separate arrangements -- an explicit wholesale transmission tariff filed at the Commission and an implicit retail transmission tariff governed by a state regulatory body. According to CCEM, failure to unbundle retail transmission will allow transmitting utilities to manipulate how they characterize and account for their own uses of transmission. ABATE contends that the Commission, for efficiency reasons, should encourage states to permit retail access. It asserts that the Commission must adopt a policy that signals to states how rates, terms, and conditions of retail service will be established; once a state sets such parameters, the Commission should review them. Commission Conclusion Although the unbundling of retail transmission and generation, as well as wholesale transmission and generation, would be helpful in achieving comparability, we do not believe it is necessary. In addition, it raises numerous difficult jurisdictional issues that we believe are more appropriately considered when the Commission reviews unbundled retail transmission tariffs that may come before us in the context of a state retail wheeling program. The Commission therefore reaffirms its decision to require the unbundling only of wholesale transmission from generation. 338/ 338/ But see discussion of buy/sell transactions in Section IV.I. Docket Nos. RM95-8-000 - 189 - and RM94-7-001 c. Transmission Provider 1. Taking Service Under the Tariff In the NOPR, we explained that a public utility must take transmission services for all of its new wholesale sales and purchases of energy under the same tariff of general applicability under which others take service. 339/ Comments A number of commenters argue that utilities should be required to take all of the transmission for their own use under their tariff. 340/ CCEM asserts that a transmission owner should have to schedule, at arm's length, its retail transmission uses and pay posted rates into a separate account; otherwise the capacity might be overforecast at no cost. PECO requests that the Commission clarify that the requirement that a transmission provider take service under its own transmission tariffs does not apply to: (1) retail service, (2) existing wholesale contracts, and (3) pooling arrangements. UNITIL claims that the requirement for a transmission provider to take service under its own tariff and to post its own tariff rate should not apply to pool transactions where a single pool-wide rate is applied. 339/ FERC Stats. & Regs.  32,514 at 33,080. 340/ E.g., Michigan Systems, Cleveland, Municipal Energy Agency Nebraska, Missouri Basin MPA, TAPS, Wisconsin Municipals, LG&E, NIEP, CCEM. Docket Nos. RM95-8-000 - 190 - and RM94-7-001 A number of IOUs contend that it is not necessary for the transmission provider to take service under the network tariff because both the transmission provider and the network customers cannot use the tariff to make off-system sales. LILCO states that it is appropriate to distinguish between a transmission owner's use of its transmission system to make: (1) wholesale bulk power sales; and (2) off-system purchases to serve its native load retail customers. LILCO contends that in the second situation it should not be required to take transmission service under its own open access tariffs. EGA argues that transmission owners should be required to take transmission service under open access tariffs for both wholesale off-system sales and purchases. It maintains that, as retail competition increases, utilities will eventually have to take retail service under their own tariffs. Power Marketing Association believes that comparability can be achieved only if transmission service provided in connection with coordination transactions is unbundled and the transmission provider takes such transmission service under its tariff. Consumers Power also claims that there is an inconsistency between the NOPR text, the tariffs, and the proposed regulatory language regarding whether the requirement for a utility to take service under its own tariff applies only to new wholesale transactions. Docket Nos. RM95-8-000 - 191 - and RM94-7-001 Commission Conclusion We conclude 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). 341/ For sales and purchases under existing bilateral economy energy coordination agreements, we will give an extension until December 31, 1996, for public utilities to take transmission service under the same tariff used by others. 342/ As further discussed in Section IV.F., we will also give an extension of time to December 31, 1996, for certain existing power pooling and other multi-lateral coordination agreements to comply with this requirement. This will ensure that utilities live by their own rules for wholesale transactions and that we can achieve non-discriminatory open access transmission. In the case of a public utility buying or selling at wholesale, the public utility must take service under the same tariff under which other wholesale sellers and buyers take service. 341/ With the exception of certain contracts and agreements executed on or before 60 days after publication of the Final Rule in the Federal Register, the regulation we are adopting requires that public utilities take service under their open access tariff for wholesale sales or purchases of electric energy and unbundled retail sales of electric energy, effective on the date the public utility engages in such transactions. 342/ As discussed in Section IV.F., the Commission will not impose this requirement on existing bilateral non-economy coordination agreements, but persons may file complaints that such agreements need to be modified. Docket Nos. RM95-8-000 - 192 - and RM94-7-001 2. Accounting Treatment In the NOPR, we did not address any accounting aspects of our proposed rule. Comments IOUs generally object to a requirement that they pay themselves for their use of the transmission system. 343/ NEPCO claims that it is a general principle of accounting that an enterprise cannot recognize and record revenues to itself. NEPCO suggests that, to ensure that utilities' financial statements are not misleading, this aspect of functional unbundling can and should be accomplished through the ratemaking process, rather than by requiring utilities to actually charge themselves revenues for taking transmission services. 344/ Atlantic City Electric states that the added costs of properly administering and accounting for these transactions separately will increase prices to ultimate consumers. It contends that ensuring that operators do not give undue preference to transactions of the transmission provider makes it unnecessary for a utility to charge itself. CSW argues that some of the provisions of the tariffs were specifically designed for third parties and do not make sense as 343/ E.g., EEI, Con Ed, VEPCO. 344/ See also NEPCO. Docket Nos. RM95-8-000 - 193 - and RM94-7-001 applied to the transmission provider (e.g., signing service agreements and running credit checks). 345/ Most IOUs suggest that a revenue credit mechanism be used to account for a transmission provider's use of its system. Florida Power Corp states that revenue credits should be equal to the utility's posted rates for transmission service multiplied by the amount of capacity reserved and/or energy transmitted by the utility. Otter Tail proposes a revenue credit that allocates revenues based on use under the tariff of the utility's transmission investment and credits these revenues against the firm load customers' accounts. Duke asserts that the transmission provider should maintain records reflecting transmission for its own transactions under the tariff and develop appropriate revenue credits for transmission rates. It also believes that all firm users of the transmission system should receive credits for all non-firm uses. Allegheny Power states that the crediting of non-firm revenues to network customers would have to be done on an after- the-fact basis when their loads would be known. However, it believes that revenue crediting should occur only if the firm service customer has retained the utility to remarket the customer's unused capacity. 345/ See also Florida Power Corp. Docket Nos. RM95-8-000 - 194 - and RM94-7-001 Cajun proposes that all transmission revenues in excess of those implicitly included in the development of the transmission rates, including those that the utility has charged itself, be credited back to the network service transmission customers on a load ratio share basis. If transmission service rates are formula rates that are recalculated annually, Cajun proposes that excess transmission revenues be used to offset the recalculated revenue requirement. If the rates are not formula rates, Cajun states that an explicit tracker with monthly crediting to the network customer must be used. To avoid cross-subsidization between affiliates and third parties, NRECA suggests that transmission revenues "paid" by a utility's generation function to its transmission function be credited back to the utility's nonaffiliated customers, and that any rate discounts extended to the generation function by the transmission function be filed with the Commission with a full explanation of why the discount was extended together with a showing that the discount was made available to all other similarly situated customers. APPA contends that the Commission's current system of revenue crediting could give transmission owners an unfair competitive advantage by allowing them to use the revenue credit to subsidize the price at which they sell power. It argues that transmission owners should pay the actual price of transmission rather than booking a revenue credit as an offset to the cost of transmission service. Docket Nos. RM95-8-000 - 195 - and RM94-7-001 TAPS and Wisconsin Municipals argue that an essential element of true comparability is the ongoing pass-through to network customers of a load ratio share of transmission revenues generated by third-party and the transmission provider's off- system uses of the transmission system. Houston L&P suggests that the revenue crediting mechanism proposed in the NOPR could be established to recognize the utility's transmission service revenue and expenses in non-third- party wheeling transactions by reclassifying a portion of its revenue equal to the cost of transmission services provided to itself during such transactions. This mechanism would not reclassify expense accounts, but would distinguish that transmission portion of the total transaction's revenue that was associated with covering the cost of transmission service, using the rates charged in similar third-party transactions. PacifiCorp contends that the Commission should enforce the requirement that utilities account for revenues they pay themselves through the Commission's audit powers and through complaint proceedings. It specifically recommends that each transmitting utility be required to indicate, in its Form No. 1 under Account 456, the megawatts and revenues associated with its firm and non-firm off-system sales. 346/ 346/ If the utility is not required to file a Form No. 1, PacifiCorp states that it should be required to file similar information annually. Docket Nos. RM95-8-000 - 196 - and RM94-7-001 MT Com states that the embedded costs that the Commission functionalizes for jurisdictional purposes should be carefully reconciled with plant balances used to calculate other costs of service. CCEM wants each transmission provider to charge and book revenues into separate accounts for (1) service provided to itself and off-system sales and third-party sales under the tariffs, (2) impact study costs that the provider performs for itself or an affiliate, and (3) ancillary service revenues, net of out-of-pocket expenses the transmission owner provides itself or an affiliate. Arizona Public Service recommends that any revenue crediting or booking be prospective only and that enforcement occur through the Commission's periodic audits and a utility's rate cases. Many IOUs argue that there should be no obligation to credit non-firm transmission revenues to customers who are not using their firm capacity. 347/ PacifiCorp contends that all non- firm revenues should be credited against total annual revenue requirements, resulting in lower rates to all customers. Wisconsin P&L maintains that non-firm sales revenue should be shared with all network customers. Otter Tail argues that non-firm transactions between existing utilities to support and achieve real-time system optimization should be permitted without charge to the 347/ E.g., Consumers Power, Northern States Power, PacifiCorp, Allegheny Power. Docket Nos. RM95-8-000 - 197 - and RM94-7-001 transmission owner. CSW asserts that no credits should be made for the non-firm secondary service under the point-to-point tariff and that off-system purchases for native load should not result in a revenue credit. Southwestern suggests that the Commission not require the crediting of a transmission component associated with off-system purchases by the public utility. Southwestern argues that a credit would interfere with a utility's ability to buy the most economic energy for its native load customers. It also argues that requiring a credit is not comparable to what network customers pay. NEPCO points out that crediting transmission associated with purchases would require native load customers to pay the costs of the utility's purchasing off-system power while network customers do not have to pay a separate point-to-point charge for their off-system purchases. Southwestern claims that the crediting requirement would double-charge the transmitting utility and its native load customers because a utility's off- system purchases directly relate to the load it serves, and that load already is reflected in the transmission rate calculation. Southwestern also claims that it is unclear from the NOPR whether the Commission considers sales from the renewal of existing wholesale requirements contracts as being subject to crediting. It argues that transmission related to these sales should not be subject to the crediting requirement because this is service to native load customers. Docket Nos. RM95-8-000 - 198 - and RM94-7-001 Brazos opposes imputing revenues associated with a utility's own use of its transmission system because this will artificially increase the cost of power and deny consumers the benefits of economy energy sales made at market-based prices. Commission Conclusion While we used the word "accounting" in the NOPR, the real issue is assuring that utilities bear the costs associated with their own uses of the system in a manner comparable to how they charge others. Accordingly, this is a rate issue, not an accounting issue. However, we direct utilities to account for all uses of the transmission system and to demonstrate that all customers (including the transmission provider's native load) bear the cost responsibility associated with their respective uses. 348/ D. Ancillary Services In the NOPR, the Commission stated that several ancillary services are needed to provide basic transmission service to a customer. These services range from actions taken to effect the transaction (such as scheduling and dispatching services) to services that are necessary to maintain the integrity of the transmission system during a transaction (such as load following and reactive power support). Other ancillary services are needed to correct for the effects associated with undertaking a transaction (such as energy imbalance service). 348/ Additional guidance on this subject is in Section IV.G.4.g.(2)(a). Docket Nos. RM95-8-000 - 199 - and RM94-7-001 We proposed six ancillary services to be offered in an open access transmission tariff, which we called (1) scheduling and dispatching services, (2) load following service, (3) energy imbalance service, (4) system protection service, (5) reactive power/voltage control service, and (6) loss compensation service. We requested comments on all aspects of ancillary services, including whether the identified ancillary services are appropriately defined, whether other services should be included, and how these services should be supplied. Commenters identified a number of other services that may be provided as part of interconnected operations. After considering the comments, we conclude 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. A description of these services and our reasons for designating them as ancillary services are included in section 1 below. We also discuss in that section our rationale for excluding other services from the list of ancillary services that must be included in an open access transmission tariff. In section 2 below, we discuss which of the six ancillary services Docket Nos. RM95-8-000 - 200 - and RM94-7-001 the transmission provider must provide or offer to provide to transmission customers, and which the transmission customer must purchase from the transmission provider. These requirements are summarized as follows: (1) Scheduling, System Control and Dispatch Service (Transmission Provider must provide and Transmission Customer must purchase from Transmission Provider); (2) Reactive Supply and Voltage Control from Generation Sources Service (Transmission Provider must provide and Transmission Customer must purchase from Transmission Provider); (3) Regulation and Frequency Response Service (Transmission Provider must offer to provide only to Transmission Customer serving load in Transmission Provider's control area and Transmission Customer must acquire, but may do so from Transmission Provider, a third party or self supply); (4) Energy Imbalance Service (Transmission Provider must offer to provide only to Transmission Customer serving load in Transmission Provider's control area and Transmission Customer must acquire, but may do so from Transmission Provider, a third party or self supply); Docket Nos. RM95-8-000 - 201 - and RM94-7-001 (5) Operating Reserve - Spinning Reserve Service (Transmission Provider must offer to provide only to Transmission Customer serving load in Transmission Provider's control area and Transmission Customer must acquire, but may do so from Transmission Provider, a third party or self supply); and (6) Operating Reserve - Supplemental Reserve Service (Transmission Provider must offer to provide only to Transmission Customer serving load in Transmission Provider's control area and Transmission Customer must acquire, but may do so from Transmission Provider, a third party or self supply). Our requirement that these six ancillary services be included in an open access transmission tariff does not preclude the transmission provider from offering voluntarily to provide other interconnected operations services to the transmission customer along with the supply of basic transmission service and ancillary services. 349/ 349/ Of course, public utilities would have to have a rate schedule on file to provide other jurisdictional interconnected operations services. Docket Nos. RM95-8-000 - 202 - and RM94-7-001 1. Definitions and Descriptions Comments Commenters generally agree that some ancillary services are needed for transmission of power. Some commenters, however, argue for a different name or description for the ancillary services we proposed in the NOPR. Others argue for a more extensive list of services. EEI believes that the term "ancillary" is a confusing description because the services are integral to providing transmission service. NERC, PSE&G, and others claim that ancillary services are not, as the term "ancillary" implies, subordinate or auxiliary to the transmission of power; rather such services are conjunctive and required to allow reliable operation of an electric system. BG&E and others contend that ancillary services should be defined as services for control area operation, 350/ and not as services provided by an individual, noncontrol area utility. NERC proposes, and many IOU commenters support, an alternative name for these services, "Interconnected Operations Services." NERC contends that the alternative name better reflects the fact that the services are needed in the broader context of allowing control areas, 350/ A control area is part of an interconnected power system with a common generation control system. It may contain one or several utilities. The operator of the control area is responsible for balancing generation and load and for maintaining reliable system operation. Docket Nos. RM95-8-000 - 203 - and RM94-7-001 transmission customers, and other operating entities to operate reliably and equitably. Some commenters propose a greater number of ancillary services. They argue that the services we proposed can be broken down into more discrete functions. A number of commenters provide rather lengthy lists of possible ancillary services to supplement those identified in the NOPR. 351/ NERC identifies twelve services, which it groups into three broad categories: interchange scheduling services, generation services, and transmission services. NERC's proposed interconnected operations services are: (a) interchange scheduling services: (1) system control and dispatch services; and (2) accounting; (b) generation services: (1) regulation service; (2) energy imbalance service; (3) frequency response service; (4) backup supply service; (5) operating reserve service: spinning reserve and supplemental reserve services; (6) real power loss service; (7) reactive supply (from generation resources) and voltage control service; and 351/ E.g., Oak Ridge, Houston L&P, Carolina P&L, NYPP. Docket Nos. RM95-8-000 - 204 - and RM94-7-001 (8) restoration service; and (c) transmission services: (1) facilities use; and (2) reactive supply (from transmission resources). NERC also identifies dynamic scheduling as a unique type of dispatch service that control areas must have responsibility over to ensure reliability. Houston L&P proposes a substitute list of twenty services. NYPP proposes a substitute list of thirty-eight "unbundled components for transmission service," which include twelve generation-related services and twenty-six operations-related services. Oak Ridge recommends that the Commission consider using seven ancillary services, which closely conform to the six services described in the NOPR. 352/ Although Oak Ridge identifies several additional ancillary services, it recommends that these services not be included in the list of services to be required because they cannot be measured or because the cost of metering and billing outweighs the cost of these services. Commission Conclusion We will adopt NERC's recommendations for definitions and descriptions with modifications. Starting with NERC's Interconnected Operations Services, we identify some of these as ancillary services that must be offered with basic transmission 352/ Oak Ridge originally identified nineteen ancillary services, which included a recommended separation of the six NOPR ancillary services into twelve services and seven additional new services. Docket Nos. RM95-8-000 - 205 - and RM94-7-001 service under an open access transmission tariff. 353/ The definitions developed by NERC for the individual services reflect the current position of a broad spectrum of experts on the subject of interconnected operations. Adoption of NERC's terminology will provide a more universally accepted set of definitions of services. We will retain the term "ancillary services," which will refer to those interconnected operations services that we will require transmission providers to include in an open access transmission tariff. The interconnected operations services identified by NERC incorporate all of the ancillary services proposed in the NOPR. We believe, however, that several of the individual services identified by NERC do not warrant classification as unbundled ancillary services due to the small cost involved (e.g., accounting). NERC also has identified services that, while capable of being provided in the context of integrated operations, are more appropriately provided for in a separate service agreement or other contractual arrangement (e.g., dynamic scheduling, loss compensation service). NERC and others have attempted to identify all interconnected operation services that 353/ NERC indicates that the list of services is a work in progress and therefore may not be a complete list. NERC has formed an independent Interconnected Operations Services Working Group (Working Group). The Working Group includes representatives with a broad range of industry interests (transmission-dependent, partial requirements, IPP, transmission-owning, public power). We encourage this effort and will consider future changes to the list of ancillary services or their descriptions to reflect the further development of concepts in this area. Docket Nos. RM95-8-000 - 206 - and RM94-7-001 could be provided by a control area. The thoroughness of the comments received on this issue has been invaluable to the Commission's deliberations. We will require that an open access transmission tariff include the six ancillary services that we have identified as necessary for the transmission provider to offer to transmission customers. These are needed to accomplish transmission service while maintaining reliability within and among control areas affected by the transmission service. Other interconnected operations services, such as loss compensation service, may be provided by the transmission provider or third parties to facilitate a particular transaction or operating arrangement. We will not require other interconnected operations services as part of an open access transmission tariff. If a transmission provider supplies such services voluntarily, they may be added to a customer's service agreement with the transmission provider. As mentioned, we will adopt NERC's definitions with modifications, and we name and describe the six ancillary services below. After each service name, we list in parenthesis the service name in the NOPR that most closely corresponds to the service defined. In the discussion, we explain whether and how we modified NERC's term. Docket Nos. RM95-8-000 - 207 - and RM94-7-001 a. The Six Ancillary Services (1) Scheduling, System Control and Dispatch Service (in the NOPR: Scheduling and Dispatching Service) Comments NERC proposes a System Control and Dispatch Service, which provides for (i) interchange schedule confirmation and implementation with other control areas, including intermediary control areas that are providing transmission service, and (ii) actions to ensure operational security during the interchange transaction. A transmission customer may schedule interchange with another control area operator or with another entity inside another control area; however, the control area operators are responsible for confirming and implementing the interchange into or out of their respective areas on behalf of the transmission customer. NERC also proposes a separate Accounting Service, which provides for energy accounting and billing services associated with interchange. Accounting Service would be provided by the operator of the control area in which the transmission service takes place. Commission Conclusion We adopt "Scheduling, System Control and Dispatch" as the name for an ancillary service. It substitutes for the NOPR's Scheduling and Dispatching Service. The name is NERC's recommendation with two modifications. First, we include the term "scheduling" in the name of this Docket Nos. RM95-8-000 - 208 - and RM94-7-001 service because a control area operator/transmission provider must take on the function of scheduling on behalf of customers. Second, we will not require Accounting as a separate ancillary service. The purpose of separating accounting as a stand-alone service would be to allow customers to take it separately from scheduling and system control. However, we believe that accounting for scheduling, system control and dispatch is not separable from these other functions and that accounting costs are likely to be small. Therefore, accounting does not warrant separate service status. The cost of accounting for these services should be included in the cost of Scheduling, System Control and Dispatch Service. (2) Reactive Supply and Voltage Control from Generation Sources Service (formerly Reactive Power/Voltage Control Service) Comments A number of commenters explain that reactive power and voltage control service is integrally related to the reliable operation of the transmission system. These commenters also note that reactive power and voltage support must be supplied at the location where it is needed. 354/ It cannot be provided by a distant supplier. 355/ NERC indicates that reactive supply is necessary to maintain the proper transmission line voltage for the transaction. NERC 354/ See, e.g., APPA. 355/ E.g., EEI, NERC, NYSEG, FPL, NSP. Docket Nos. RM95-8-000 - 209 - and RM94-7-001 states that reactive supply is provided from both generation resources and transmission facilities (e.g., capacitors), and lists its provision as two services, distinguished by the facilities that supply them. 356/ NERC further distinguishes reactive supply service based on the source of the need for the service: (1) reactive supply needed to support the voltage of the transmission system and (2) reactive supply needed to correct for the reactive portion of the customer's load at the delivery point. Commission Conclusion We adopt "Reactive Supply and Voltage Control from Generation Sources" as the name for an ancillary service. It substitutes for the NOPR's Reactive Power/Voltage Control Service. We accept NERC's identification of two ways of supplying reactive power and controlling voltage. One is to install facilities, usually capacitors, as part of the transmission system. We will consider the cost of these facilities as part of the cost of basic transmission service. Providing reactive power and voltage control in this way is not a separate ancillary service. The second is to use generating facilities to supply reactive power and voltage control. This use is the service 356/ See also APPA. Docket Nos. RM95-8-000 - 210 - and RM94-7-001 named here, which must be unbundled from basic transmission service. We note, however, that customers have the ability to reduce (but not eliminate completely) the reactive supply and voltage control needs and costs that their transactions impose on the transmission provider's system. For example, customers who control generating units equipped with automatic voltage control equipment can use those units to respond to local voltage requirements and thereby reduce a portion of the reactive power requirements associated with their transaction. 357/ In addition, transmission customers that serve loads can minimize the reactive power demands that they impose on the transmission system by maintaining a high power factor at their delivery points. A poor power factor at a customer's delivery point creates a need for either transmission reactive facilities (i.e., capacitors) or local generator-supplied voltage support. 358/ 357/ The ability to reduce reactive power requirements will be affected by the location and operating capabilities of the generator. Any arrangement for the customer to self-supply a portion of reactive supply should be specified in the transmission customer's service agreement with the transmission provider. 358/ Transmission providers may propose delivery point power factor standards, including additional (penalty) charges for failure to maintain specified power factors, in service agreements with customers. We will evaluate the reasonableness of any such proposals by public utilities to determine whether they conform to prudent utility practices and are comparable to requirements imposed by the utility on other customers, including the utility's own requirements customers, and are otherwise just and reasonable. Docket Nos. RM95-8-000 - 211 - and RM94-7-001 However, these transmission customer actions do not eliminate entirely the need for generator-supplied reactive power. The transmission provider must provide at least some reactive power from generation sources. For this reason, and because a transmission customer has the ability to affect the amount of reactive supply required, we will require that reactive supply and voltage control service be offered as a discrete service, and to the extent feasible, charged for on the basis of the amount required. 359/ (3) Regulation and Frequency Response Service (in the NOPR: Load Following Service) Comments Someone must supply extra generating capacity, called regulating margin, to follow the moment-to-moment variations in the load located in a control area. Following load variations is necessary to maintain scheduled interconnection frequency at sixty cycles per second (60 Hz). NERC and others support the need for someone to provide load following service to have generation follow a transmission 359/ Separation of reactive supply and voltage control from basic transmission service also may contribute to the development of a competitive market for such service if technology or industry changes result in improved ability to measure the reactive power needs of individual transmission customers or the ability to supply reactive supply from more distant sources. We recognize that these capabilities may not be fully developed at present and the ability to distinguish the reactive power needs of individual customers may be limited at first to generator control and power factor correction. Docket Nos. RM95-8-000 - 212 - and RM94-7-001 customer's load changes; someone must supply power to meet any difference between a customer's actual and scheduled generation. Usually, the control area operator provides this service, but it is possible for a customer to arrange for someone else to follow its variations in load. Many commenters indicate that the industry commonly refers to this service as "Regulation Service." 360/ Also, NERC proposes that Frequency Response Service be identified as a related but distinct service. NERC indicates that all control areas are expected to have generation and control equipment to respond automatically to frequency deviations in their networks. Commission Conclusion We adopt "Regulation and Frequency Response" as the name of an ancillary service. It substitutes for the NOPR's Load Following Service. This name conforms to the terminology recommended by NERC. We conclude that Regulation Service and Frequency Response Service are the same services that make up the Load Following Service referenced in the NOPR. While the services provided by Regulation Service and Frequency Response Service are different, they are complementary services that are made available using the same equipment. For this reason, we believe that Frequency 360/ E.g., NERC, EEI, Florida Power Corp. Docket Nos. RM95-8-000 - 213 - and RM94-7-001 Response Service and Regulation Service should not be offered separately, but should be offered as part of one service. (4) Energy Imbalance Service (the same in the NOPR) Comments Many commenters explain that Energy Imbalance Service, as proposed in the NOPR, is necessary when transmission service is provided in a control area that contains the load being served. 361/ Energy Imbalance Service supplies any hourly mismatch between a transmission customer's energy supply and the load being serving in the control area. That is, this service makes up for any net mismatch over an hour between the scheduled delivery of energy and the actual load that the energy serves in the control area. In contrast, Regulation and Frequency Response Service corrects for instantaneous variations between the customer's resources and load, even if over an hour these variations even out and require no net energy to be supplied. Commission Conclusion We will adopt "Energy Imbalance" as the name for an ancillary service. This is the same name proposed in the NOPR. NERC's description is the same as the service proposed in the NOPR. (5) Operating Reserve - Spinning Reserve Service and 361/ E.g., NERC, EEI. Docket Nos. RM95-8-000 - 214 - and RM94-7-001 (6) Operating Reserve - Supplemental Reserve Service (in the NOPR these two were formerly System Protection Service) Comments Many commenters express confusion regarding the NOPR term "system protection." They indicate that the term "system protection," is described in the NOPR as furnishing operating reserve, but has another meaning in the industry. 362/ Operating reserve is extra generation available to serve load in case there is an unplanned event such as loss of generation. Generation held for operating reserve should be located near the load, typically in the same control area. Operating reserve amounts are set by the region, subregion, or a reserve sharing group in which the transmission customer's load is electrically located. NERC and other commenters recommend the commonly-used name, "operating reserve," for this service. NERC also indicates that there are two types of operating reserve: spinning reserve and supplemental reserve. Spinning reserve is provided by generating units that are on-line and loaded at less than maximum output. They are available to serve load immediately in an unexpected contingency, such as an unplanned outage of a generating unit. Supplemental reserve is also generating capacity that can be used to respond to contingency situations. Supplemental reserve, 362/ E.g., EEI, Florida Power Corp, TVA, Wollenberg. Docket Nos. RM95-8-000 - 215 - and RM94-7-001 however, is not available instantaneously, but rather within a short period (usually ten minutes). Supplemental operating reserve is provided by generating units that are on-line but unloaded, by quick-start generation, and by customer-interrupted load, i.e., curtailing load by negotiated agreement with a customer to correct an imbalance between generation and load rather than increasing generation output. Commission Conclusion We adopt Operating Reserve - Spinning Reserve Service and Operating Reserve - Supplemental Reserve Service as the names of two related, but distinct, ancillary services. They substitute for a single ancillary service in the NOPR, System Protection Service. The names conform to the terminology recommended by NERC. We distinguish them because these services may be subject to different reliability requirements; the resources that supply each service may not be the same; and the two services may be provided by different suppliers. b. Other Services Discussed in the NOPR Commenters discussed whether two other services that were discussed in the NOPR should be designated as ancillary services. 363/ Although we do not designate these as ancillary services for purposes of this Rule, we discuss the names and 363/ In addition, NERC designates "facilities use service" as an interconnected operations service. We note that the facilities use service described by NERC is simply basic transmission service, which must be provided under an open access tariff. We do not consider facilities use service to be an ancillary service. Docket Nos. RM95-8-000 - 216 - and RM94-7-001 descriptions here so that we can discuss our policy regarding these services. (1) Real Power Loss Service (in the NOPR: Loss Compensation Service) In the NOPR, we proposed that Loss Compensation be an ancillary service. Comments NERC recommends the term, "Real Power Loss," to refer to energy consumed in transmission, much of it by resistance heating of the lines and transformers. Many parties, including NERC, comment that there are a number of ways to compensate the transmission provider for the losses that occur in providing transmission service. They indicate that real power loss service can be obtained from a variety of sources, such as the power supplier, the customer, a third-party, the transmission provider, or another control area. Also, the loss is commonly accounted for by a transmission customer receiving less energy at the point of delivery than it provides to the transmission provider at the point of receipt. The difference between delivered and received energy can be set equal to the energy lost in transmission. Commission Conclusion We adopt the term "Real Power Loss" as the name of this interconnected operations service. It substitutes for the Loss Compensation service described in the NOPR. This name conforms to the terminology recommended by NERC. Docket Nos. RM95-8-000 - 217 - and RM94-7-001 Although proposed as an ancillary service in the NOPR, we will not require that Real Power Loss be included as an ancillary service in an open access transmission tariff. It is not necessary to require the transmission provider to supply energy losses to the transmission to ensure comparable transmission access. Real Power Loss is more appropriately an interconnected operations service that transmission providers may offer voluntarily to provide to transmission customers. It is not necessary for the transmission provider to supply Real Power Loss to effect a transmission service transaction. The transmission provider is not uniquely situated to provide Real Power Loss service to its customers, nor does it have a comparative advantage over anyone in providing such a service. Indeed, to require the transmission provider to provide this service would effectively obligate the transmission provider to engage in a sale of power when such a sale is not needed to effect the transmission service transaction. As noted in the comments, customers have several options to cover losses that occur when electricity moves across transmission facilities. 364/ The availability of open access permits the customer to obtain energy losses from many regional suppliers. Although we will not require the transmission provider to supply Real Power Loss to the transmission customer nor require 364/ See, e.g., Portland, APPA, PacifiCorp, EEI. Docket Nos. RM95-8-000 - 218 - and RM94-7-001 the customer to purchase it from the transmission provider, the customer must make provision for Real Power Loss. It cannot take basic transmission service without such a provision. A customer seeking transmission service must bring to the transaction sufficient energy and capacity to replace the losses associated with its intended transaction. 365/ Consequently, we will require that the transmission customer's service agreement with the transmission provider identify the party responsible for supplying real power loss. In addition, we will require that the transmission provider indicate, either in its tariff or on its OASIS, what the energy and capacity loss factors would be for any transmission service it may provide so that potential customers will know the amount of losses to replace. (2) Dynamic Scheduling (the same in the NOPR) In the NOPR's discussion of Scheduling and Dispatch Service, we pointed out that dynamic scheduling is possible in some regions. We asked for comments on whether we should require dynamic scheduling as an ancillary service, given the complexity of the service. 365/ If a transmission provider does not charge for transmission used to supply losses for its own wholesale power sales and purchases, it may not charge others. If it charges others, it must charge for its own uses. Docket Nos. RM95-8-000 - 219 - and RM94-7-001 Comments Most commenters would not have us require Dynamic Scheduling as an ancillary service. 366/ Dynamic scheduling provides the metering, telemetering, computer software, hardware, communications, engineering, and administration required to allow remote generators to follow closely the moment-to-moment variations of a local load. In effect, dynamic scheduling electronically moves load out of the control area in which it is physically located and into another control area. Commission Conclusion We adopt the name Dynamic Scheduling Service, but we will not designate it as an ancillary service that must be included in an open access transmission tariff. In the NOPR, we noted that Dynamic Scheduling could be used in a transmission transaction if it is technically feasible to do so without adversely affecting reliability. We did not propose in the NOPR that Dynamic Scheduling be named an ancillary service. Although Dynamic Scheduling is closely related to Scheduling, System Control and Dispatch Service, it is a special service that is used only infrequently in the industry. It uses advanced technology and requires a great level of coordination. Each Dynamic Scheduling application has unique costs for special telemetry and control equipment, making it difficult to post a standard price for the service. 366/ E.g., Detroit Edison, El Paso, FPL, Minnesota P&L, NIPSCO. Docket Nos. RM95-8-000 - 220 - and RM94-7-001 Consequently, we will not require that the transmission provider offer Dynamic Scheduling Service to a transmission customer, although it may do so voluntarily. If the customer wants to purchase this service from a third party, 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. c. Other Services Not Discussed in the NOPR Comments Some commenters identified several other services that were not discussed in the NOPR, which they recommend we require to be provided as ancillary services. 367/ Examples are emergency power, supplemental power, and inadvertent power. Commission Conclusion We believe that these other services generally refer to either (1) generation services that are not related to providing transmission or (2) a subpart of a service discussed above, the cost of which is not easily separable from the other service. Consequently, we will not name any of these services as an ancillary service that a transmission provider will be required to offer separately under an open access transmission tariff. However, generation-related services may be offered voluntarily to the transmission customer. 367/ E.g., NERC, Carolina P&L, Oak Ridge, Houston L&P. Docket Nos. RM95-8-000 - 221 - and RM94-7-001 We discuss below two of these proposed generation-related ancillary services, which NERC included among its proposed interconnected operations services. (i) Backup Supply Service Comments NERC explains that Backup Supply is electric generating capacity and energy that is provided to the transmission customer as needed (1) to replace the loss of its generation sources and (2) to cover that portion of the customer's load that exceeds its generation supply for more than a short time. NERC notes that Backup Supply Service is a long-term service, which distinguishes it from Operating Reserve Service and Energy Imbalance Service. Backup Supply service replaces temporary use of operating reserves; it serves load after operating reserves are returned to standby mode to maintain operating reserves at required levels. Backup Supply may last for hours, weeks, or longer. NERC indicates that a transmission customer could reduce its need for backup supply service by using interruptible load control or active demand-side management control, or both. Commission Conclusion We accept the term "Backup Supply" as the name for this interconnected operations service, but we will not require this service as an ancillary service under an open access transmission tariff. Backup Supply Service is not required for comparable open access transmission service. Docket Nos. RM95-8-000 - 222 - and RM94-7-001 Backup Supply Service is an alternative source of generation that a customer can use in the event its primary generation source becomes unavailable for more than a few minutes. Although we believe that the two short-term operating reserve services (spinning and supplemental) are necessary to support transmission, we conclude that long-term service is not necessary. Backup Supply is a generation service that may reasonably be viewed as the responsibility of the transmission customer, who may contract for backup service or curtail load. We will impose 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 power supply to be made available. The transmission provider is obligated to protect against emergencies for a short time; it has no obligation to furnish replacement power on a long-term basis if the customer loses its source of supply. The transmission provider has no obligation to provide power for the weeks necessary for unit maintenance, for example. The transmission provider is not uniquely situated to provide Backup Supply Service to its transmission customers, nor does it have a comparative advantage over others in providing such service. Moreover, as Backup Supply Service may require substantial amounts of generation capability, it is inappropriate to require the transmission provider to assume significant generation responsibilities as we functionally unbundle transmission from generation. Docket Nos. RM95-8-000 - 223 - and RM94-7-001 Although the transmission provider will not be required to offer this service to transmission customers, it may offer voluntarily to provide Backup Supply Service to its transmission customers. Any arrangements for the supply of such service by the transmission provider should be specified in the customer's service agreement. (ii) Restoration Service Comments NERC states that Restoration Service provides facilities and procedures to enable (1) a transmission provider to restore its system and (2) a transmission customer to start its generating units or restore its loads if local power is unavailable. Other commenters refer to Restoration Service as Blackstart Service, which may be provided by the operator of the host control area, another control area operator, or another generation supplier. 368/ According to NERC, close coordination with the host control area operator is absolutely necessary during system restoration operations. Under current industry practice, each control area operator is responsible for implementing a restoration plan in coordination with non-control area utilities as well other power producers. Many large generating units require startup power to restart after being out of service. Startup power may be provided, for example, by self-contained diesel engine generator 368/ E.g., Atlantic City, Oak Ridge. Docket Nos. RM95-8-000 - 224 - and RM94-7-001 sets located at a generating plant. If electric power is not available from the grid, some and perhaps many plants must obtain the necessary power from their auxiliary generators to restart plants and return the grid voltage to the proper level. Other generators without blackstart capability may rely on power from the grid to restart, once the grid is energized by others. NERC notes, however, that it may be inappropriate to rely completely on power from the grid for restart power because power from the grid may be unavailable or insufficient. Consequently, at least some power plants must have internal auxiliary power sources. Commission Conclusion We accept the term "Restoration" as the name for this interconnected operations service. We will not require the transmission provider to offer Restoration Service as a separate ancillary service in an open access transmission tariff. Comments on Restoration Service appear to describe two services, blackstart service and planning for system restoration. Presumably, each utility and power producer will do its part through voluntary coordination and self-interest to ensure a reliable and adequate source of startup power for its generating units. We will not require a transmission provider to provide blackstart capability to transmission customers. Generators without blackstart capability can instead purchase blackstart power from any power supplier connected to the grid at an appropriate power price, if such service is available after a contingency is corrected. Docket Nos. RM95-8-000 - 225 - and RM94-7-001 The obligation to plan for restoration capability is a system control area function that rests with the transmission provider and the operator of the control area in which the transmission provider is located. The transmission provider (or its associated control area operator) generally makes arrangements with enough generators to provide the system with this capability at strategic locations on the transmission system. Thus, restoration planning is intrinsic to the transmission provider's basic transmission service and included in its cost. 2. Obligations of Transmission Providers and Transmission Customers with Respect to Ancillary Services In the NOPR, the Commission proposed that public utilities required to file open access transmission tariffs also be required to provide unbundled ancillary services to transmission customers. Although the NOPR included a list of ancillary services to be offered by transmission providers, the NOPR did not indicate whether a customer must take basic transmission service from the transmission provider to be eligible to require the transmission provider to supply ancillary services. Comments on these issues are summarized below. 369/ 369/ Some commenters suggest that transmission providers be required to provide, or transmission customers be required to purchase or self-supply, certain services other than the six ancillary services that we will require to be included in an open access transmission tariff. Because we will not require the transmission provider to offer any services other than basic transmission service and the six ancillary (continued...) Docket Nos. RM95-8-000 - 226 - and RM94-7-001 Comments Several commenters 370/ distinguish generation-related ancillary services from others. Generation-related services are those that require the provider to have extra generating capacity or to provide electric energy. The remaining ancillary services are called transmission-related services or control area services. Transmission-related services would involve, for example, voltage support from transmission facilities. An example of a control area service is system control and dispatch. Commenters do not agree on how each service should be classified. Many commenters state that only control area operators should be allowed to offer certain ancillary services, such as scheduling, system control and dispatch. 371/ They believe that otherwise reliability might suffer. Minnesota P&L states that certain ancillary services (e.g. reactive power from generators, load following, frequency control) should be provided exclusively by the operator of the control area where the load resides. 372/ Minnesota P&L indicates that obtaining these services externally could jeopardize reliability. Several commenters claim that a control 369/(...continued) services, comments on requirements to provide or take other services are not included in the summary. 370/ E.g., NERC, Tallahassee, IL Com. 371/ E.g., BG&E, Minnesota P&L, Florida Power Corp. 372/ See also Florida Power Corp and Montana Power. Docket Nos. RM95-8-000 - 227 - and RM94-7-001 area operator must provide the scheduling, system control and dispatch service and reactive power supply service (except in cases where the customer's load is very close to the generating source). 373/ Numerous commenters indicate that load following (now called Regulation and Frequency Response Service) generally is provided only by a control area operator. 374/ EEI and other commenters state that energy imbalance service must be provided by either the control area operator or some other entity that is in the control area where the customer's load is located and has real-time response capability. 375/ NYSEG points out that transmission providers generally are also control area operators and thus automatically provide energy imbalance service to maintain interchange flows and control area reliability. For this reason, NYSEG believes it is important that this service remain a responsibility of the transmission provider. SC Public Service Authority contends that ancillary services can be provided only by an entity large enough to operate at a NERC regional scale. It states that ancillary services protocols must be established regionally to support regional transmission services. 373/ E.g., Carolina P&L, Texas Utilities, NERC, PSE&G. 374/ E.g., SCE&G, Montana Power, NIPSCO, EEI, PacifiCorp. EEI and PacifiCorp indicate that dynamic scheduling of load following service is an exception to the general practice of the control area operator providing load following service. 375/ E.g., Montana Power, TDU Systems. Docket Nos. RM95-8-000 - 228 - and RM94-7-001 Other commenters disagree. They argue that all the generation-related ancillary services identified in the NOPR can be obtained from sources other than the transmission provider. 376/ American Wind believes the ability of a transmission customer to self-supply ancillary services or purchase them from a third party will help to curb inflated prices for such services. Southwest TDU Group also claims that permitting entities outside the transmission provider's control area to provide ancillary services will enhance competition and reduce the need for Commission oversight of charges for ancillary services. A majority of commenters support the view that the transmission-providing public utility should provide ancillary services. Many commenters do not discuss the services individually but present their views generally on the provision of ancillary services. Missouri-Kansas Industrials and CCEM support a requirement that utilities make ancillary services available through a tariff. They argue that, from a customer's point-of-view, it is extremely critical that a transmission provider be required to furnish these services under a regulated, nondiscriminatory, cost-based tariff format. NIEP argues that, until a fully competitive market for ancillary services develops, transmitting utilities should be obligated to provide or arrange for any and all of the NOPR ancillary services, to the extent 376/ E.g., Tallahassee, Wisconsin Municipals, IL Com. Docket Nos. RM95-8-000 - 229 - and RM94-7-001 that the transmission customer desires such services. Direct Service Industries emphasizes that a transmission provider should be required to provide any ancillary service that it is capable of supplying. Direct Service Industries and Utilities For Improved Transition claim that open access tariffs should state clearly that the transmission provider must secure ancillary services for a transmission customer if the transmission provider is not able to provide these services itself. Large Public Power Council contends that, during the transition to a competitive market for generation-related ancillary services, transmission providers should be required to provide all ancillary services related to generation that existing customers now take on a bundled basis. OH Com notes that transmission owners, by virtue of their position as transmission owners, are necessarily the providers of last resort for certain ancillary services. OH Com therefore believes that only transmission providers should provide ancillary services. Several non-IOU, transmission-owning commenters, however, urge that the Commission not require transmission providers to provide ancillary services that they cannot physically supply, i.e., if they lack sufficient generation, lack control area facilities, or have slow-responding generating units. 377/ NRECA and TDU Systems also state that many cooperatives and transmission dependent systems presently obtain ancillary 377/ E.g., OVEC, OG&E, Memphis, Nebraska Public Power, TDU Systems, TANC, San Francisco, Brazos. Docket Nos. RM95-8-000 - 230 - and RM94-7-001 services from control area utilities under specific contract terms. Consequently, if their member systems are asked to provide transmission service, they may not be able to take on the obligation to secure ancillary services under their existing contracts for transmission customers. Soyland and Pacific Northwest Coop argue that a transmission provider should not be required to supply services that it does not provide to its native load. Most IOU commenters and others oppose a requirement that the transmission provider be obligated to provide generation-related ancillary services. They offer the following reasons: (1) the need for such services differs from one transaction to the next; (2) a transmission provider is neither uniquely qualified to provide these services, nor is it essential that such provider be the one providing these services in order to effect a transaction; (3) until it is demonstrated that these services cannot be obtained from a source other than the transmission provider, it is inappropriate to require transmission providers to supply such services; and (4) a transmission provider should have no residual obligation as a provider of last resort to plan its system to have generating resources available for the supply of ancillary services. 378/ IL Com also contends that utilities should not be required to provide generation-related 378/ E.g., PSNM, Atlantic City, Centerior, UWG, Texas Utilities, Entergy, LG&E, Montana Power, FPL, United Illuminating, Large Public Power Council, Christensen. Docket Nos. RM95-8-000 - 231 - and RM94-7-001 ancillary services under general transmission service tariffs if such services can be obtained from the bulk power market. Other IOU commenters argue that there is a fundamental inconsistency between an obligation to provide or obtain ancillary services for customers and the NOPR's unbundling requirement. For example, BG&E claims that it is inconsistent to require the traditional vertically integrated utility to functionally unbundle and also to remain responsible for providing at cost-based rates what should be competitively-priced generation services. Florida P&L and other IOU commenters argue that providing generation-related ancillary services effectively imposes the load-serving obligation of the transmission customer on the transmission provider. However, some IOU commenters contend that the transmission provider or its agent should be required to provide certain ancillary services. 379/ NIPSCO and PacifiCorp believe that load following (now called Regulation and Frequency Response Service) should be provided only by the transmitting utility, especially if the customer's load and resources are located in the control area operated by the transmitting utility. EEI contends that a third-party generator should have the opportunity to provide regulation service if it resides in the transmission provider's control area and coordinates its actions with the control area operator. 379/ E.g., NIPSCO, PacifiCorp, Orange & Rockland, Allegheny, NYSEG, EEI. Docket Nos. RM95-8-000 - 232 - and RM94-7-001 IN Com and NY Com recommend that the Commission provide flexibility in assessing responsibility for the supply of ancillary services. MN DPS recommends that an individual transmission provider should not be required to file an individual tariff for ancillary services if it is a member of an RTG whose tariffs adequately cover the same services. EEI contends that a control area utility should not be required to provide ancillary services to a third party outside its control area. EEI also argues that, if the transmission provider is not a control area, it should not be required to procure ancillary services from a control area on behalf of a third party seeking service over its system. Rather, the third party should be responsible for procuring the ancillary services it needs. Other IOU commenters argue that the responsibility to acquire ancillary services belongs to the transmission customer, not the transmission provider. 380/ Many IOU commenters express concern that ancillary services be offered and taken on a symmetrical basis, i.e., if transmission providers are uniquely situated to provide the service, customers should likewise be required to take and pay for the service from such transmission providers. 381/ BG&E claims that it is patently unfair to give third-party users the option not to purchase ancillary services that the transmission 380/ E.g., BG&E. 381/ E.g., CSW, BG&E, ConEd, United Illuminating, Ohio Edison, Atlantic City, Centerior, SoCal Edison, Duke, EEI. Docket Nos. RM95-8-000 - 233 - and RM94-7-001 provider must offer. BG&E argues that, if transmission providers have an obligation to provide ancillary services, equity dictates that transmission customers have a corresponding obligation to take those services or compensate transmission providers for the costs associated with the unused capabilities. United Illuminating argues that the requirement to provide service without a corresponding obligation to purchase service unfairly burdens the transmission provider and skews competition in favor of transmission customers. Other non-IOU commenters oppose a symmetric obligation to provide and purchase particular ancillary services. 382/ Ontario Hydro and others claim that the customer should decide on a case-by-case basis which ancillary services it needs to purchase. BPA and BG&E assert that transmission providers should be able to require that the party receiving the power, which may not be the transmission customer, be responsible for acquiring ancillary services. This would allow the transmission provider to establish the appropriate contractual arrangements with the party that is actually receiving the energy and avoid shifting responsibility to a party that is merely arranging the transmission service. A number of IOU commenters express concern that customers may "lean" on a transmission provider's system for ancillary 382/ E.g., RUS, TDU Systems, DE Muni. Docket Nos. RM95-8-000 - 234 - and RM94-7-001 services. That is, they worry that the transmission customer may not purchase an ancillary service but nevertheless rely on the transmission provider to provide it. Commenters propose various remedies to address this concern. NIEP, Dayton P&L and others argue that the Commission should require that, as a prerequisite to basic transmission service, the transmission customer has either arranged to obtain ancillary services from the transmission provider or has demonstrated it has an arrangement with an alternative supplier that is reliable and sufficient to satisfy the ancillary service needs associated with the transmission service transaction. NYPP believes that, if the customer's method of providing ancillary services does not meet the standards of the transmission provider, the transmission provider should be able to require that the transmission customer find another ancillary service supplier or purchase the service directly from the transmission provider at its tariff rates. 383/ EEI proposes that penalties be permitted as a backstop if the market cannot resolve the "leaning" problem. VEPCO suggests that utilities should have the option to require customers to maintain backup supply reserves. Commission Conclusion The NOPR proposed that six ancillary services be included in an open access transmission tariff. Some commenters interpret the NOPR to require that transmission providers make a 383/ See also NYSEG, Ohio Edison. Docket Nos. RM95-8-000 - 235 - and RM94-7-001 "universal" offer of unbundled ancillary services, i.e., an offer to any transmission customer regardless of location and whether the transmission customer would also be taking basic transmission service from the supplier of ancillary services. 384/ Such interpretation is incorrect; it goes beyond what is required for comparability. These services are required to be provided only to customers taking basic transmission service. However, transmission providers may offer these services on a voluntary basis to other customers if technology permits. Transmission through or out of a control area requires fewer ancillary services from the operator of the control area than transmission within or into a control area to serve loads in the control area. If the requested transmission service transaction involves more than one control area, i.e., the receipt point and delivery point of transmission service are located in different control areas, certain ancillary services will be needed only in the control area where the transmission customer's load is located. We will distinguish two groups or categories of ancillary services: (1) services that we will require the transmission provider to provide to all its basic transmission customers, and (2) services that we will require the transmission provider to offer to provide only to transmission customers serving load in the provider's control area. The first group is comprised of (i) 384/ E.g., PSNM, Atlantic City, Centerior, Texas Utilities, Entergy, FPL, Utility Working Group. Docket Nos. RM95-8-000 - 236 - and RM94-7-001 Scheduling, System Control and Dispatch and (ii) Reactive Supply and Voltage Control from Generation Services. The second group is comprised of (i) Regulation and Frequency Response, (ii) Energy Imbalance, (iii) Operating Reserve - Spinning, and (iv) Operating Reserve - Supplemental. With respect to the first group of ancillary services, we conclude that the transmission provider that operates a control area is uniquely positioned to provide these services. Thus, as stated above, we will require the transmission provider that operates a control area to provide these ancillary services. We will also require that the transmission customer purchase these services from the transmission provider, as explained in the next section. With respect to the second group of ancillary services, we conclude that the transmission provider is not always uniquely positioned to provide these services, although in many cases it may be the only practical source. Thus, we will require the transmission provider to offer to provide the ancillary services in the second group to transmission customers serving load in the transmission provider's control area. We also will require the transmission customer serving load in the transmission provider's area to acquire these services, but it may do so from the transmission provider, a third party or self-supply. These ancillary services must be provided by someone if the system is to be operated reliably; the customer may not decline the transmission provider's offer of ancillary services unless it Docket Nos. RM95-8-000 - 237 - and RM94-7-001 demonstrates that it has acquired the services from another source. The transmission provider may require the customer to decide which of these ancillary services it will purchase from the transmission provider when it applies for basic transmission service. If the transmission provider is a public utility providing basic transmission service but is not a control area operator, it may be unable to provide some or all of the ancillary services we require without substantial investment. In this case, we will allow the transmission provider to fulfill its obligation to provide, or offer to provide, ancillary services by acting as the customer's agent. We will require the transmission provider to offer to act as agent for the transmission customer to secure these services from the control area operator. 385/ The customer may have the transmission provider act as agent or may secure the ancillary services directly from the control area operator. As stated above, the customer may also secure the second group of ancillary service from a third party or by self- supply. If the transmission provider is a public utility that is not a control area operator, but its control area operator is a 385/ The requirement to offer to act as agent is in lieu of the requirement for the transmission provider to supply the ancillary service to the transmission customer. Many commenters asked that we not require the transmission provider to acquire the capacity to provide ancillary services that it does not provide for itself but acquires from its control area operator. E.g., EEI, NRECA, BPA, TDU Systems. Docket Nos. RM95-8-000 - 238 - and RM94-7-001 public utility, the control area operator must 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. 386/ We discuss the requirement to supply and purchase each ancillary service individually below. a. Ancillary Services Required to be Provided by Transmission Provider for All of Its Transmission Customers (1) Scheduling, System Control and Dispatch Service We conclude that this service is necessary to the provision of basic transmission service within every control area. As NERC and other commenters point out, Scheduling, System Control and Dispatch Service can be provided only by the operator of the control area in which the transmission facilities used are located. 387/ This is because the service is to schedule the movement of power through, out of, within, or into the control area. 386/ If the transmission provider is a control area operator but not a public utility, we can order transmission services only upon application, pursuant to section 211 and 212 of the FPA. However, the provision of transmission services by non-public utilities would be necessary to satisfy the reciprocity condition in public utilities' open access transmission tariffs. 387/ E.g., Carolina P&L, Texas Utilities, PSE&G. Docket Nos. RM95-8-000 - 239 - and RM94-7-001 (2) Reactive Supply and Voltage Control Service from Generation Sources We conclude that this service is necessary to the provision of basic transmission service within every control area. Because reactive power cannot be transmitted for significant distances, the local transmission provider has to supply reactive power from generation sources. It is often uniquely situated to supply reactive power. The transmission provider or the operator of the control area in which the provider is located cannot avoid supplying it to the transmission customer, and the transmission customer cannot avoid taking at least some of this service from the transmission provider. Although a customer is required to take this ancillary service from the transmission provider or control area operator, it may reduce the charge for this service to the extent it can reduce its requirement for reactive power supply. b. Ancillary Services Required to be Offered Only to Transmission Customers Serving Loads in the Transmission Provider's Control Area (1) Regulation and Frequency Response Regulation and Frequency Response Service is not required for transmission out of or through the transmission provider's control area. We conclude that this service must be offered only for transmission within or into the transmission provider's control area to serve load in the area. Customers may be able to satisfy the regulation service obligation by providing generation with automatic generation control capabilities to the control Docket Nos. RM95-8-000 - 240 - and RM94-7-001 area in which the load resides. Dynamic scheduling may also be used to electronically "move" a remote generating unit into the appropriate control area. For customers to take advantage of these developments, a transmission provider is required to identify the regulating margin requirements for transmission customers serving loads in its control area and develop procedures by which customers can avoid or reduce such requirements. (2) Energy Imbalance We conclude that Energy Imbalance service must be offered for transmission within and into the transmission provider's control area to serve load in the area. Energy imbalance represents the deviation between the scheduled and actual delivery of energy to a load in the local control area over a single hour. A transmission customer can reduce or eliminate the need for energy imbalance service in several ways. A customer can avoid taking energy imbalance service if it controls generation with load-following capabilities located in the control area. The Final Rule pro forma tariff allows unlimited changes before the hour at no additional charge to a customer's hourly schedule of energy deliveries to the control area. By changing its schedule more frequently (based on updated load information, for example), a customer can reduce or avoid energy imbalance charges. Other customer options to reduce or avoid energy imbalance charges include (i) establishing the load as a separate control area Docket Nos. RM95-8-000 - 241 - and RM94-7-001 island within the transmission provider's control area with its own generation and load and (ii) removing the customer's load from the transmission provider's control area through dynamic scheduling. 388/ (3) Operating Reserve - Spinning (4) Operating Reserve - Supplemental We conclude that Operating Reserve - Spinning and Operating Reserve - Supplemental must be offered for transmission within and into the transmission provider's control area to serve load in the control area. Reserves should be located near load in case of unplanned unavailability of generating units serving load in the control area. We will permit transmission providers to rely upon prevailing regional practices to set reserve criteria. Transmission providers are required to facilitate efforts by customers to meet Operating Reserve obligations with their own generating resources or from third-party sources if they can satisfy the regional criteria. If a customer uses either type of operating reserve, it must expeditiously replace the reserve with backup power to reestablish required minimum reserve levels. 388/ Some of these options (e.g., establishing a separate control area), while technically feasible, may be too costly or otherwise inadvisable. Docket Nos. RM95-8-000 - 242 - and RM94-7-001 3. Unbundling and Bundling Ancillary Services a. Services that Can be Bundled with Transmission Service In the NOPR, the Commission proposed that transmission providers should be required to offer ancillary services as discrete services, unbundled from basic transmission service. Comments While most commenters support the approach to unbundling the ancillary services proposed in the NOPR, a number of commenters argue that, for technical and administrative reasons, certain services should be bundled with basic transmission service. For example, some commenters assert that Reactive Supply and Voltage Support service should be bundled with basic transmission service. 389/ They argue that this service is integrally related to the operation of the transmission system, that it must be provided at or near the point of need, and that its costs are difficult to isolate and account for. 390/ Other commenters argue that scheduling and dispatch service, for similar reasons, should be bundled with basic transmission service. 391/ A few commenters suggest that other services could be bundled with the basic transmission service. For example, NYSEG identifies energy imbalance service as a candidate for bundling. 389/ E.g., Carolina P&L, NYSEG, FPL, NSP, WP&L, Orange & Rockland, Arizona, Salt River, SC Public Service Authority, Brazos, NY Com. 390/ See, e.g., Carolina P&L Initial Comments at 56. 391/ See, e.g., CCEM, Carolina P&L, NYSEG, CINergy. Docket Nos. RM95-8-000 - 243 - and RM94-7-001 EEI identifies frequency regulation and NYMEX identifies frequency control as services that could be bundled with basic transmission service. Some commenters believe that the Commission should allow utilities to file transmission tariffs that bundle all necessary transmission and ancillary services, at least as an interim measure. 392/ On the other hand, other commenters believe that a greater level of unbundling of transmission and ancillary services is necessary to facilitate the development of competitive markets and to ensure that transmission customers are able to purchase only the services they require. 393/ Dayton P&L believes that all ancillary services should be offered as discrete services with separate prices. Texas Utilities asserts that generation-related ancillary services should be unbundled and separately priced. Commission Conclusion Although commenters raise valid concerns, they do not provide a compelling reason to require that our six ancillary services be bundled with basic transmission service. We have, however, changed the proposal in the NOPR to clarify that reactive supply and voltage support from transmission resources is part of basic transmission service. 392/ E.g., UT Com, Washington and Oregon Energy Offices, WA Com. 393/ E.g., Direct Service Industries, Mt. Hope Hydro. Docket Nos. RM95-8-000 - 244 - and RM94-7-001 Unbundling ancillary services will promote competition and efficiency in their supply. Because most generation-based ancillary services potentially can be provided by many of the generators connected to the transmission system, some customers may be able to provide or procure such services more economically than the transmission provider can. Once they are unbundled, a more competitive market may emerge to supply such services. Also, unbundling makes possible a more equitable distribution of costs. Because customers that take similar amounts of transmission service may require different amounts of some ancillary services, bundling these services with basic transmission service would result in some customers having to take and pay for more or less of an ancillary service than they use. For these reasons, the Commission concludes that the six required ancillary services should not be bundled with basic transmission service. With respect to the specific question of whether Reactive Supply and Voltage Control from Generation Sources should be bundled with basic transmission service, we believe that this service should remain unbundled because, as explained above, transmission customers have some ability to affect how much of this service they need and a third party may be able to supply some portion of a customer's reactive power requirements. Docket Nos. RM95-8-000 - 245 - and RM94-7-001 b. Services that May be Offered and Sold as a Package The NOPR indicated that ancillary services must be offered separately from one another but did not indicate if the transmission provider may also offer a package of ancillary services. Comments Several commenters support giving customers the option either to purchase ancillary services as separate and distinct services or to purchase a package of services from the transmission provider. 394/ Others, such as Tallahassee, recommend that utilities be prohibited from bundling the purchase of one service with another so that a transmission customer cannot rely on the transmission provider for just one or a few of the ancillary services. EEI and ELCON argue that the Commission should permit customers the option to request that transmission providers offer packages of selected ancillary services. 395/ They and other commenters express a concern that efficiencies can be lost under a policy that precludes combining ancillary services. 394/ E.g., Direct Service Industries, Mt. Hope Hydro, ELCON, PA Com. 395/ EEI Initial Comments at V-4; ELCON Initial Comments at 21. Docket Nos. RM95-8-000 - 246 - and RM94-7-001 Commission Conclusion We conclude that a transmission provider must offer and price the individual ancillary services separately. It may not tie the purchase of one to the purchase of another. However, 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. It may also offer rate discounts on any ancillary service. If a rate discount is offered to the transmission owner itself or to an affiliate of the transmission owner, the same discount must be offered to non-affiliates, as well. In addition, discounts offered to non-affiliates must be on a basis that is not unduly discriminatory. All discounts must be posted on the transmission provider's OASIS. 4. Reassignment of Ancillary Services In the NOPR, the Commission noted that ancillary services may not be suitable for reassignment and requested comments on this issue. Comments Commenters express divided views on the reassignment issue. Some IOU commenters believe that, subject to technical limitations, ancillary services could be reassigned. 396/ Other commenters, including many IOUs, oppose reassignment 396/ E.g., WP&L, NYSEG. Docket Nos. RM95-8-000 - 247 - and RM94-7-001 because they believe it is impractical. 397/ In particular, PacifiCorp claims that the customer-specific nature of generation-related ancillary services prevents such services from being reassigned. TDU Systems argue that transmission customers that must pay for ancillary services they do not need should be able to resell them to someone else. 398/ Mt. Hope Hydro claims that, if a bulk power transaction and the associated transmission service can be reassigned, it is reasonable that the ancillary services used to support the transaction also should be reassigned, particularly if the same facilities and contract path are used. 399/ Commission Conclusion We conclude that transmission customers will be allowed to reassign ancillary services along with the reassignment of basic transmission service. The Commission believes that a policy of transmission capacity reassignment may not be possible unless the ancillary services used to support the transmission are also reassignable. 5. Pricing of Ancillary Services In the NOPR, we asked for comments on ancillary service pricing and proposed specific ancillary services prices in the 397/ E.g., Consumers, PacifiCorp, Carolina P&L, PSNM, Salt River, PA Com, TDU Systems. 398/ TDU Systems Initial Comments at 87. 399/ Mt. Hope Hydro Initial Comments at 17. Docket Nos. RM95-8-000 - 248 - and RM94-7-001 Stage One implementation rates. Many commenters commented on the Stage One rates. There is no Stage One in the Final Rule. Comments Many commenters state that ancillary services are difficult to price. They suggest diverse pricing approaches. IN Com notes that, because utilities and regulatory commissions have no experience with pricing unbundled ancillary services, the process needs to evolve but the goal should be to encourage market pricing in competitive markets. Air Liquide believes the best pricing policy should be negotiated bilateral agreements, provided market power is mitigated. Other commenters express concern about how pricing proposed in the NOPR would affect the development and operation of competitive ancillary services markets. Industrial Energy Applications notes that low price caps on generation-related services, such as supplying losses, imbalance energy, operating reserve and backup power, which can be provided from many sources, inhibit competitive market development. There is little incentive for other providers to invest in facilities to provide these services. Dayton P&L and others contend that the Commission should not require transmission providers to provide generation-based ancillary services at cost-based rates and then allow third parties to resell such services at market-based rates. PacifiCorp expresses concern that the NOPR's pricing proposal would be overly restrictive in the emerging competitive market for generation-related ancillary services. Docket Nos. RM95-8-000 - 249 - and RM94-7-001 Many commenters argue that cost-based price caps are appropriate for ancillary services if there are no alternative suppliers or until competitive markets develop. 400/ CAMU suggests that the comparability standard is not met if market rates exceed the costs of providing ancillary services. Allegheny, Ohio Edison and Atlantic City support cost-based pricing for Reactive Power/Voltage Control. Ohio Edison recommends cost-based pricing for frequency regulation, and Atlantic City recommends it for scheduling and dispatch. Several commenters suggest that the Commission require cost- based rates for ancillary services where no source other than the transmission provider exists and market-based rates for generation-related ancillary services if competition exists. 401/ Washington and Oregon Energy Offices recommend that, before permitting market-based rates, at least two other non- affiliated parties should be able to offer a nearly identical ancillary service and that the Commission should use the same standards for allowing market-based rates for ancillary services that it has used for wholesale power sales. Mt. Hope Hydro argues that vertically integrated utilities should be permitted to charge cost-based rates that are limited to no more than the market price for ancillary services. It also contends that 400/ E.g., Utilities For Improved Transition, Idaho, CINergy, Direct Service Industries, Mt. Hope Hydro, ABATE, TDU Systems, Missouri-Kansas Industrials, Washington and Oregon Energy Offices, IN Com. 401/ E.g., PJM, Texas Utilities, Entergy, Carolina P&L. Docket Nos. RM95-8-000 - 250 - and RM94-7-001 companies whose generation facilities are not supported by captive retail or transmission customers should be authorized to sell at market-based prices. The vast majority of commenters from all interest groups who address market-based pricing for ancillary services agree that market-based pricing is appropriate for ancillary services where competitive market conditions exist. However, commenters disagree over whether a competitive market for ancillary services currently exists. In determining the extent of competition, many commenters distinguish between ancillary services that are (1) generation- related and (2) transmission-related. Commenters disagree over whether the Commission can declare generation-related ancillary services to be competitive on a generic basis. Many commenters contend that transmission-related ancillary services are not available in a competitive market; consequently, they agree that prices for such services should be cost-based. Commission Conclusion We will consider ancillary services rate proposals on a case-by-case basis. In response to comments, 402/ we offer here some general guidance on ancillary services pricing principles. 402/ Many commenters were particularly concerned that rates for energy losses, a NOPR ancillary service, should be market- based. We need not address this concern in this Rule, however, because we will not require Real Power Losses to be offered as an ancillary service. Docket Nos. RM95-8-000 - 251 - and RM94-7-001 (1) Ancillary service rates should be unbundled from the transmission provider's rates for basic transmission service, even though such services are a necessary adjunct to basic transmission service. (2) The fact that we have authorized a utility to sell wholesale power at market-based rates does not mean we have authorized the utility to sell ancillary services at market-based rates. (3) In the absence of a demonstration that the seller does not have market power in such services, rates for ancillary services should be cost-based and established as price caps, from which transmission providers may offer a discount to reflect cost variations or to match rates available from any third party. If a rate discount is offered to the transmission owner itself or to an affiliate of the transmission owner, the same discounted rate must be offered to non-affiliates, as well. In addition, discounts offered to non-affiliates must be on a basis that is not unduly discriminatory. All discounts must be posted on the transmission provider's OASIS. (4) The amount of each ancillary service that the customer must purchase, self-supply, or otherwise procure must be readily determined from the transmission provider's tariff and comparable to the obligations to which the transmission provider itself is subject. The provider Docket Nos. RM95-8-000 - 252 - and RM94-7-001 must take ancillary services for its own wholesale transmission under its own tariff. (5) The location and characteristics of a customer's loads and generation resources may affect significantly the level of ancillary service costs incurred by the transmission provider. Ancillary service rates and billing units should reflect these customer characteristics to the extent practicable. 6. Accounting for Ancillary Services Comments Some commenters suggest that there may be a need for revising the Uniform System of Accounts to track better the costs of providing discrete ancillary services. Other commenters believe that ancillary services are transmission-type services and suggested that the costs of generation-provided ancillary services be refunctionalized from power production expense to transmission expense. Oak Ridge asserts that a primary goal of those interested in restructuring the electricity industry should be to identify clearly the different functions that are today buried within the vertically integrated utility and bundled into one price. Oak Ridge, however, indicates that achieving this ideal of identifying unbundled services at appropriate prices will be difficult because of utility accounting practices. EEI asserts that since the current Uniform System of Accounts was designed to track costs incurred to provide bundled Docket Nos. RM95-8-000 - 253 - and RM94-7-001 wholesale service, it does not track the discrete costs incurred to provide ancillary services. Therefore, according to EEI, a major update is needed to support the pricing of discrete ancillary services. ConEd states that ancillary services are integral and essential elements of providing transmission services. It notes that, historically, due to the vertical integration of utilities, those services have been bundled with the other services provided and the costs associated with providing ancillary services have not been specifically defined. ConEd claims that to a large degree, this is due to the fact that utility accounting mechanisms were not established with the intention of identifying the costs for ancillary services. UI asserts that if transmission customers are to be charged for certain ancillary services, it may be necessary to refunctionalize certain specific costs items from generation to transmission. UI points out that some of the reactive power to support system voltages and to provide transmission services, for example, is supplied from the variable reactive output of the generators. It states that these costs, to the extent they can be identified with the provision of transmission service, should be refunctionalized to the transmission account. However, UI states it may not be possible to develop a unit cost for specific transactions. Thus, UI states it may be more appropriate to roll these costs into the embedded transmission rate and allocate them among the various users of the transmission system. Docket Nos. RM95-8-000 - 254 - and RM94-7-001 Commission Conclusion To ensure comparable transmission access a Transmission Provider is obligated to offer or arrange to provide certain ancillary services to the Transmission Customer. Also, the Transmission Provider may offer to provide other ancillary services to the Transmission Customer. A Transmission Customer is obligated to purchase certain ancillary services from the Transmission Provider. Generation resources provide certain ancillary services, while transmission resources provide other ancillary services. Consequently, the costs of providing certain ancillary services are recorded in the utility's power production expense accounts, while others are recorded in the utility's transmission expense accounts. Currently, the Uniform System of Accounts requires that costs incurred in providing ancillary services be recorded as power production or transmission expense depending upon which resource the utility uses to supply the service. At this time, we are not convinced that the amounts involved or the difficulty associated with measuring the cost of ancillary services warrants a departure from our present accounting requirements. We will specify, however, that revenues a Transmission Provider receives from providing ancillary services must be recorded by type of service in Account 447, Sales for Resale, or Account 456, Other Electric Revenues, as appropriate. Docket Nos. RM95-8-000 - 255 - and RM94-7-001 E. Real-Time Information Networks In the Open Access NOPR, the Commission determined that in order to remedy undue discrimination, a utility must functionally unbundle its wholesale services, and that among the things required by functional unbundling is that the utility, when buying or selling power, rely upon the same electronic network that its transmission customers rely upon to obtain transmission information. Accordingly, the Commission accompanied its issuance of the Open Access NOPR with issuance of a notice of technical conference that initiated a proceeding in Docket No. RM95-9-000 to consider whether Real-Time Information Networks (RINS) or some other option would be the best means to ensure that potential customers of transmission services have access to the information necessary to obtain open access transmission service on a non-discriminatory basis. 403/ The Commission affirms its conclusion 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. Therefore, we issue, in conjunction with this Final 403/ See Real-Time Information Networks, Notice of Technical Conference and Request for Comments, 60 FR 17726 (April 7, 1995). Docket Nos. RM95-8-000 - 256 - and RM94-7-001 Rule, a final rule adding a new Part 37 that requires the creation of a basic OASIS and standards of conduct. 404/ The Phase I OASIS rules require each public utility (or its agent), as defined in section 201(e) of the Federal Power Act, 16 U.S.C.  824(e), that owns, controls, or operates facilities used for the transmission of electric energy in interstate commerce to develop and/or participate in an OASIS. The Phase I OASIS rules describe what information must be provided on the OASIS during Phase I and how OASIS must be implemented. In addition, the new Part 37 contains a code of conduct applicable to all transmission providing public utilities. The code of conduct is designed to ensure that preferential access to information about wholesale transmission prices and availability is not available to employees of the public utility engaged in wholesale marketing functions or to employees of certain of the public utility's affiliates. F. Coordination Arrangements: Power Pools, Public Utility Holding Companies, Bilateral Coordination Arrangements, and Independent System Operators Comments Timing of Reformation Many marketers, IPPs, and other nonmembers of pools request that the Commission immediately apply unbundling and transmission tariff requirements to all new transactions under existing 404/ In Phase II, we will continue to develop the requirements for fully functional OASIS. We expect to issue a final rule on Phase II OASIS requirements sometime in 1997. Docket Nos. RM95-8-000 - 257 - and RM94-7-001 pooling agreements. APPA states that the Commission should not deal with power pools as a "follow-on activity" because treatment of pools is an integral step in achieving transmission comparability. AEC contends that until pools publish open access tariffs, the Commission should permit applications for section 211 transmission orders from one or more applicants directed to multiple respondents. Existing pools generally urge the Commission to allow time for the pools to propose alternative structures or agreements which would meet the objectives of the final rule. EEI states that the rule may create problems for power pools that will not be examined or understood by the Commission and the public until the Commission's pooling inquiry is completed; it requests that the pooling inquiry be completed before a final rule is issued. Duke recommends that implementation of open access transmission services by power pools be addressed in a separate proceeding because implementation of open access for power pools raises complex issues. EGA, among others, argues that new transactions under existing pooling agreements should not be grandfathered, but rather should be required to meet the functional unbundling requirements of the final rule. Some pool members argue that pool transactions are largely not wholesale transactions. For example, PECO (a member of PJM) requests the Commission to clarify that the delivery of pooled generation to pool members' native load is not a "wholesale purchase" of power and thus would Docket Nos. RM95-8-000 - 258 - and RM94-7-001 not require taking transmission service under one's own open access transmission tariff. Another member of PJM, BG&E, interprets the proposed rule to require all PJM economy trades to be firm point-to-point services; it claims that such a requirement "jeopardizes the continued viability of the pool." System-wide tariffs Virtually all commenters on power pool issues state that the tariff requirements should not be applied directly to individual utilities who are members of "tight" power pools. ELCON, CCEM, and others argue that the pro forma tariff requirement should be applied directly to "tight" or "single system" power pools to avoid discriminatory "pancaking" of transmission rates. However, Duke argues that where there are both multiple owners and operators, as in "loose" pools, it is appropriate to have individual tariffs unless the pool members agree otherwise. DOE recommends a power pool file a single pool-wide tariff to offset problems associated with joint ownership or control of transmission. CT DPUC recommends that the Commission provide guidance for transmission access and pricing (so as to avoid needless disruption of present methods). Flexible Treatment Most commenters on power pools support recognizing regional differences among power pools and urge flexibility. PSE&G (a member of PJM) states that open access tariffs must be specially crafted to deal with power pool members. NYPP and PJM state that they are considering innovations and urge that their efforts not Docket Nos. RM95-8-000 - 259 - and RM94-7-001 be stifled by any final rule. CSW proposes a region-wide pricing model based on power flows. NPPD, a member of the Mid-Continent Area Power Pool (MAPP), says MAPP is considering adopting the megawatt-mile approach to transmission pricing. SoCal Edison states that California utilities are developing a market-based power pool and that it is crucial for the final rule to be flexible to permit innovations throughout the country. ELCON and power marketers, however, argue for uniformity and point out the difficulties of moving power from system to system where each system has varying standards or "pool rules." These commenters support uniform application of the terms and conditions in the pro forma tariffs to create a national standard. NEPOOL emphasizes that since pools remain voluntary, the imposition of rules that are not acceptable to pool members simply increases the likelihood that members will withdraw and pools will disintegrate. For this reason, NEPOOL states that solutions to enhance competition (within a tight pool setting) are best identified through the consensus of pool members, which requires both time and flexibility on the part of the Commission. DE, DC, NJ and MD Coms emphasizes its concern that a one- size-fits-all open-access policy, while perhaps benefiting subsets of individual suppliers and purchasers, may not be the best solution for the millions of retail customers who currently Docket Nos. RM95-8-000 - 260 - and RM94-7-001 rely on power pools. 405/ It wants the Commission to be