ÿ Docket Nos. RM95-8-001 -1- and RM94-7-002 those designated in their service agreement) on an as-available basis at no additional charge. Because the firm point-to-point customers taking secondary non-firm are accorded this scheduling flexibility at no additional charge, they are properly accorded a lower priority than stand alone, non-firm transmission. In contrast, network customers are responsible for paying for a percentage of total system transmission costs in order to serve their designated network loads whether the energy is from designated network resources or from non-designated resources on an as-available basis. 310/ Because the network customer pays a load-ratio share of total transmission costs, it receives a higher priority. Significantly, if any firm point-to-point customer wants to avail itself of the higher priority associated with economy energy purchases under the network tariff, it is free to do so by undertaking the cost responsibilities associated with network service. Finally, in response to VT DPS, we note that we have chosen different approaches in the electric and natural gas areas. In this regard, we recognize that there is a trade-off between encouraging tradable capacity rights versus maximizing revenues that can be credited against the transmission provider's costs of providing transmission service. On the electric side, fully developed transmission capacity trading rights simply do not exist at this time, and so we have chosen to emphasize an This is comparable to the service a utility provides its native load.ÿ ÿ Docket Nos. RM95-8-001 -2- and RM94-7-002 approach that maximizes revenues to be credited to transmission customers. However, we will continue to evaluate our approach in the context of any future transmission rate proposal that is based on the concept of tradable capacity rights. 4. Reciprocity Provision In the Final Rule, the Commission concluded that it was appropriate to require a reciprocity provision in the pro forma tariff. 311/ The Commission explained that this provision will be applicable to all customers, including non-public utility entities such as municipally-owned entities and RUS cooperatives, that own, control or operate interstate transmission facilities and that take service under the open access tariff, and any affiliates of the customer that own, control or operate interstate transmission facilities. The Commission developed a voluntary safe harbor procedure under which non-public utilities would be allowed to submit to the Commission a transmission tariff and a request for declaratory order that the tariff meets the Commission's comparability (non-discrimination) standards. The Commission explained that if it finds that a tariff contains terms and conditions that substantially conform or are superior to those in the Final Rule pro forma tariff, it will deem it an acceptable reciprocity tariff and require public utilities to provide open access service to that non-public utility. FERC Stats. & Regs. at 31,760-63; mimeo at 370-378. Docket Nos. RM95-8-001 -3- and RM94-7-002 If a non-public utility chooses not to seek a Commission determination that its tariff meets the Commission's comparability standards, the Commission declared that a public utility could refuse to provide open access transmission service. However, any such denial must be based on a good faith assertion that the non-public utility has not met the Commission's reciprocity requirements. In support of its decision to adopt a reciprocity provision, the Commission explained that it was not requiring non-public utilities to provide transmission access, but was conditioning the use of public utilities' open access services on an agreement to offer open access services in return. The Commission noted that non-public utilities can choose not to take service under public utility open access tariffs and can instead seek voluntary service from the public utility on a bilateral basis. The Commission further explained that the reciprocity requirement strikes an appropriate balance by limiting its application to circumstances in which the non-public utility seeks to take advantage of open access on a public utility's system. However, the Commission recognized that Congress has determined that certain entities in the bulk power market can use tax-exempt financing by issuing bonds that do not constitute "private activity bonds" 312/ or by financing facilities with See 26 U.S.C.  141. Interest on private activity bonds is taxable unless the bonds are qualified bonds for which a specific exception is included in the Internal Revenue Code. Docket Nos. RM95-8-001 -4- and RM94-7-002 "local furnishing" bonds. 313/ The Commission stated that it was not its purpose to disturb Congress' and the IRS's determinations with respect to tax-exempt financing. Therefore, the Commission clarified that reciprocal service will not be required if providing such service would jeopardize the tax-exempt status of the transmission customer's (or its corporate affiliates') bonds used to finance such transmission facilities. 314/ With respect to local furnishing bonds, which are available to a handful of public utilities, the Commission noted that Congress, in section 1919 of the Energy Policy Act, amended section 142(f) of the Internal Revenue Code to provide that a facility shall not be treated as failing to meet the local furnishing requirement by reason of transmission services ordered by the Commission under section 211 of the FPA if "the portion of the cost of the facility financed with tax-exempt bonds is not greater than the portion of the cost of the facility which is allocable to the local furnishing of electric energy." 315/ So that any local furnishing bonds that may exist do not interfere with the effective operation of an open access transmission regime, the Commission required any public utility that is subject to the Open Access Rule that has financed transmission See 26 U.S.C.  142. The Commission also clarified that reciprocal service will not be required if providing such service would jeopardize a G&T cooperative's tax-exempt status. 26 U.S.C.  142(f)(2)(A). Docket Nos. RM95-8-001 -5- and RM94-7-002 facilities with local furnishing bonds to include in its tariff a similar provision that it will not contest the issuance of an order under section 211 of the FPA requiring the provision of such service, and will, within 10 days of receiving a written request by the applicant, file with the Commission a written waiver of its rights to a request for reciprocal service from the applicant under section 213(a) of the FPA and to the issuance of a proposed order under section 212(c). In addition, the Commission limited the reciprocity requirement to the applicant and corporate affiliates. The Commission explained that if a G&T cooperative seeks open access transmission service from the transmission provider, then only the G&T cooperative, and not its member distribution cooperatives, would be required to offer transmission service. However, if a member distribution cooperative itself receives transmission service from the transmission provider, then it (but not its G&T cooperative) must offer reciprocal transmission service over any interstate transmission facilities that it may own, control or operate. Furthermore, the Commission explained that a non-public utility, for good cause shown, may file a request for waiver of all or part of the reciprocity requirement. The Commission also explained that the reciprocity requirement will apply to any entity that owns, controls or operates interstate transmission facilities that uses a marketer or other intermediary to obtain access. The Commission added Docket Nos. RM95-8-001 -6- and RM94-7-002 that it would apply the same criteria to waive the reciprocity condition for small non-public utilities as for small public utilities. Rehearing Requests Reciprocity Provision -- Public Power Position A number of public power entities argue that the reciprocity provision should be eliminated because the Commission cannot require indirectly what it cannot require directly. 316/ Several other public power entities add that the reciprocity obligation is beyond the jurisdiction of the Commission because the transmission obligations of non-public utilities (e.g., municipal utilities) are established and limited to those required by sections 211 and 212 of the FPA. 317/ Tallahassee asserts that the Commission's conditioning approach has the effect of excluding an entire class of transmission customer from open access, i.e., those unable to grant reciprocal service. This, Tallahassee asserts, is discriminatory and contrary to the purpose of the Final Rule and the requirements of sections 205, 206 and 212 of the FPA. TANC argues that the Commission does not have the discretion to grant or withhold open access transmission on the condition that the customer consent to doing something that the Commission admits it cannot directly order: "The Commission has never 'conditioned' its duty to allow only just E.g., NRECA, Oglethorpe, AEC & SMEPA, TANC. E.g., Redding, Tallahassee, TANC, Dairyland. Docket Nos. RM95-8-001 -7- and RM94-7-002 and reasonable rates on any action by the customer." (TANC at 16). A number of entities challenge the Commission's assertion that the reciprocity requirement for non-public utilities is voluntary. 318/ Dairyland contends that the alternative of seeking a bilateral agreement is illusory -- even if it could be obtained -- because Order No. 888 provides that any bilateral wholesale coordination agreement executed after July 9, 1996 will be subject to open access requirements. Dairyland argues that the phrase "subject to open access requirements" presumably would include the reciprocity requirement for non-public utilities. AEC & SMEPA assert that there is no record support for the contention that non-public utilities are responsible for closed systems or that such systems, if any, have an impact on the market. NRECA asserts that if the reciprocity provision is retained, the Commission should "modify its terms to incorporate the statutory standards and protections which FPA sections 211 and 212 contain." 319/ Umatilla Coop asks the Commission to clarify that distribution cooperatives will not become subject to the E.g., NRECA, Dairyland, TDU Systems, AEC & SMEPA. NRECA at 29. NRECA specifically lists the following: reliability of electric service; impairment of contracts; ability to cease service; all costs associated with the service must be recovered; retail marketing areas; and prohibitions on retail wheeling and sham wholesale transactions. See also Oglethorpe. Docket Nos. RM95-8-001 -8- and RM94-7-002 reciprocity requirements merely because they purchase power from affiliated cooperatives that are acting as power marketers. TDU Systems assert that a cooperative should not have to render reciprocal service if it would interfere with its ability to obtain RUS loan financing. TAPS declares that the transmission provider alone should not have access to third-party systems through reciprocity. It maintains that the utility's long-term transmission customers should also be afforded access to those third-party systems so that the transmission provider does not have a competitive advantage. TAPS argues that a third-party should be required to have an open access tariff available. Reciprocity Provision -- Utility Position A number of utilities argue that the exemption from reciprocity for distribution cooperatives should be eliminated. 320/ EEI and Montana-Dakota Utilities assert that G&Ts could eliminate their reciprocity obligation by selling or transferring their transmission facilities to their distribution owner/members. Southwestern argues that the exception for distribution cooperatives puts public utilities at a competitive disadvantage in that distribution cooperatives can use a public utility's system to compete with the public utility, but a public utility cannot use the distribution cooperatives' systems to E.g., EEI, Entergy, Montana-Dakota Utilities, Southwestern, Oklahoma E&G, Southern. Docket Nos. RM95-8-001 -9- and RM94-7-002 compete to sell power to their customers. 321/ It adds that the exception allows distribution cooperatives to hide behind shell G&Ts. For example, Southwestern argues that Golden Spread Electric Cooperative is a shell G&T because it owns only small amounts of facilities. It concludes that reciprocal access may become especially important if a state implements a retail access plan because section 211 cannot be used to obtain transmission for retail access over a distribution cooperative's system. Southern claims that cooperatives have argued in courts and in Congress that a G&T cooperative and its distribution cooperative owners are unified economic interests in which the interest of the whole is equal to the sum of the parts, and that federal courts have upheld this view (citing one case -- City of Morgan City v. South Louisiana Electric Cooperative Ass'n, 49 F.3d 1074 (5th Cir. 1995) (Morgan City)). EEI claims that clarification of certain aspects of reciprocity is needed: (1) public utilities may not be able to determine if reciprocal service is comparable because non-public utilities do not have to provide Form 1 data, and thus non-public utilities should be required to submit additional data; (2) non- public utilities should be required to functionally unbundle, charge rates to themselves and others that reflect the cost of using the system themselves, comply with the standards of conduct, and establish an OASIS; (3) non-public utility members See also Oklahoma E&G. Docket Nos. RM95-8-001 -10- and RM94-7-002 of an RTG should be required to offer reciprocal service comparable to that provided by public utility members; and (4) a non-public utility should be required to provide all services it is reasonably capable of providing. Carolina P&L adds that a customer should be required to provide the full panoply of transmission services that it is capable of providing because the customer has a right to take any type of service from the transmission provider even though it may only choose one particular service. Tucson Power asks the Commission to clarify how it will determine the comparability of a non-public utility's tariff. It asserts that first, under the safe harbor option, the Commission should clarify (1) that non-public utilities must comply with the Commission's rules of practice and procedure, and (2) how it will determine that the rates, terms and conditions of the reciprocal service are comparable to the service the non-public utility provides itself (Tucson Power argues that this could require submittal of data comparable to that contained in Form 1). Second, the Commission should eliminate the option that would require the public utility to determine whether the request by the non-public utility is consistent with the tariff. Finally, under the RTG option, the Commission should clarify that the evidentiary requirements for non-public utilities that are members of an RTG will be the same as for non-public utilities using the safe harbor procedure, i.e., any disputes regarding compliance should be resolved by the Commission, not the RTG. Docket Nos. RM95-8-001 -11- and RM94-7-002 A number of utilities assert that the Commission should not limit the right to obtain reciprocity only to the public utility that provides the transmission service because power could actually flow over other public utilities' transmission lines. They argue that the Commission should ensure that open access transmission is as widely available as possible. 322/ EEI asserts that Federal power marketing agencies, including BPA, should be required to provide comparable open access transmission. Oklahoma G&E argues that Order No. 888 violates the Constitution's equal protection principles because it does not require universal open access. It asserts that the Commission has created an arbitrary distinction between classes of utilities that is unrelated to the Commission's objective and therefore is constitutionally invalid. Oklahoma G&E contends that the proper approach is to proceed under EPAct for all transmitting utilities on a case-by-case basis. Detroit Edison asks the Commission to clarify that the supplier and the recipient of power are direct beneficiaries and must be considered transmission customers for reciprocity purposes. Otherwise, Detroit Edison contends, parties from jurisdictional transmission transactions may be able to evade reciprocity. Reciprocity Provision -- Other Arguments E.g., Montana-Dakota Utilities, Southern, EEI. Docket Nos. RM95-8-001 -12- and RM94-7-002 CCEM argues that reciprocity should be expanded to require a transmission customer obtaining open access service also to provide open-access transmission service to all eligible customers. Otherwise, CCEM maintains, transmission owners will be able to penetrate into wholesale markets controlled by non- public utilities, but power marketers will not. CCEM asks the Commission to clarify that when a non-public utility obtains open access from a power pool, member of a power pool, or parties to some form of bilateral coordination agreement, its reciprocity obligation extends to all eligible customers, including all members of the pool or parties to the agreement. Commission Conclusion We continue to believe that it is appropriate to condition the use of public utility open access tariffs on the agreement of the tariff user to provide reciprocal access to the transmission provider. No eligible customer, including a non-public utility, that takes advantage of non-discriminatory open access transmission tariff services should be allowed to deny service or otherwise discriminate against the open access provider. As we explained in the Final Rule, [n]on-public utilities, whether they are selling power from their own generation facilities or reselling purchased power, have the ability to foreclose their customers' access to alternative power sources, and to take advantage of new markets in the traditional service territories of other utilities. While we do not take issue with the rights these non-public utilities may Docket Nos. RM95-8-001 -13- and RM94-7-002 have under other laws, we will not permit them open access to jurisdictional transmission without offering comparable service in return. We believe the reciprocity requirement strikes an appropriate balance by limiting its application to circumstances in which the non-public utility seeks to take advantage of open access on a public utility's system. [323/] Contrary to arguments raised on rehearing, we are not requiring non-public utilities to provide transmission access. Instead, we are conditioning the use of public utility open access tariffs, by all customers including non-public utilities, on an agreement to offer comparable (not unduly discriminatory) services in return. 324/ It would not be in the public interest to allow a non-public utility to take non-discriminatory transmission service from a public utility at the same time it refuses to provide comparable service to the public utility. This would restrict the operation of robust competitive markets and would harm the very ratepayers that Congress has charged us to protect. Very simply, we refuse to take a head-in-the-sand approach and order a remedy for undue discrimination that will FERC Stats. & Regs. at 31,762; mimeo at 374. As discussed infra, non-public utilities may seek a waiver of the reciprocity condition. We therefore reject Tallahassee's argument that we are excluding an entire class of transmission customer from open access, i.e., those unable to grant reciprocal service. If the Commission determines that a particular customer truly is not able to reciprocate, the reciprocity condition can be waived. These situations are obviously different from situations involving entities that do not wish to provide reciprocal service. Docket Nos. RM95-8-001 -14- and RM94-7-002 permit the beneficiaries of the remedy to engage in unduly discriminatory actions. Moreover, non-public utilities are free to seek from a public utility a waiver of the open access tariff reciprocity condition. We note that this is a modification of our statements in Order No. 888, in which we said that non-public utilities could seek a voluntary offer of transmission service from a public utility on a bilateral basis. Since the time Order No. 888 issued, we have concluded that except in unusual circumstances, public utility services should be provided pursuant to the open access tariff and not pursuant to separate bilateral agreements. 325/ This applies to all customers, including non-public utilities. Therefore, rather than requesting a bilateral agreement in order to avoid the reciprocity condition, non-public utilities instead may ask a utility for a waiver of the reciprocity condition in the utility's open access tariff. We disagree with Dairyland that this type of alternative approach is illusory. If the public utility chooses voluntarily to grant a waiver, the reciprocity condition would not apply. We reject NRECA's request that we incorporate in the reciprocity condition the statutory standards and protections of FPA sections 211 and 212. NRECA states on rehearing that mandated services to third parties would endanger cooperatives' See Public Service Electric & Gas Company, 78 FERC  61,119, slip op. at 4 and n.7 (1997). Docket Nos. RM95-8-001 -15- and RM94-7-002 ability to provide service to members, or increase members' costs. It further states that sections 211 and 212 provide substantive protections to ensure continued service to the transmitting utility's own customers, and to avoid their subsidization of services to third parties. NRECA appears to believe that these substantive protections are not provided outside the context of sections 211 and 212. We disagree. We believe the protections that NRECA is seeking are contained in the pro forma tariff and, as required by section 6 of the tariff, the non-public utility must offer its service on similar terms and conditions. 326/ We also reject requests that we not grant the exception to reciprocity provided in the Final Rule for distribution cooperatives and joint action agencies. We continue to believe that if a G&T cooperative seeks open access transmission service from the transmission provider, then only the G&T cooperative, and not its member distribution cooperatives, should be required to offer transmission service. 327/ Without a corporate affiliation between G&T cooperatives and their member With regard to the basic substantive protections such as reliability, opportunity to recover costs, and the standards for rates, terms and conditions of transmission service, we see no relative distinctions between sections 211 and 212 and sections 205 and 206 of the FPA. In response to Southern's citation to Morgan City, while this case provides some background as to the relationship between G&T cooperatives and distribution cooperatives, it in no way suggests that the relationship rises to the level of a corporate affiliation. Docket Nos. RM95-8-001 -16- and RM94-7-002 distribution cooperatives, we do not believe it is appropriate to apply the reciprocity condition to the member distribution cooperatives. To do so would result in the member distribution cooperatives being bound by their G&T cooperatives. 328/ Carolina P&L has brought to our attention a possible misunderstanding as to the meaning of comparable transmission service that a non-public utility must agree to provide as a condition of using an open access tariff. Because a non-public utility may choose any type of service from a public utility transmission provider that the transmission provider provides or is capable of providing, we clarify that a non-public utility seeking to take service under the transmission provider's open access tariff must likewise agree to offer to provide the transmission provider any service that the non-public utility provides or is capable of providing on its system in order to satisfy reciprocity. We note that in the Final Rule we explained that "[a]ny public utility that offers non-discriminatory open access transmission for the benefit of customers should be able to obtain the same non-discriminatory access in return." 329/ In However, in response to Umatilla Coop, we clarify that to the extent a distribution cooperative purchases power from an affiliated cooperative that is acting as a power marketer, the distribution cooperative will be subject to the reciprocity condition because of the marketing affiliate relationship between the two. Moreover, as we explained in the Final Rule, the reciprocity condition also applies to any entity that owns, controls or operates transmission facilities and that uses a marketer or other intermediary to obtain access. FERC Stats. & Regs. at 31,763; mimeo at 378. FERC Stats. & Regs. at 31,760; mimeo at 370. Docket Nos. RM95-8-001 -17- and RM94-7-002 this regard, because a public utility must have an OASIS and a standard of conduct for employee separation, so must a non-public utility that seeks open access transmission from a public utility. 330/ At the same time, however, we deny requests to expand the reciprocity condition. 331/ Although we believe that non-public utilities should provide open access transmission as a matter of policy, to require non-public utilities to offer transmission service to entities other than the public utility transmission providers increases the chances that they could lose tax-exempt status. Accordingly, we have adopted a policy that recognizes the statutory tax restrictions placed on non-public utilities but also balances the fundamental unfairness of requiring a utility to make its facilities available to someone who could use that access to the competitive disadvantage of the utility. Ultimately the public interest is best served by nationwide open access and, if the tax issue is favorably resolved, we may revisit the matter. See South Carolina Public Service Authority (Santee Cooper), 75 FERC  61,209 (1996); Central Electric Cooperative, Inc., 77 FERC  61,076 (1996). Of course, the non-public utility can always seek a waiver of the OASIS and standard of conduct requirements. Such a waiver request will be evaluated under the same criteria applicable to a waiver requests by a public utility. In reaching this conclusion, we note that the electric industry currently conducts business using contract path pricing. If we are presented with a regional proposal for flow-based pricing, we will reconsider whether there is a need to expand reciprocity as requested by certain entities. Docket Nos. RM95-8-001 -18- and RM94-7-002 Moreover, in response to Detroit Edison, we take this opportunity to clarify that reciprocity would apply to a wholesale purchaser if a generation seller obtains transmission service from a public utility to sell to such purchaser and such purchaser owns, operates or controls interstate transmission facilities. The same would be true where the seller owns, operates and controls interstate transmission facilities and the buyer arranges for the transmission service. Just as with marketers or other intermediaries, we do not intend to allow reciprocity to be defeated simply on the basis of whether the seller or buyer requests transmission. Such a result would elevate form over substance. With respect to TDU System's assertion that reciprocal service should not have to be rendered if it would interfere with RUS loan financing, we note that we have already indicated that reciprocal service need not be provided if tax-exempt status would be jeopardized. If TDU Systems is arguing that we should not require reciprocal service if RUS attaches such a condition in its regulation of RUS-financed cooperatives, we reject such an argument. Such cooperatives have the option to seek bilateral service agreements. We reject EEI's and Tucson Power's argument that non-public utilities must provide Form 1 data in order to provide comparable service. The Form 1 data would be relevant only if the Commission were setting non-public utilities' rates. Such a detailed review is not necessary, however. See Santee Cooper, 75 Docket Nos. RM95-8-001 -19- and RM94-7-002 FERC  61,209 (1996). Similarly, there is no need to have non- public utilities follow our Rules of Practice and Procedure to satisfy reciprocity. Rehearing Requests Safe Harbor/Waiver Provisions NRECA states that the following issues related to safe harbor status and declaratory order requests need clarification: (1) under what statutory authority is the Commission considering such petitions? (2) what rights do non-public utilities have to obtain review of Commission determinations with which they disagree? (3) how closely will a reciprocal tariff have to conform to Order No. 888 to win approval? (4) will non-public utilities have to pay the standard fee (now $11,550) with a declaratory order petition? 332/ and (5) will the Commission allow non-public utilities to include a stranded cost recovery provision similar to section 26 of the pro forma tariff? 333/ Oglethorpe asserts that the Commission should not use these procedures to assert jurisdiction over non-public transmitting utilities. Dairyland contends that requiring non-public utilities to invoke declaratory order or waiver proceedings just to assert the clear statutory protections contained in sections 211 and 212 is unwarranted. NRECA raises comparable questions with respect to waiver procedures. See also TANC. Docket Nos. RM95-8-001 -20- and RM94-7-002 TANC declares that the safe harbor provisions do not cure the problems created by reciprocity. It argues that the safe harbor provision expands the transmission access that must otherwise be offered by non-public utilities, i.e., rather than just providing reciprocal service to the transmission provider, under the safe harbor provision, the non-jurisdictional entity must offer open access to any eligible customers. Blue Ridge alleges that the safe harbor and waiver provisions face practical administrative problems. It asserts that a waiver itself will result in disputes and that the application of the waiver principle to non-public utilities is based on questionable statutory authority. It requests that the Commission add the following language to section 6 of the tariff: "If the Transmission Customer is a non-public utility, the Transmission Provider must demonstrate a need for transmission service from such entity." (Blue Ridge at 39). TAPS asks that the Commission accord the filing of a waiver application by a small non-public utility system, or inclusion in an application of a sworn statement of inapplicability, the same protections afforded larger non-public utility systems that file under the safe harbor mechanism. Arkansas Cities ask the Commission to clarify that "utilities like Arkansas Cities' members, which do not operate a control area, do not own 'transmission' facilities and primarily purchase energy for resale at retail are not subject to the transmission reciprocity condition contained in Order 888, and Docket Nos. RM95-8-001 -21- and RM94-7-002 are also not required to file a request for a waiver from the requirements of Order 888 and 889." (Arkansas Cities at 18-19) SWRTA and NWRTA ask the Commission to clarify that RTGs have the authority to issue limited waivers of the reciprocity requirements of Order Nos. 888 and 889 to qualifying non-public utility members of RTGs, and that the Commission will accord deference to an RTG's determination with respect to a non-public utility member's request for waiver of, or exemption from, these requirements. 334/ They note that SWRTA's bylaws have a Commission-approved waiver process and disputes would go to arbitration or to the Commission. Southern and EEI argue that public utilities should have a parallel "safe harbor" -- the right to seek a declaratory order as to whether the transmission service being offered by a non- public utility satisfies its reciprocity obligation. Tallahassee asks that the Commission clarify the good faith assertion a public utility must make that the non-public utility has not met the reciprocity requirements. It asserts that the section 211 good faith request rules form an appropriate standard by which to measure a good faith assertion. Commission Conclusion Several entities raise procedural and jurisdictional concerns with respect to our safe harbor and waiver provisions. At the outset, we emphasize that this Commission does not have WRTA supports NWRTA in NWRTA's rehearing request. Docket Nos. RM95-8-001 -22- and RM94-7-002 jurisdiction over non-public utilities under sections 205 and 206 and that the safe harbor mechanism and waiver provisions do not, and indeed cannot, give us such jurisdiction. Rather the safe harbor and waiver procedures are voluntary means for non-public utilities to obtain a Commission determination that they meet the reciprocity condition in the open access tariffs and thereby avoid potential delays or denials of open access service based on allegations that the transmission requestor does not meet reciprocity. In Santee Cooper, issued subsequent to the Final Rule, the Commission recognized that it lacks jurisdiction under sections 205 and 206 over transmission rates, terms and conditions offered by non-public utilities, but explained that it has the authority to evaluate non-jurisdictional activities to the extent they affect the Commission's jurisdictional responsibilities. We clarify that non-public utilities that disagree with a Commission determination are free to request rehearing of a Commission order, as occurred in Santee Cooper. If aggrieved by the Commission's final order, they may appeal under section 313 of the FPA. Also, with respect to the filing fee a non-public utility entity would have to pay in making a declaratory order request, the Commission in Santee Cooper explained that its regulations specifically exempt states, municipalities and anyone who is engaged in the official business of the Federal Government Docket Nos. RM95-8-001 -23- and RM94-7-002 from filing fees. 335/ Because of the nature of the safe harbor and waiver provisions, we will also waive the filing fee for declaratory orders for all other non-public utilities in these circumstances. As to the question of how closely a reciprocal tariff will have to conform to Order No. 888, the Commission determined in Santee Cooper that: As part of its compliance filing . . . the Authority must submit a single tariff that conforms to the Open Access Rule pro forma tariff. [336/] The Commission further explained that "[t]he Open Access Rule requires that reciprocity tariffs contain terms and conditions which substantially conform or are superior to those in the Open Access Rule pro forma tariff." 337/ We clarify, however, that in that case the utility chose to offer an open access tariff, whereas Order No. 888 provides, as a condition of service, that reciprocal access be offered to only those transmission providers from whom the non-public utility obtains open access service. Therefore, a non-public utility may so limit the use of any voluntarily offered tariff, as long as the tariff otherwise substantially conforms to the pro forma tariff. We also note that non-public utilities are free to enter into bilateral agreements to satisfy the reciprocity condition. With respect to 75 FERC at 61,694-95 (citing 18 CFR 381.108). 75 FERC at 61,701. Id. Docket Nos. RM95-8-001 -24- and RM94-7-002 such bilateral reciprocal agreements, we must leave these agreements to case-by-case determinations. Which terms and conditions may be necessary for a non-public utility to provide reciprocal service to the public utility in a bilateral agreement is necessarily a fact-specific matter not susceptible to resolution in a generic rulemaking proceeding. Additionally, we clarify that non-public utilities may include stranded cost recovery provisions in any reciprocity tariffs that they may file. 338/ In response to TANC's concern that the safe harbor provision expands the transmission access that must otherwise be offered by non-public utility entities, and Blue Ridge's concern that the safe harbor and waiver provisions raise practical administrative problems, we emphasize that both of these procedures are purely voluntary and a non-public utility can avoid any perceived problems simply by not taking part in either process. We note that several entities have voluntarily availed themselves of these procedures without any apparent hardships. 339/ Because we have not extended the reciprocity condition to rate aspects of a non-public utility's tariff, we would not evaluate any stranded cost recovery mechanism and, as with respect to all terms and conditions of non-jurisdictional tariffs, the Commission is without jurisdiction to enforce such a charge. E.g., Santee Cooper, Omaha Public Power District (filed petition for declaratory order on October 17, 1996, which was docketed as NJ97-2-000), Southern Illinois Power Cooperative (filed petition for declaratory order on October 8, 1996, which was docketed as NJ97-1-000). Docket Nos. RM95-8-001 -25- and RM94-7-002 Arkansas Cities' various waiver requests are best addressed on a case-by-case basis that permits a full airing of the factual circumstances surrounding each entity seeking a waiver. As we explained in a recent order, "the Commission will not address waiver requests in a generic rulemaking proceeding, but will require entities seeking waiver of all or part of Order Nos. 888 and 889 to submit separate, fact-specific requests. . . ." 340/ EEI's and Southern's request that public utilities be provided a parallel "safe harbor" (i.e., the right to seek a declaratory order as to whether the transmission service being offered by a non-public utility satisfies its reciprocity obligation) is denied. In the Final Rule, we explained that a public utility may refuse to provide open access transmission service to a non-public utility if its denial is based on a good faith assertion that the non-public utility has not met the Commission's reciprocity requirements. 341/ Moreover, a public utility can file a petition to terminate transmission service if a non-public utility is violating the reciprocity condition of its open access service agreement with the public utility. 342/ In response to SWRTA and NWRTA's request to clarify that RTGs have the authority to issue limited waivers of the 76 FERC  61,009 at 61,027 (1996). FERC Stats. & Regs. at 31,761; mimeo at 372. For the same reason, we deny Tallahassee's request that we clarify the good faith assertion a public utility must make that the non-public utility has not met the reciprocity condition. Docket Nos. RM95-8-001 -26- and RM94-7-002 reciprocity conditions of the Order No. 888 pro forma tariffs, we recognize that RTGs have procedures in place to resolve disputes that may arise concerning a non-public utility member's request for service from a public utility member. Because RTGs have these dispute resolution procedures in place, we clarify that RTGs, which are in themselves reciprocal voluntary arrangements, may determine whether to apply reciprocity between and among member public utilities and member non-public utilities, subject to the RTG dispute resolution procedures authorized by this Commission. Rehearing Requests Retail Wheeling Dairyland contends that the Commission improperly requires a non-public utility to provide retail wheeling if it uses the open access tariff of a public utility that allows retail access either voluntarily or as part of a state-mandated program. Docket Nos. RM95-8-001 -27- and RM94-7-002 Commission Conclusion Contrary to Dairyland's contention, nothing in the Final Rule requires a non-public utility to provide retail wheeling. Section 212(h) of the FPA explicitly prohibits the Commission from ordering retail transmission directly to an ultimate consumer. If a non-public utility offers reciprocal service, its tariff would have to include the same explicit provision contained in the pro forma tariff, which states that an eligible customer cannot obtain transmission that would violate section 212(h) of the FPA, unless pursuant to a state program that requires the transmission provider to offer such wheeling. Rehearing Requests OASIS Southern argues that the Commission should explicitly require that non-public utilities must comply with Order No. 889 as part of the reciprocity obligation. Commission Conclusion We agree with Southern and, as discussed above, absent a waiver, will require non-public utilities to comply with Order No. 889 as part of the reciprocity obligation. Rehearing Requests Foreign Entities In the Open Access Rule, we decided that a foreign entity that otherwise meets the eligibility criteria should be able to obtain service under a United States public utility's open access tariff. However, like United States non-public utilities (which Docket Nos. RM95-8-001 -28- and RM94-7-002 also are not under our section 205-206 jurisdiction), a foreign entity that owns or controls transmission facilities and that takes transmission service under a United States public utility's open access tariff must comply with the reciprocity provision in the tariff. 343/ The reciprocity provision ensures that when a public utility provides service under its open access tariff to a transmission-owning entity that is not subject to the open access requirement, the public utility will be able to receive service in turn from that entity. In our discussion of the reciprocity provision, we pointed out that if a non-jurisdictional entity that owns or controls transmission does not wish to provide service to the public utility, it can choose not to use the public utility's open access tariff and can instead seek voluntary service from the public utility on a contractual basis. 344/ On rehearing, Ontario Hydro argues that the Commission has "unilateral[ly] impos[ed]" the reciprocity requirement on foreign entities in violation of the North American Free Trade Agreement (NAFTA). 345/ It declares that [u]nder the principle of national treatment, the citizens of each party to NAFTA . . . are allowed the same market access within another treaty party's market as is provided to the citizens of such other party. A party to FERC Stats. & Regs. at 31,689; mimeo at 156. FERC Stats. & Regs. at 31,761; mimeo at 373. 32-3 Int'l Legal Materials 682 (1993); 19 U.S.C.A.  3301 et seq. (1995 Supp.)(legislation implementing NAFTA). Docket Nos. RM95-8-001 -29- and RM94-7-002 these agreements cannot withhold access to its market by conditioning it upon receipt of equal access into the market of another party, because the result would be market access less favorable for the other party . . . than that accorded the party's own citizens. [346/] Ontario Hydro claims that the Open Access Rule "makes open access the law of the land for wholesale transmission service within the United States . . ." and that Canadian entities are thus entitled to such access on an unconditional basis. 347/ Next, it accuses the Commission of trying to "coerce" Canada to "conform its market access policy" to United States policy and of "impos[ing] U.S. regulatory policies" on Canadian markets. 348/ Finally, Ontario Hydro argues that even aside from the NAFTA issue, under the FPA the Commission does not have jurisdiction over foreign entities and thus cannot require reciprocity. Commission Conclusion We disagree with Ontario Hydro's claim that NAFTA's national treatment principle requires us to allow a Canadian transmission- owning entity (or its corporate affiliate) to take advantage of a United States public utility's open access tariff -- a tariff we have required the utility to adopt -- while simultaneously refusing to allow the United States utility to use the Canadian entity's transmission facilities. NAFTA's national treatment Ontario Hydro at 4-7. Ontario Hydro at 5. Ontario Hydro at 5, 3. Docket Nos. RM95-8-001 -30- and RM94-7-002 principle requires that each signatory "accord national treatment to the goods" of other signatories in accordance with Article III of the General Agreement on Tariffs and Trade (GATT). 349/ National treatment means that the United States "must not discriminate between foreign and domestic energy on the basis of nationality . . ." and that Canadian electricity must be treated "no less favorabl[y] than U.S. electricity, under all U.S. laws and rules respecting the sale, . . . distribution, and use of . . . electricity." Thus, this Commission must accord Canadian energy supplies treatment that is no less favorable than the treatment accorded United States supplies. 350/ Ontario Hydro's interpretation, however, would twist this principle into a requirement that Canadian entities be treated better than United States entities, including United States non-public utilities that are subject to the reciprocity condition. 351/ NAFTA Article 301, citing GATT, 61 Stat. A5, A18-A19 (1947). "Goods" under NAFTA include transmission service. NAFTA, Articles 606, 609. Iroquois Gas Transmission System, L.P., et al., 53 FERC  61,194 at 61,700-01 (1990), aff'd sub nom. Louisiana Association of Independent Power Producers and Royalty Owners v. FERC, 958 F.2d 1101 (D.C. Cir. 1992), quoting United States-Canada Free Trade Agreement Implementation Act of 1988, Report of the Committee on Energy and Commerce, House of Representatives, H.R. Rep. No. 100-816, Part 7, 100th Cong., 2d Sess. at p. 7 (1988). The Free Trade Agreement is a predecessor to NAFTA. We have no section 205-206 jurisdiction over non-public United States utilities, just as we have no jurisdiction over foreign entities. Ontario Hydro's claim that the Open Access Rule "makes open access the law of the land for wholesale transmission service within the United States" is wrong; open access is not the law of the land for United States non-public Docket Nos. RM95-8-001 -31- and RM94-7-002 Under Order No. 888, all public utility open access tariffs contain a reciprocity condition that applies to all users of the tariff within the United States, including United States non- public utilities, unless the condition is waived either by the Commission or the public utility provider. Under the reciprocity condition, non-public utilities do not have to offer an open access tariff (i.e., a tariff that offers transmission service to any eligible customer), but rather must offer comparable transmission services only to those transmission providers whose open access tariffs the non-public utility uses. 352/ The same condition applies to foreign utilities. Thus, Ontario Hydro is in plain error in arguing that application of the reciprocity condition to foreign entities would result in less favorable treatment than that accorded to United States citizens. Ontario Hydro's reading of NAFTA would place transmission-owning Canadian entities (or their corporate affiliates) in a better position than any domestic entity; not only would Canadian entities not be subject to the open access requirement, but, unlike domestic non- public utilities, they would be able to use the open access tariffs we have mandated without providing any reciprocal utilities, since we have no section 205-206 jurisdiction over them. United States public utilities, of course, are separately required by Order No. 888 to have on file open access tariffs and thus meet reciprocity through the separate, more stringent open access requirement. Docket Nos. RM95-8-001 -32- and RM94-7-002 service. Ontario Hydro has cited no precedent demonstrating that NAFTA imposes such an unreasonable requirement. 353/ Moreover, we are not "coercing" Canada into adopting our policies or "imposing" open access on Canadian entities; we are simply placing the same condition on a Canadian entity's use of a United States utility's open access tariff as on a domestic non- public utility's use of that tariff. However, consistent with the approach we have taken in other contexts involving foreign utilities seeking to transact in United States electricity markets, we are amenable to a variety of approaches for Canadian utilities to meet the reciprocity condition. 354/ Ontario Hydro is also wrong in its claim that even aside from NAFTA, we lack authority under the FPA to require reciprocity when a foreign entity wishes to use a domestic utility's open access tariff. Just as we are not asserting jurisdiction over domestic non-public utilities under sections 205 or 206 of the FPA, we also are not asserting jurisdiction Ontario Hydro also complains that the reciprocity obligation of domestic non-public utilities is subject to various limitations and waiver provisions. These provisions apply to foreign entities as well. In recent cases involving the mitigation of transmission market power of Canadian utilities that are affiliates of power marketers that seek to sell power at market-based rates in the United States, the Commission has explicitly acknowledged the sovereign authority of Canadian governments over Canadian entities and has said that we will be "amenable to a variety of approaches" for foreign utilities to mitigate transmission market power. British Columbia Power Exchange Corporation, 78 FERC  61,024 (1997); accord, TransAlta Enterprises Corporation, 75 FERC  61,268 (1996) and Energy Alliance Partnership, 73 FERC  61,019 (1995). Docket Nos. RM95-8-001 -33- and RM94-7-002 over foreign entities. Rather, we are simply placing the same reasonable and fair condition on both types of entities' uses of the transmission ordered in the Final Rule. 355/ Rehearing Requests Unconstitutional as Applied to NE Public Power District NE Public Power District asserts that the reciprocity provision as applied to NE Public Power District (a public corporation and political and governmental subdivision under Nebraska law) is unconstitutional. It argues that reciprocity would intrude into the sovereignty of Nebraska and would negate the decision of Nebraska's citizens to use their own governmental institutions to provide electric service. Moreover, contrary to the Commission's assertion, NE Public Power District states that it does not have a real choice in deciding whether to use the transmission service of public utilities. Because it is beyond the power of Congress to compel Nebraska to adopt a federally prescribed program for providing its citizens with electric utility services, NE Public Power District argues that it must follow that a federal agency lacks the constitutional and EEI and Ontario Hydro note that section 6 of the tariff limits the obligation of foreign utilities to provide reciprocal service to "facilities used for transmission of electric energy in interstate commerce owned, controlled or operated by the Transmission Customer. . . ." (EEI at 14). This is inconsistent with the preamble, which says that the reciprocity provision applies to foreign entities (whose transmission facilities may not be "interstate"). We recognize that the language in section 6 of the pro forma tariff conflicts with the preamble language of the Final Rule. We are modifying section 6 of the tariff accordingly. Docket Nos. RM95-8-001 -34- and RM94-7-002 statutory authority to compel a Nebraska state instrumentality to adopt a FERC-drafted tariff and to modify its contracts. NE Public Power District states that section 201(f) of the FPA exempts state-owned utilities from the jurisdiction of the Commission and that sections 211-213 are the exclusive means by which the Commission can require non-public utilities to perform involuntary transmission service. It asserts that the Commission should exempt publicly-owned utilities from application of the Final Rule and notes that virtually all non-public utility entities are, or soon will be, voluntary participants in power pools, RTGs, or other similar organizations. Thus, NE Public Power District argues that there is no compelling public interest to require these entities now to submit to the reciprocity provision. In addition, NE Public Power District argues that compliance would conflict with Nebraska law and bond covenants, i.e., Nebraska law, for example, does not permit a public entity to agree in advance of a dispute to submit to binding arbitration. NE Public Power District states that it is bound by a bond covenant that prohibits it from rendering service free of charge and requires that a customer's default must be cured within a specific time. It also argues that these requirements are in conflict with section 7.3 of the pro forma tariff. Docket Nos. RM95-8-001 -35- and RM94-7-002 Commission Conclusion Under the Supremacy Clause of the Constitution, Nebraska law cannot and does not override this Commission's authorities and responsibilities under the FPA. Rather, this Commission has exclusive jurisdiction over the rates, terms and conditions of transmission in interstate commerce by public utilities, including reciprocity conditions contained in the tariffs of public utilities. Nothing in Order No. 888 compels Nebraska to adopt a "federally prescribed program." While we do not have full jurisdiction over non-public utilities, 356/ our actions in regulating jurisdictional matters may impact those who wish to use jurisdictional services or to enter into agreements with public utilities. The Commission's obligation is to ensure that public utilities' services are just and reasonable and not unduly discriminatory or preferential and non-public utilities can choose to comply or not regarding matters within our exclusive jurisdiction. Moreover, as we explained above, NE Public Power District can seek waiver of the reciprocity condition on a case- by-case basis. Rehearing Requests QF Position American Forest & Paper asks the Commission to clarify that QFs are exempted from the reciprocity requirement or, in the We do have jurisdiction over many non-public utilities under certain sections of the FPA, e.g., sections 210, 211 and 212. Docket Nos. RM95-8-001 -36- and RM94-7-002 alternative, grant them a blanket waiver. It states that QFs are not allowed to provide transmission service for third parties. Moreover, it asserts that there are unlikely to be many requests for transmission service over a QF's interconnection line and such cases should be handled on a case-by-case basis. Commission Conclusion We will not grant QFs an exemption from the reciprocity condition or grant them a blanket waiver, but will address this issue on a case-by-case basis if and when it arises. Because most QFs own little transmission, it is not likely that they will be asked to provide reciprocal service. Furthermore, in a proceeding involving a QF, we explained that use of a QF's transmission line by a non-QF would not affect its QF status: It would not fail the ownership test for QF status because, consistent with the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA), the Oxbow Geothermal facility would continue to be "owned by a person not primarily engaged in the generation or sale of electric power (other than electric power solely from cogeneration facilities or small power production facilities)." 16 U.S.C.  796(18)(B)(1994). [357/] If a QF that owns, controls or operates interstate transmission facilities seeks open access transmission from a public utility, Oxbow Power Marketing, 76 FERC  61,031 at 61,179 (1996), reh'g pending. We did note, however, that the QF would become a public utility to the limited extent it provides transmission service over its line on behalf of others. Docket Nos. RM95-8-001 -37- and RM94-7-002 it must agree to provide reciprocal service to that public utility. Of course, the QF could file a waiver request in a separate proceeding, as set forth in the Final Rule and clarified in a subsequent order. 358/ Rehearing Requests Tax-Exempt Financing Issues Reciprocity and Private Activity Bonds EEI asks the Commission to require non-public utilities claiming that their tax status is a bar to granting reciprocity to substantiate such claim in a safe harbor proceeding and to take reasonable measures to request the IRS to allow them to provide reciprocal service while retaining their tax status. If the Commission decides not to require a safe harbor proceeding, EEI requests that the Commission require non-public utilities to substantiate their tax concerns and to demonstrate to each public utility from which they seek service that they are actively pursuing the issue with the IRS. 359/ It also urges that the Commission require any request for exemption from the reciprocity requirement that is based on jeopardy to tax-exempt status be filed with the Commission as part of a request for declaratory order in a safe harbor proceeding. Moreover, it requests that the Commission require a non-public utility to specifically identify the facilities it cannot use without jeopardizing its See Order Clarifying Order Nos. 888 and 889 Compliance Matters, 76 FERC  61,009 at 61,027 (1996). See also Tucson Power. Docket Nos. RM95-8-001 -38- and RM94-7-002 tax-exempt financing and to provide copies of, and specifically reference the tax provisions in, the related financing agreements that embody this restriction. Centerior asks that the Commission condition receipt of open access transmission service by municipal utilities upon the elimination or mitigation of tax subsidies and regulatory inequities. Southern maintains that tax-exempt status can remain undisturbed if non-public utilities do not seek open access transmission service from public utilities. Thus, Southern asserts, non-public utilities can weigh the benefits of transmission service under the Final Rule against the potential threat to their tax benefits, and make the choice that serves their best interest. At a minimum, it argues, the Commission should await the determinations of the IRS before finalizing this aspect of the reciprocity provision, rather than confer yet another unique benefit on non-public utilities. 360/ CAMU asks that the Commission defer reciprocity obligations until the IRS has clarified the status of private use limitations within the context of transmission access. Otherwise, CAMU asserts, innocent investors could suffer penalties because the Commission moved too quickly on this sensitive issue. See also SoCal Edison. It asserts that the Commission should require publicly-owned utilities to provide open access on the same terms as other utilities after a short transitional period that provides an opportunity for the IRS and/or Congress to address the interrelationship between open access transmission and tax-exempt financing. Docket Nos. RM95-8-001 -39- and RM94-7-002 Local Furnishing Bonds Local Furnishing Utilities and ConEd state that section 5.1 of the pro forma tariff applies to "Transmission Service," which is defined in section 1.48 to include point-to-point service, but not network service. They ask the Commission to clarify that the phrase "transmission service" also applies to network service. Local Furnishing Utilities and ConEd ask that the Commission confirm that all costs associated with the loss of tax-exempt status, including defeasing, redeeming, and refinancing tax- exempt bonds, will be considered costs of providing transmission that must be borne by the customer for whom the transmission is provided. They state that defeasance and refinancing costs are just as attributable to the particular transmission service causing such defeasance or redemption as the costs of expanding the system are attributable to the service that cause the need for such expansion. They ask that the Commission clarify that a transmission provider may include in its tariff a provision permitting the recovery of such costs, even if a filing under section 205 of the FPA is required. ConEd asserts that if a customer does not want to pay costs associated with the loss of tax-exempt status on the bonds, the Commission should allow the transmission provider to decline to provide the requested service. Local Furnishing Utilities and ConEd also assert that section 5.2 of the pro forma tariff should be clarified to state that issuance of a section 211 order by the Commission is a Docket Nos. RM95-8-001 -40- and RM94-7-002 condition precedent to the provision of transmission service. Local Furnishing Utilities states that there is a question whether the Commission should insist on waiver of the issuance of a proposed order under section 212(c). According to Local Furnishing Utilities, the negotiations that normally would follow the issuance of a proposed order are likely to provide the only opportunity to demonstrate and review the costs associated with the loss of tax-exempt status. Local Furnishing Utilities and ConEd assert that sections 5.1 and 5.2(i) of the pro forma tariff improperly limit the safe harbor protection of section 1919 of EPAct to transmission providers that financed "transmission facilities" with local furnishing bonds. Because of this, they assert, the safe harbor is not available to ConEd, all of whose local furnishing bonds have been used to finance its distribution system. They argue that section 5.1 should apply to service that would jeopardize the tax-exempt status of bonds that finance distribution or generation, as well as transmission, facilities. NE Public Power District contends that section 5.2(ii) should be amended "to make it clear that interim service need not be begun if rendering the service would endanger the tax-exempt status of the provider's bonds, unless the customer agrees to bear the financial consequences of such loss of tax-exempt status and has the wherewithal to do so." (NE Public Power District at 22-23). Docket Nos. RM95-8-001 -41- and RM94-7-002 SoCal Edison argues that local furnishing utilities should be required to comply with the Final Rule without any exception based upon their tax-exempt bonds. Commission Conclusion Private Activity Bonds As we explained in Order No. 888, it is not our purpose to disturb Congress's and the IRS's determinations with respect to tax-exempt financing. With respect to private activity bonds, we reaffirm our finding that reciprocal service will not be required if providing such service would jeopardize the tax-exempt status of the transmission customer's (or its corporate affiliates') bonds used to finance such transmission facilities. We remain hopeful that the IRS in its private activity bond rulemaking will, to the maximum extent possible, remove regulatory impediments that limit the ability of industry participants to provide reciprocal open access. As we indicated in Order No. 888, after the IRS acts, we will reexamine our policy to ensure that the reciprocity condition is applied broadly to achieve open access without jeopardizing tax-exempt financing. 361/ We will reject the request of EEI and Tucson Power that the Commission require non-public utilities to substantiate in a safe We note that on January 10, 1997, the IRS issued final regulations on the definition of private-activity bonds applicable to tax-exempt bonds issued by state and local governments, but reserved section 1.141-7 dealing with output contracts to further consider the issues raised by regulatory changes in the electric power industry. 62 FR 2275 (January 16, 1997). Docket Nos. RM95-8-001 -42- and RM94-7-002 harbor proceeding a claim that their tax status is a bar to granting reciprocity. As we stated in Order No. 888, if a non- public utility has sought a declaratory order on a voluntarily- filed tariff, we request that it identify the services, if any, that it cannot provide without jeopardizing the tax-exempt status of its financing. However, we cannot require that a non-public utility use the safe harbor mechanism, whether to file a reciprocal tariff with the Commission or to substantiate a claim as to loss of tax-exempt status. As we explain above, the safe harbor procedure is a voluntary means for non-public utilities to obtain a Commission determination that they meet the reciprocity condition in the open access tariffs and thereby avoid potential delays or denials of open access service based on allegations that the transmission requestor does not meet reciprocity. Nevertheless, just as we believe that it is appropriate to condition the use of public utility open access tariffs on the agreement of the tariff user to provide reciprocal access to the transmission provider, we also believe it is appropriate to condition the use of public utility open access tariffs on the agreement of the non-public utility tariff user to substantiate any claim that providing reciprocal transmission service would jeopardize the tax-exempt status of its financing. The non- public utility can provide such substantiation by identifying for Docket Nos. RM95-8-001 -43- and RM94-7-002 the customer the services that it cannot provide without jeopardizing its tax-exempt financing. 362/ Southern suggests that tax-exempt status can remain undisturbed if non-public utilities do not seek open access transmission service from public utilities and, therefore, that non-public utilities can weigh the benefits of transmission service under the Rule against the potential threat to their tax benefits. We believe it is important to remember why we required open access in the first place -- as a remedy for undue discrimination in transmission services in interstate commerce. Southern would force a non-public utility to give up a Congressionally-mandated right as a condition to taking open access transmission. Clearly Southern's suggestion is misplaced and overbroad. 363/ For this reason, we believe that our In response to EEI's request that the Commission require a non-public utility to provide copies of, and specifically reference the tax provisions in, the related financing agreements, we note that the level of detail needed to substantiate a non-public utility's claim that providing reciprocal transmission service would jeopardize the tax- exempt status of its financing is likely to depend on the facts of each case. As a result, what will constitute adequate substantiation is properly determined on a case-by- case basis. Additionally, we will reject EEI's request that the Commission require non-public utilities to demonstrate that they are actively pursuing the issue with the IRS. As we explain above, the IRS is currently examining these issues; we in turn will reexamine our policy after the IRS acts to ensure that the reciprocity condition is applied broadly to achieve open access without jeopardizing tax- exempt financing. We will reject Centerior's request that the Commission condition receipt of open access transmission service by non-public utilities upon the elimination or mitigation of tax subsidies. As we stated in Order No. 888, Congress has Docket Nos. RM95-8-001 -44- and RM94-7-002 decision not to require reciprocal service if providing such service would jeopardize the non-public utility's tax-exempt financing -- pending action by the IRS in its private activity bond rulemaking -- is appropriate for the time being. 364/ We reiterate that we will reexamine our policy after the IRS acts. As we state above, we believe that ultimately the public interest is best served by nationwide open access. Local Furnishing Bonds We clarify, in response to Local Furnishing Utilities and ConEd, that the reference to "Transmission Service" in section 5.1 of the pro forma tariff was intended to be to "transmission service," and thereby to apply to point-to-point service as well as network service. We have revised section 5.1 accordingly. We further clarify that all costs associated with the loss of tax-exempt status, including the costs of defeasing, redeeming, and refinancing tax-exempt bonds, are properly considered costs of providing transmission services. Therefore, a customer that takes service, understanding that such service will result in loss of tax-exempt status, shall be responsible for such costs to the extent consistent with Commission policy, entrusted the IRS with the responsibility for implementing laws governing tax-exempt financing, and it is not this Commission's purpose to disturb Congress's and the IRS's determinations in that regard. In response to CAMU, we note that the Commission has, in effect, deferred -- pending IRS action -- a non-public utility's reciprocity obligation in cases in which the provision of reciprocal service would jeopardize the tax- exempt status of the non-public utility's financing. Docket Nos. RM95-8-001 -45- and RM94-7-002 and a transmission provider may include in its tariff a provision permitting it to seek recovery of such costs. We clarify that if the transmission customer is not willing to pay the costs associated with the transmission provider's loss of tax-exempt status, the transmission provider will not be required to provide the requested service. 365/ Local Furnishing Utilities and ConEd also ask the Commission to revise section 5.2 of the pro forma tariff to state that issuance of a section 211 order by the Commission is a condition precedent to the provision of transmission service. Under the tariff provision adopted by Order No. 888 to address situations in which the provision of transmission service would jeopardize the tax-exempt status of any local furnishing bonds used to finance a local furnishing utility's facilities, the customer requesting transmission service would tender an application under section 211 of the FPA. Within ten days of receiving a copy of the section 211 application, the transmission provider "will waive its rights to a request for service under Section 213(a) of the [FPA] and to the issuance of a proposed order under Section 212(c) of the [FPA] and shall provide the requested transmission service in accordance with the terms and conditions of this Tariff." 366/ We clarify that the Commission, upon receipt of Of course if the transmission provider can provide part of the requested service without jeopardizing tax-exempt status, it should offer to provide such service. Pro Forma Open Access Transmission Tariff, Section 5.2(ii). Docket Nos. RM95-8-001 -46- and RM94-7-002 the transmission provider's waiver of its rights to a request for service under section 213(a) and to the issuance of a proposed order under section 212(c), shall issue an order under section 211. 367/ Upon issuance of the order under section 211, the transmission provider shall be required to provide the requested transmission service in accordance with the terms and conditions of the tariff. Section 5.2 of the pro forma tariff has been revised accordingly. Local Furnishing Utilities and ConEd also contend that the language of sections 5.1 and 5.2(i) of the pro forma tariff improperly limits the safe harbor protection of section 1919 of EPAct to transmission providers that financed transmission facilities with local furnishing bonds. ConEd expresses concern that although all of its electric local furnishing bonds have We will reject Local Furnishing Utilities' request that the Commission reconsider whether it should insist on the transmission provider's waiver of the issuance of a proposed order under section 212(c). As Order No. 888 indicates, this aspect of the local furnishing provision of the tariff is similar to a provision included in the transmission tariff of San Diego G&E, one of the Local Furnishing Utilities. Waiver of the issuance of a proposed order enables a transmission provider to expeditiously provide service under section 5.2 of the pro forma tariff, thereby ensuring that any local furnishing bonds that may exist do not interfere with the effective operation of an open access transmission regime. Although Local Furnishing Utilities now apparently support the issuance of a proposed order on the basis that the negotiations that normally would follow are likely to provide an opportunity to review the costs associated with the loss of tax-exempt status, we believe that any dispute as to costs subsequently can be resolved without causing any delay in the provision of the requested transmission service. For example, the service could be provided at the maximum rate allowed by the Commission, subject to refund. Docket Nos. RM95-8-001 -47- and RM94-7-002 been used to finance its distribution system, the test as to whether those bonds have been used for the "local furnishing" of electricity is based in part on whether ConEd has been a "net importer" of energy into its service territory. As a result, ConEd argues that the use of its transmission system to wheel power from a generating source located inside ConEd's service territory to a customer located outside its service territory could cause ConEd to violate the net importer rule and thereby lose the tax exemption for the bonds used to finance its distribution system. ConEd asks the Commission to modify sections 5.1 and 5.2 of the pro forma tariff to make clear that those provisions apply to transmission providers that have financed any "facilities" (i.e., distribution and generation, not just transmission, facilities) with local furnishing bonds. As we explained in Order No. 888, we believe the local furnishing bonds provision in section 5 of the pro forma tariff is necessary and appropriate so that any local furnishing bonds that may exist do not interfere with the effective operation of an open access transmission regime. If the provision of transmission service pursuant to Order No. 888 would result in the loss of tax-exempt status for local furnishing bonds, regardless of whether the facilities financed with those bonds are transmission, distribution, or generation facilities, it is our intent that the provisions of section 5 would apply. Thus, we clarify in response to ConEd and Local Furnishing Utilities that, to the extent the provision of transmission under an open Docket Nos. RM95-8-001 -48- and RM94-7-002 access tariff would jeopardize the tax-exempt status of local furnishing bonds used to finance distribution or generation facilities (even if no transmission facilities were financed with such bonds), 368/ such situation would fall within the reference to "facilities that would be used in providing . . . transmission service" contained in sections 5.1 and 5.2(i). This is so because the loss of tax-exempt status in such circumstances would be directly attributable to the provision of transmission services under the Rule. Further, we said in Order No. 888 that "we will require any public utility that is subject to the Open Access Rule that has financed transmission facilities with local furnishing bonds to ConEd suggests that this might occur if, for example, the provision by ConEd of transmission service were to cause it to violate the net importer rule and thereby lose the tax exemption for bonds used to finance its local distribution system. Although we clarify above that section 5 of the pro forma tariff would apply to this situation, we note that it is not clear that wheeling required by the Commission would be counted for purposes of determining whether a public utility is a "net importer." In its committee report on the bill that became the Energy Policy Act, the House Ways and Means Committee stated: The committee believes further that, in applying the IRS ruling position that a local furnishing utility that is interconnected with other utilities (other than for emergency transfers of electricity) must be a net importer of electricity, the determination of whether the utility is a net importer should be made without regard to electricity generated by another party that is wheeled by the utility to a point outside its service area pursuant to a FERC order authorized under the bill. H.R. Rep. No. 102-474(VI), 102d Cong., 2d Sess. 25 (1992), reprinted in 1992 U.S.C.C.A.N. 2232, 2236. Docket Nos. RM95-8-001 -49- and RM94-7-002 include in its tariff" a provision similar to section 5 of the pro forma tariff. 369/ We clarify that we did not intend by this statement that the section 5 local furnishing bonds provision would only apply to public utilities that have financed transmission facilities with local furnishing bonds, and not those that have financed generation and distribution facilities with such bonds. As we explain above, it is our intent that the provisions of section 5 apply if the provision of transmission service pursuant to an open access tariff would result in the loss of tax-exempt status for local furnishing bonds, regardless of whether the facilities financed with those bonds are transmission, distribution, or generation facilities. Rehearing Requests Unfunded Mandates Reform Act NE Public Power District 370/ argues that the final regulations adopted in this proceeding "constitute[] an unfunded mandate under the Unfunded Mandates Reform Act of 1995 . . . ." 371/ It declares that Order No. 888 imposes significant costs upon local governments and that the Commission was required under the Unfunded Mandates Reform Act to consider the financial impact FERC Stats. & Regs. at 31,763; mimeo at 377. NE Public Power District is a public corporation and a political subdivision of the State of Nebraska that generates, transmits and delivers electric energy to wholesale and retail customers throughout the state. NE Public Power District at 2. NE Public Power District asserts that the Commission failed to respond to this issue as raised by NE Public Power District in its comments. Docket Nos. RM95-8-001 -50- and RM94-7-002 of its rulemaking upon state and local governments and to prepare and issue as part of its rulemaking process a statement containing certain specified analyses and estimates concerning this matter and a description of its pre-issuance consultations with state and local government authorities. To support its argument NE Public Power District relies upon: (a) Executive Order No. 12875, Enhancing the Intergovernmental Partnership (Executive Order); 372/ and (b) the Unfunded Mandates Reform Act of 1995 (the Act). 373/ Commission Conclusion We disagree with NE Public Power District. The Executive Order applies to every "executive department . . . [and] agency . . . ." 374/ It defines "executive agency" as "any authority of the United States that is an 'agency' under 44 U.S.C.  3502(1), other than those considered to be independent regulatory Executive Order No. 12875, 3 CFR 699-71 (1994); 58 Fed. Reg. 58,093-094 (1993). The Executive Order provides that, unless required by statute, no Executive department or agency shall promulgate any regulation that creates a mandate upon state, local or tribal governments unless it either: (a) provides the funds necessary to carry out the obligations; or (b) before promulgating the regulation, provides to the Director of the Office of Management and Budget: (1) a description of its consultation with the affected governments; (2) a statement of their concerns and copies of communications it has received from them; and (3) the reasons why it thinks the regulations should issue. The Unfunded Mandates Reform Act is Pub. L. No. 104-4, 109 Stat. 48 (1995)(to be codified at 2 U.S.C.  602, 632, 653, 658, 1501-1504, 1511-1516, 1531-1538, 1551-1556 and 1571). 3 CFR at 670; 58 FR 58093 (1993). Docket Nos. RM95-8-001 -51- and RM94-7-002 agencies, as defined in 44 U.S.C.  3502 (10)." 375/ In section 3502(10), the Federal Energy Regulatory Commission is defined as an independent regulatory agency. As a result, the Executive Order does not apply to the Commission. The Act similarly applies to federal agencies, but, as with the Executive Order, does not apply to independent regulatory agencies. 376/ Although the Act does not define "independent regulatory agency," there is no indication that Congress intended to exclude the Commission from the definition. In fact, in all instances in which Congress has defined the term "independent regulatory agency" of which we are aware, the Commission has been included. As noted, the Commission is defined as an independent regulatory agency in Title 44 U.S.C. Also, Title 42 U.S.C.  7176 provides that: For the purposes of chapter 9 of title 5, United States Code . . . [Executive Reorganization], the [Federal Energy Regulatory] Commission shall be deemed to be an independent regulatory agency. [377/] 3 CFR at 671; 58 FR at 58094 (1993)(emphasis supplied). 90 Stat 50 (to be codified at 2 U.S.C.  658). 42 U.S.C.A.  7176 (1995) (Department of Energy Organization Act) (P.L. 95-91, 91 Stat. 586)(1977). See also Pub. L. No. 104-13, the Paperwork Reduction Act of 1995  3502 (5), 109 Stat. 165 (1995) (to be codified at 44 U.S.C.  3502 (5)), which provides that "the term 'independent regulatory agency' means [among other agencies] . . . the Federal Energy Regulatory Commission." Docket Nos. RM95-8-001 -52- and RM94-7-002 Accordingly, we find that the Commission is an independent regulatory agency as used in the Act; therefore, it is not covered by the Act. Moreover, even if the Act applied to the Commission, the Final Rule will not impose a Federal mandate on state, local or tribal governments. Section 305 of the Act defines a "Federal mandate" as: any provision in [a] statute or regulation or [in] any Federal court ruling that imposes an enforceable duty upon State, local, or tribal governments[,] including a condition of Federal assistance or a duty arising from participation in a voluntary Federal program. [378/] The Open Access Final Rule imposes requirements only on certain public utilities 379/ and, pursuant to section 201(f) of the FPA, state and local governments, and their agencies, authorities and instrumentalities, are not public utilities. Additionally, although the Final Rule will allow public utilities' transmission tariffs to contain reciprocity provisions in order to ensure that public utilities offering open access transmission to others can obtain similar service from open access users, the reciprocity provision is not an enforceable duty. A duty is mandatory; it is an obligation to perform and is 109 Stat. 70 (to be codified at 2 U.S.C.  1555)(emphasis supplied). I.e., those that own, operate or control interstate transmission facilities and do not obtain a waiver from the Commission. Docket Nos. RM95-8-001 -53- and RM94-7-002 compulsory. 380/ The reciprocity provision is merely a condition of receiving a benefit, i.e., open access transmission service from a public utility. 381/ There is no requirement that NE Public Power District promulgate an open access tariff and apply to FERC for a declaratory order. Moreover, as we explained above, non-public utilities, such as NE Public Power District, are free to seek from a public utility a waiver of the open access tariff reciprocity condition. With regard to the Stranded Cost Final Rule, while it applies to non-public utilities as well as public utilities, it does not impose a duty on any entity since it merely permits public utilities and transmitting utilities to seek recovery of certain costs. As a result, since the Open Access and Stranded Cost final rules will not impose an enforceable duty on state, municipal or tribal power agencies such as NE Public Power District, the rules are not Federal mandates as defined in the Act. Dayton Hudson Corp. v. Eldridge, 742 S.W. 2d 482, 485-86 (1987); Kerrigan v. Errett, 256 N.W. 2d 394, 399 (1977); Huey v. King, 415 S.W. 2d 136, 138 (1967); Black's Law Dictionary 505 (6th ed. 1990). A state or municipal power authority, such as NE Public Power District, does not have to agree to reciprocity, and the Commission cannot force it to do so. The Commission is not requiring state or municipal power authorities to provide transmission access. If non-public utilities elect not to take advantage of open access services because they don't want to meet the tariff reciprocity provision, they can still seek voluntary, bilateral transmission service from public utilities. Docket Nos. RM95-8-001 -54- and RM94-7-002 Because the Unfunded Mandates Reform Act of 1995 does not apply to the Commission and, in any event, the Open Access/Stranded Cost final rules do not impose Federal mandates on state, local or tribal governments, we reject NE Public Power District's argument that the Unfunded Mandates Reform Act of 1995 is applicable here. 5. Liability and Indemnification In the Final Rule, the Commission explained that the indemnification provision was broken into two parts (set forth in section 10.1 (Force Majeure) and section 10.2 (Indemnification) of the pro forma tariff). 382/ The Commission explained that the first part is a force majeure provision which provides that neither the transmission provider nor the customer will be in default if a force majeure event occurs, but also provides that both the transmission provider and customer will take all reasonable steps to comply with the tariff despite the occurrence of a force majeure event. The Commission explained that the second portion of the provision provides for indemnification against third party claims arising from the performance of obligations under the tariff. The Commission limited the indemnification portion of the provision so that it is only the transmission customer who indemnifies the transmission provider from the claims of third parties. The Commission explained that the revised provision FERC Stats. & Regs. at 31,765-66; mimeo at 384-85. Docket Nos. RM95-8-001 -55- and RM94-7-002 provides that the customer will not be required to indemnify the transmission provider in the case of negligence or intentional wrongdoing by the transmission provider. Rehearing Requests A number of utilities argue that the Commission has expanded transmitter liability beyond the existing standard in the industry, i.e., gross negligence. 383/ They assert that the Commission has provided no basis to subject transmission providers to liability, including consequential damages, due to ordinary negligence. KCPL points out that 21 of 25 states addressing this issue hold that a utility should not be liable for ordinary negligence. It declares that society will be worse off in litigation expenses and wasted human resources if utilities are held liable for simple negligence. It adds that the electric industry is much more susceptible to liability from interruptions of service than gas pipelines (refuting the Commission's reliance on Pacific Interstate Offshore Company, which it states is traceable to United Gas Pipeline Co. v. FERC, 824 F.2d 417 (5th Cir. 1987)). Florida Power Corp asks the Commission to modify section 10.2 to provide that a customer must indemnify the transmission provider except where a finder of fact determines that the transmission provider has committed gross or intentional wrongdoing. It also argues that the Commission Coalition for Economic Competition, EEI, KCPL, Florida Power Corp. Docket Nos. RM95-8-001 -56- and RM94-7-002 should eliminate liability of both the transmission provider and the customer to the other for consequential damages. Southern argues that the exception language in section 10.2 should be changed to "except where a court has determined that the Transmission Provider has engaged in intentional wrongdoing or has been grossly negligent." (Southern at 20-21). Southern also argues that the Commission should limit consequential damages arising from negligence in the operation of the transmission system. Puget asserts that the exception language in section 10.2 should be changed to "except in cases of and to the extent of comparative or contributory negligence or intentional wrongdoing by the Transmission Provider." (Puget at 18). It also asserts that the Commission should exclude liability for special, incidental, consequential, or indirect damages. EEI argues that the Commission should add a new section 10.3: "If the Transmission Provider is found liable for any damages associated with this Tariff, those damages shall be limited to direct damages, and the Transmission Provider shall not be liable for any special, indirect or consequential damages of any nature by virtue of the transactions conducted under this Tariff." (EEI at 26). Coalition for Economic Competition argues that the Commission should modify section 10.2 to provide that the transmission provider will not be liable to a transmission customer or any third party for damages caused by interruptions Docket Nos. RM95-8-001 -57- and RM94-7-002 or irregular or defective service, except if gross negligence or wilful misconduct caused such damages. 384/ Coalition for Economic Competition asserts that the definition of force majeure should include ordinary negligence and asks that the Commission clarify that a utility is not liable for force majeure events. CCEM also argues that transmission customer indemnity in section 10.2 should attach only to legal actions brought by customers of the transmission customer or third-party beneficiaries of those customers. On the other hand, TDU Systems argues that the indemnity provision unfairly provides the transmission provider with virtually total indemnification for acts on its side of the delivery point, but provides no reciprocal protection to the transmission customers for damage incurred on the customers' system in connection with purchasing the transmission provider's services. CSW Operating Companies asks the Commission to revise the pro forma tariff to provide that a transmission provider will not be liable for errors in an estimate made in good faith and in accordance with its published procedure. They propose the following language: Information posted on the OASIS concerning the availability of transfer capability will be based on the Transmission Provider's best estimates given the information readily and See also EEI at 26 (suggesting "except in cases of a finding by a trier of fact of gross negligence or intentional wrongdoing by the Transmission Provider"). Docket Nos. RM95-8-001 -58- and RM94-7-002 actually available to the transmission provider. No such estimate will be binding on the Transmission Provider for any purpose. Alternatively, they ask the Commission to clarify that as long as a transmission provider in good faith follows its published methodology for determining ATC and TTC it will be deemed not to be negligent. Commission Conclusion The purpose of the force majeure provision in the pro forma tariff is to ensure that neither the customer nor the transmission provider is held in default in the event of an unpredictable and uncontrollable force majeure event. It was not the Commission's intention that the force majeure clause provide an avenue for a party to claim that it is excused from liability for its own negligence. A force majeure event does not include an act of negligence or intentional wrongdoing. The pro forma tariff will be changed accordingly. 385/ The purpose of the indemnification provision is to allocate the risks of a transaction, and the costs associated with those risks, to the party on whose behalf the transaction has been conducted, the transmission customer. As the tariff does not obligate the customer to perform services on behalf of the See Tex-La Electric Cooperative of Texas, Inc., 69 FERC  61,269 (1994) (requiring clarification that force majeure clause in electric transmission agreement does not excuse negligence); Avoca Natural Gas Storage, 68 FERC  61,045 (1994) (requiring modification of force majeure provision to ensure that parties would be liable for negligence or intentional wrongdoing). Docket Nos. RM95-8-001 -59- and RM94-7-002 transmission provider, there is no comparable basis for imposing an indemnification obligation on the transmission provider. 386/ As is explained in the Final Rule, the Commission does not believe it appropriate to extend the indemnification obligation so that it would apply even in cases where the transmission provider has been negligent. The contention that electric transmission outages are either more frequent or more costly than gas outages does not serve to distinguish the electric transmission situation from the gas pipeline cases in which the Commission has found that indemnification clauses should not protect the pipeline owner from its own negligence. 387/ In either case, it would be inappropriate to require the customer to indemnify the transmission provider from damages arising from the transmission provider's own negligence. We note, however, that liability is a separate issue from indemnification. Despite the absence of indemnification protection, there is nothing in the indemnification provision that would preclude transmission providers from relying on the protection of state laws, when and where applicable, protecting utilities or others from claims founded in ordinary negligence. The Commission notes that in the past it may have accepted agreements containing gross negligence in force majeure and indemnification provisions. Consistent with the Commission's general policy of not abrogating existing contracts, we leave those provisions undisturbed. See, e.g., Pacific Interstate Offshore Company, 62 FERC  61,260 at 62,733-734 (1993) (requiring amendment of indemnification provisions that required indemnification except in cases of "gross negligence"). Docket Nos. RM95-8-001 -60- and RM94-7-002 With respect to the issue of consequential and indirect damages, the indemnification provision already provides protection to the transmission provider from consequential and indirect damage claims by third parties except in cases of negligence or intentional wrongdoing by the transmission provider. The Commission sees no need to further extend this protection. Again, we note that liability is a separate issue from indemnification, and that nothing in these provisions precludes transmission providers or customers from relying, when and where such law is applicable, on the protection of statutes or other law protecting parties from consequential or indirect damages. Furthermore, we will not revise the pro forma tariff, as requested by CSW Operating Companies, to provide that a transmission provider will not be liable for errors in an estimate made in good faith or in accordance with its published procedure. We believe that a utility should have no different a liability standard for operating an OASIS than for its other operations. 388/ 6. Umbrella Service Agreements The Commission received requests for clarification regarding this issue, which was not specifically addressed by the Commission in the Final Rule. Rehearing Requests See, e.g., Texas Eastern Transmission Corporation, 62 FERC  61,015 at 61,107 (1993). Docket Nos. RM95-8-001 -61- and RM94-7-002 SoCal Edison argues that it is too burdensome to require a separate Completed Application and a separate Service Agreement to be executed for each individual service transaction for short- term firm and non-firm transmission service (and filed with the Commission). SoCal Edison contends that requiring a separate service agreement for each short-term firm transaction to be filed with the Commission will stifle transactions in the short- term market. It indicates that it suggested a simpler approach in Docket No. ER96-222-000 that would establish a non-transaction specific Service Agreement and a Completed Application that would contain the specific transaction information, but would not be filed with the Commission, but would be made available for audit. 389/ Commission Conclusion SoCal Edison misinterprets the tariff provisions regarding service agreements for non-firm point-to-point transmission service. Tariff section 14.5 details the treatment of service agreements for non-firm transmission service: The Transmission Provider shall offer a standard form Non-Firm Point-To-Point Transmission Service Agreement (Attachment B) to an Eligible Customer when it first submits a Completed Application for Non-Firm Point- To-Point Transmission Service pursuant to the tariff. (Emphasis added) Moreover, in tariff section 18 (Procedures for Arranging for Non-Firm Point-To-Point Transmission Service) requires that a separate service agreement be executed for each individual To date, the Commission has only issued a suspension order in this proceeding. Docket Nos. RM95-8-001 -62- and RM94-7-002 service transaction as claimed by SoCal Edison. In the pro forma tariff, the Commission established a non-transaction specific (or "umbrella") service agreement in an attempt to streamline the application procedures for non-firm point-to-point transmission service. Therefore, the service agreement for non-firm point-to- point transmission service need only be executed and filed with the Commission once, when the transmission customer first applies for non-firm point-to-point transmission service. Subsequent non-firm transactions by the same customer only require the submission of a completed application (as provided in tariff sections 18.1 and 18.2) by that customer, which will be submitted via the transmission provider's OASIS (when the OASIS is fully implemented). Accordingly, no changes are required to the application procedures for non-firm point-to-point service. However, we do find SoCal Edison's arguments persuasive that streamlined procedures should also be applied to applications for firm point-to-point transmission service with a duration of less than one year (short-term firm). We agree that there is no compelling reason to require the submission of separate service agreements for every short-term firm transaction. Accordingly, we will adopt an "umbrella" service agreement approach (as is currently used for non-firm point-to-point transactions) and require a service agreement of general applicability to be filed with the Commission when the first short-term firm transaction is arranged between the transmission provider and customer. Docket Nos. RM95-8-001 -63- and RM94-7-002 In order to facilitate an umbrella service agreement approach for short-term firm transmission service, minor modifications have been made to several sections of the pro forma tariff 390/ as well as to Attachment A (Form of Service Agreement For Firm Point-To-Point Transmission Service). Notably, pages 3 and 4 of the service agreement, containing transaction specific information, is now required only for long-term firm point-to- point transmission service. 7. Other Tariff Provisions a. Minimum and Maximum Service Periods In the Final Rule, the Commission adopted a one-day minimum term for firm point-to-point service. 391/ The Commission also concluded that it will not specify a maximum term for either firm point-to-point or network transmission service. However, the Commission modified the tariff to require that an application for transmission service specify the length of service being requested. Rehearing Requests CCEM states that a competitive market for hourly trades should be allowed to develop (transmission and ancillary services). It argues that contrary to the Commission's goal of comparability, the Rule effectively allows only incumbent See changes to tariff sections 1.33, 1.34, 13.4, 13.7 and 17.3. FERC Stats. & Regs. at 31,752-53; mimeo at 346-47. Docket Nos. RM95-8-001 -64- and RM94-7-002 utilities to participate in hourly markets on behalf of their own or network loads (citing section 13.1 of the pro forma tariff). American Forest & Paper argues that firm and non-firm service should be made available on an hourly basis and that the Commission should assure that utilities make non-firm service available. Commission Conclusion It is unclear as to what hourly "trades" CCEM is referring. If CCEM is referring to off-system sales, the transmission provider is obligated to take transmission for any off-system sales under point-to-point transmission service under its tariff. Inasmuch as the tariff does not require the provision of hourly firm transmission, in order to provide itself with hourly firm transmission, the transmission provider would either: (1) reserve firm point-to-point service on a daily basis in order to participate in the hourly market or (2) propose in a section 205 filing to modify its tariff to voluntarily provide hourly firm point-to-point service. Under either circumstance, comparability would be maintained as all point-to-point customers would have equal access to the hourly market. If CCEM is referring to purchases, hourly economy purchases by the transmission provider on behalf of its native load customers are also available on a comparable basis to network customers. However, if CCEM is referring to specific purchases made on behalf of a particular wholesale customer, this resale Docket Nos. RM95-8-001 -65- and RM94-7-002 must be provided under point-to-point transmission service, as described above. The Commission has rejected hourly firm point-to-point transmission service as a mandatory service to be provided under the Tariff. 392/ Many entities would not oppose hourly firm service if afforded a lower priority, i.e., if they were curtailed before longer-term firm services. However, with this lower priority there may be little or no difference between the pro forma tariff non-firm service and curtailable firm hourly service. The Commission adopted the one-day minimum term for firm service to address concerns that customers would engage in "cream skimming" by taking firm service only during the hours at the daily peak while taking non-firm service for other hours, and thereby avoiding paying a fair share of the costs of the transmission system. However, this does not mean that the Commission would not allow such services if voluntarily proposed by a transmission provider. Finally, in response to American Forest & Paper, the transmission provider has every incentive to make non-firm service available to all eligible customers in order to benefit native load customers, as the revenues generated by this service are typically used as a revenue credit to offset the costs of providing firm service. In addition, parties may raise concerns with the Commission in a section 206 complaint if the FERC Stats. & Regs. at 31,752; mimeo at 346. Docket Nos. RM95-8-001 -66- and RM94-7-002 transmission provider offers non-firm transmission service in a non-comparable, i.e., unduly discriminatory fashion. b. Amount of Designated Network Resources In the Final Rule, the Commission indicated that it will not change the limitation on the amount of resources a network customer may designate. 393/ The Commission explained that a transmission provider is required to designate its resources and is subject to the same limitations required of any other network customer. The Commission further explained that limiting the amount of resources to those that the customer owns or commits to purchase will protect a utility from having to incur costs that are out of proportion to the customer's load. With respect to the allocation of interface capacity under network service, the Commission clarified that a customer is not limited to a load ratio percentage of available transmission capacity at every interface. It explained that a customer may designate a single interface or any combination of interface capacity to serve its entire load, provided that the designation does not exceed its total load. Rehearing Requests A number of entities state that section 30.8 of the pro forma tariff should be clarified to conform to the Final Rule preamble. The preamble states that a network customer should not FERC Stats. & Regs. at 31,753-54; mimeo at 349-50. Docket Nos. RM95-8-001 -67- and RM94-7-002 be limited to a load ratio percentage of available transmission capacity at every interface, but may designate a single interface or any combination of interface capacity to serve its entire load, provided that the designation does not exceed its total load. However, they point out that section 30.8 of the pro forma tariff provides that a network customer's use of the transmission provider's total interface capacity with other transmission systems may not exceed the network customer's load ratio share. 394/ TAPS and Wisconsin Municipals ask the Commission to clarify the inconsistency by deleting the phrase "Ratio Share" at the end of the section 30.8. TAPS argues that section 30.8 of the tariff conflicts with the preamble, other sections of the tariff itself (see section 28), and recent Commission orders (Wisconsin Public Service Corporation, 74 FERC  61,022 at 61,064 and FMPA v. FPL, 67 FERC 61,167 at 61,484). It further argues that load ratio restrictions on total interface usage would expand the market power of transmission providers. EEI and Southern state that under section 30.8 and the related preamble language, it is unclear how the concept of load ratio share should be applied in the context of interface capacity, (i.e., is the network customer entitled to a load ratio share of available transmission capacity or total transmission capacity for an interface?). They argue that ATC is the E.g., NRECA, Blue Ridge, TDU Systems, Cleveland, AEC & SMEPA, Wisconsin Municipals, TAPS. Docket Nos. RM95-8-001 -68- and RM94-7-002 appropriate basis for calculating shares of interface capacity and state that the Commission should specify that network service entitles the user to a load ratio share of the available capacity of each interface. EEI adds that if sufficient interface capacity is available, a request by a network customer to use available interface capacity to bring in resources for network load in excess of its load ratio share of the interface should be accommodated under the point-to-point tariff and treated on a first-come, first-served basis. 395/ Florida Power Corp states that "[i]n order to clarify that network customers may obtain transmission service over the transmission provider's interfaces in excess of their load ratio shares, the Commission should clarify that additional interface capability may be purchased (subject to availability) as firm point-to-point transmission service." (Florida Power Corp at 29). Commission Conclusion We agree that the pro forma tariff should be conformed to the preamble language in the Final Rule so that the interface capacity is limited to the customer's total load, not a load ratio share. This is consistent with the Commission's recent rehearing order in FMPA v. FPL: We clarify that the phrase "that is, up to its share of the load, 3%" was not intended to limit FMPA's use of each interface to a discrete ratio (3%). Rather, FMPA, as well TAPS filed a response opposing these requests for rehearing. (TAPS Response). As we explained above, we will accept the TAPS Response. Docket Nos. RM95-8-001 -69- and RM94-7-002 as Florida Power, can use each interface, if capacity is available, to service its entire network load. If the interface is [constrained] [sic], they will either pay redispatch costs or expansion costs based on their load ratio share. [396/] c. Eligibility Requirements In the Final Rule, the Commission found that a non- discriminatory open access transmission tariff must be made available, at a minimum, to any entity that can request transmission services under section 211 and to foreign entities. 397/ Rehearing Requests VT DPS and Valero state that the Final Rule does not appear to contemplate that marketers will buy network service or that one network service customer might serve a portion of the requirements of another network customer. Thus, they argue that network load can be double counted. To resolve this problem, they argue, service should be made available to suppliers rather than load, as provided in the NorAm NIS tariff, Section 1.5. Commission Conclusion Power marketers are specifically named in the definition of Eligible Customer (Section 1.11), and nothing in the Network Integration Transmission Service prohibits marketers from serving customers and designating those customers' loads (or portions thereof) as the marketers' Network Loads. 74 FERC at 61,018. FERC Stats. & Regs. at 31,754; mimeo at 351. Docket Nos. RM95-8-001 -70- and RM94-7-002 Additional rehearing requests regarding eligibility are addressed in Section IV.C.1. (Eligibility to Receive Non- discriminatory Open Access Transmission). d. Two-Year Notice of Termination Provision In the Final Rule, the Commission deleted the notice of termination provision from the tariff. 398/ Rehearing Requests No requests for rehearing addressed this matter. e. Termination of Service for Failure to Pay Bill In the Final Rule, the Commission stated that section 7.3 of the Final Rule pro forma tariff provides that in the event of a customer default, the transmission provider may, in accordance with Commission policy, file and initiate a proceeding with the Commission to terminate service. 399/ Rehearing Requests El Paso asserts that the Commission does not have the authority to prohibit a transmission provider from terminating service to a customer that has failed to pay its bill until permission from the Commission has been obtained. It argues that the Commission does not have abandonment authority under the FPA. Commission Conclusion El Paso is not correct. Under section 205 of the FPA, public utilities are allowed to effectuate changes in rates, FERC Stats. & Regs. at 31,754-55; mimeo at 353. FERC Stats. & Regs. at 31,794; mimeo at 467. Docket Nos. RM95-8-001 -71- and RM94-7-002 charges, classification or service only after providing 60 days notice to the Commission and the public. Because a termination of service is clearly a change in service, public utilities must file notice of a termination 60 days prior to the proposed effective date. In Portland General Electric Company, 75 FERC  61,310, reh'g denied, 77 FERC  61,171 (1996), we denied a requested waiver of section 35.15 of the Commission's Rules of Practice and Procedure to permit the utility to terminate service in the event of customer default. We indicated that we had previously explained the reasons for requiring public utilities to file notices of termination when seeking to discontinue service 400/ and further explained that electricity is not just any commercial good or service. Rather, Congress in the Federal Power Act has charged us with ensuring that sales for resale or transmission of electricity in interstate commerce by public utilities take place at rates, terms and conditions that are just and reasonable. [401/] f. Definition of Native Load Customers The Commission defined the term "Native Load Customers" in section 1.19 of the pro forma tariff as: The wholesale and retail power customers of the Transmission Provider on whose behalf the E.g., to protect wholesale purchasers -- and, by extension, ultimate consumers -- from losing service unjustly; to provide the Commission an opportunity to ensure that the termination is just and reasonable. 77 FERC at 61,171. Id. Docket Nos. RM95-8-001 -72- and RM94-7-002 Transmission Provider, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate the Transmission Provider's system to meet the reliable electric needs of such customers. Rehearing Requests The pro forma tariff defines native load customers as "[t]he wholesale and retail power customers of the Transmission Provider. . . ." Cooperative Power argues that the definition of native load customers should recognize that joint planning is a sufficient criterion, and that construction and operation by the transmission provider should not be necessary for native load status to be conferred. It asserts that under joint planning, the loads of transmission-only customers are considered native, therefore the Commission should eliminate the word power from the definition. 402/ NRECA and TDU Systems state that traditional wholesale customers that have long been on the system, have assisted in paying for past expansions, and will likely continue to be captive to a provider's monopoly transmission service, should have "native load equivalent" rights if they take network or long-term firm service. If the transmission provider has planned and will plan in the future for a customer's full or partial Dairyland filed a supplemental request for rehearing raising similar arguments. (Dairyland Supplement). We will accept this pleading as a motion for reconsideration, not as a request for rehearing, because it was not filed within the 30-day statutory period for rehearing requests. See 16 U.S.C.  8251(a). Docket Nos. RM95-8-001 -73- and RM94-7-002 needs, they argue that the customer should be treated as the equivalent of native load. They point out that section 1.19 of the tariff limits native load status only to wholesale power customers of the transmission provider. VA Com argues that the definition of native load in section 1.19 of the tariff should include existing distribution cooperatives and others who currently provide service to end users. Commission Conclusion We reject Cooperative Power's suggestion to include transmission-only point-to-point customers in the definition of native load. We note that network customers are provided with rights comparable to native load customers because the transmission provider includes their network resources and loads in its long-term planning horizon. However, a point-to-point transmission service customer is not similarly situated to native load and Network Customers. The Network service formula rate requires the Network customer to pay a load-ratio share of the costs of the transmission provider's transmission system on an ongoing basis, while a point-to-point transmission service customer is only responsible for paying on a contract demand basis over the contract term. The network customer and the native load of the transmission provider pay all the residual costs of the transmission system and face greater risks of rate fluctuations due to facility additions and variations in load of both its and other customers. In contrast, the point-to-point Docket Nos. RM95-8-001 -74- and RM94-7-002 transmission service customer may be more transitory in nature electing shorter terms of service and specific forms of service tailored for discrete services over specific time periods that do not necessarily enter into the transmission provider's planning horizon. To the extent a transmission customer desires similar rights and cost responsibilities to a native load customer, it can always elect to take network service. We further note that, in granting a right of first refusal to existing customers, we afforded existing transmission only point-to-point customers a priority to continue to use the transmission provider's system. VA Com's proposed change to the definition of native load was made in conjunction with its proposed change in the reservation priority (highest priority for "native load", followed by firm contract customers and lastly, non-firm customers). Because we are rejecting VA Com's proposed reservation priority (see Section IV.G.3.a. above), we will also reject its proposed conforming change to the definition of native load as proposed by VA Com. g. Off-System Sales Regarding the unbundling of off-system sales, the Final Rule required that all bilateral economy energy coordination contracts executed before the effective date of Order No. 888 must be modified to require unbundling of any economy energy transaction Docket Nos. RM95-8-001 -75- and RM94-7-002 occurring after December 31, 1996. 403/ Concerning the treatment of revenues from transmission associated with off-system sales, the Commission stated in the Final Rule that revenue from non-firm services should continue to be reflected as a revenue credit in the derivation of firm transmission tariff rates. 404/ Rehearing Requests Montana Power asserts that the Commission should clarify that off-system sales that originate from generating plants or power purchases outside the transmission provider's system and do not use the transmission provider's transmission system should not be automatically assessed point-to-point charges. Maine Public Service asks the Commission to clarify that revenues from off-system sales are not to be credited where the sales do not use the transmission provider's system (referencing sections 1.44 and 8.1 of the pro forma tariff). Maine Public Service states that it makes sales from Maine Yankee (which is not located on Maine Public Service's system) to customers not on its system and that it should not have to credit these sales revenues to its transmission customers. Wisconsin Municipals asks the Commission to clarify that the provision and level of revenue credits are rate issues and that if parties have negotiated provisions for revenue credits, the FERC Stats. & Regs. at 31,700; mimeo at 191. FERC Stats. & Regs. at 31,738; mimeo at 304. Docket Nos. RM95-8-001 -76- and RM94-7-002 Final Rule cannot be used to avoid obligations undertaken in a settlement. Commission Conclusion Utilities must take all transmission services for wholesale sales under new requirements contracts and new coordination services under the same tariff used by eligible customers. The Commission provided an extension until December 31, 1996, for utilities to take transmission service under the same tariff for their economy energy transactions, certain power pooling arrangements, and other multi-lateral arrangements. 405/ The above criteria, however, only apply when a utility transmission system is being used to accommodate off-system sales. Therefore, a utility would not be required to take point-to-point transmission service if its transmission system is not being used for the transaction. Maine Public Service's concern is misplaced. Maine Public Service states that certain of its sales do not use its own transmission system and that it pays other utilities for such transmission service. However, Section 8.1 only specifies the treatment of revenues the transmission provider receives from transmission service it provides itself when making third-party sales using point-to-point transmission service under its tariff. If Maine Public Service is not the transmission provider for FERC Stats. & Regs. at 31,700; mimeo at 191. Docket Nos. RM95-8-001 -77- and RM94-7-002 these third-party sales, then Section 8.1 does not apply to such transactions. Wisconsin Municipals' argument with respect to prior settlements has been previously addressed in Section IV.D.1.c.(2) (Energy Imbalance Bandwidth). h. Requirements Agreements A detailed description of the Commission's unbundling requirements pertaining to requirements agreements is described below. Rehearing Requests Blue Ridge requests that the Commission clarify the definitions of requirements, economy and non-economy energy coordination agreements. In addition, Blue Ridge seeks clarification regarding which dates are to be used to distinguish between existing and new contracts (July 11, 1994 or July 9, 1996). Docket Nos. RM95-8-001 -78- and RM94-7-002 Commission Conclusion The definitions of economy and non-economy energy coordination agreements are addressed in section IV.F.4. (Bilateral Coordination Arrangements). With respect to Blue Ridge's concern regarding requirements agreements, we defined requirements contracts broadly in section 35.28(b)(1) of the Commission's regulations as "any contract or rate schedule under which a public utility provides any portion of a customer's bundled wholesale power requirements." The definition is intended to encompass partial requirements service, since that service is intended to meet the bundled load requirements of a customer that is not provided from other sources such as self- generation or unit power purchases. In contrast, a non-economy energy coordination agreement is not intended to meet, by itself, the entirety of a customer's bundled power requirement or the residual partial power requirement of a customer. For example, a 50 MW unit power purchase or a long-term firm power purchase would supply long-term firm power but a customer would likely need an additional partial requirements agreement to supply the residual amount of its load requirement. Regarding Blue Ridge's request for clarification of the dates for new and existing agreements, the Commission explicitly stated in Order No. 888 that any bilateral wholesale coordination agreements executed after July 9, 1996 would be subject to the functional unbundling and open access requirements set forth in Docket Nos. RM95-8-001 -79- and RM94-7-002 the Rule. 406/ In addition, the Commission required that all bilateral economy energy coordination contracts executed on or before July 9, 1996 be modified to require unbundling of any economy energy transaction occurring after December 31, 1996. The Commission permitted all non-economy energy bilateral coordination agreements executed before July 9, 1996 to continue in effect subject to section 206 complaints. For the purpose of distinguishing between existing and new wholesale requirements contracts and for stranded investment recovery provisions, the Commission established July 11, 1994 as the applicable date. 407/ For a utility to recover stranded investment costs in new requirements contracts, it must include explicit provisions in the contract for stranded investment recovery. Existing requirements contracts would not need a similar provision to be eligible for stranded investment recovery. 408/ Utilities are required to unbundle all new requirements contracts. The requirement that utilities unbundle existing wholesale requirements contracts is for informational purposes and will enable existing requirements customers to evaluate and compare the transmission component of existing contracts to alternative contracts prior to the existing contracts' expiration dates. FERC Stats. & Regs. at 31,729-30; mimeo at 277-78. Mimeo at 769. FERC Stats. & Regs. at 33,110 and 31,804-05; mimeo at 85 and 497-98. Docket Nos. RM95-8-001 -80- and RM94-7-002 i. Use of Distribution Facilities The Commission received requests for clarification regarding this issue which was not specifically addressed by the Commission in the Final Rule. Rehearing Requests CSW Operating Companies asks the Commission to make clear that to the extent a transmission provider makes available to transmission customers the use of distribution facilities, the terms governing the use of and the charges for such use should be set forth in the customer's service agreement. Commission Conclusion Utilities are free to include customer-specific terms and conditions or terms and conditions limited to certain customers (e.g., a distribution charge) in a customer's service agreement and/or the network customer's network operating agreement. j. Losses The Commission received requests for clarification regarding this issue which was not specifically addressed by the Commission in the Final Rule. Rehearing Requests VT DPS asserts that network customers should not have to bear losses twice -- the tariffs allow collection of losses over all network load, even that supplied by behind the meter generation. It argues that losses should only be paid on power actually transmitted over the company's system. Docket Nos. RM95-8-001 -81- and RM94-7-002 Commission Conclusion The pro forma tariff neither specifies the applicable Real Power Loss factors (see tariff section 28.5) nor the demand levels to which the loss factors should be applied. Accordingly, concerns regarding the loss calculation for a customer should be raised when the transmission provider files with the Commission a service agreement for a network customer. k. Modification of Non-rate Terms and Conditions The Commission's requirements pertaining to modification of non-rate terms and conditions is described below. Rehearing Requests TAPS asserts that the language of section 35.28(c)(1)(v) and the preamble of Order No. 888 are inconsistent. TAPS argues that the Commission should require a demonstration of consistency with and superiority to the terms and conditions of the pro forma tariff and indicate that it will not allow deviations that seek to withdraw the minimum terms and conditions of non- discriminatory transmission. According to TAPS, the Commission should also clarify that the Commission will not let onerous tariff terms creep in through the back door, i.e., through service agreements. TAPS also maintains that the Commission should not allow transmission providers to use conformity as an excuse to evade commitments. Commission Conclusion Order No. 888 allows a utility the flexibility to propose, after the compliance tariffs go into effect, to modify non-rate Docket Nos. RM95-8-001 -82- and RM94-7-002 terms and conditions of the tariff if it can "demonstrate[] that such terms . . . are consistent with, or superior to, those in the compliance tariff." These are the same principles that are referenced in the regulation language (deviations allowed if the transmission provider can demonstrate the deviation is consistent with the principles of Order No. 888). While utilities are free to file revised tariffs after their compliance filings, any filing including service agreements will be carefully reviewed by the Commission to assure that the revised tariffs and service agreements are just and reasonable and consistent with the principles of Order No. 888. With regard to TAPS' concern about transmission providers evading commitments, we reiterate that we will not require abrogation of existing contracts (and the commitments reflected therein) except on a case-specific basis. l. Miscellaneous Tariff Modifications (1) Ancillary Services The Commission explained that the pro forma tariff incorporates conforming revisions consistent with the determinations discussed in the Final Rule. 409/ (2) Clarification of Accounting Issues FERC Stats. & Regs. at 31,763; mimeo at 378. Docket Nos. RM95-8-001 -83- and RM94-7-002 In the Final Rule, the Commission offered clarifications on the Final Rule pro forma tariff requirements and certain other accounting issues related to the Final Rule. 410/ (a) Transmission Provider's Use of Its System (Charging Yourself) In the Final Rule, the Commission stated that the purpose of functional unbundling is to separate the transmission component of all new transactions occurring under the Final Rule pro forma tariff, thereby assisting in the verification of a transmission provider's compliance with the comparability requirement. With respect to off-system sales, the Commission stated that the transmission provider would book to operating revenue accounts those revenues received from the customer to whom it made the off-system sale. 411/ The Commission required that the transmission service component and energy component of those revenues be recorded in separate subaccounts of Account 447, Sales for Resale. Rehearing Requests APPA argues that the revenue from the transmission component of all off-system uses must be included in the credit if comparability is to be achieved. APPA also argues that booking revenue credits to Account 447 for a test year reduction does not ensure timely receipt by FERC Stats. & Regs. at 31,763-64; mimeo at 379-80. FERC Stats. & Regs. at 31,764; mimeo at 380-81. Docket Nos. RM95-8-001 -84- and RM94-7-002 customers. It asserts that a monthly pass-through to all firm transmission customers is needed. APPA further argues that a properly functioning revenue credit does away with the perception of disparate treatment of network and point-to-point customers. Similarly, TDU Systems argues that comparability requires that revenues attributable to transmission owners' use of their transmission systems be flowed through to customers' benefit immediately so that transmission owners and customers receive comparable price signals with regard to their uses of the system. Commission Conclusion The precise methodology to be used to credit revenues from off-system sales for the benefit of the tariff customers should be addressed in the compliance filing proceedings and will depend on the particular rate design methodology that is ultimately employed. APPA's proposed monthly pass-through of revenue credits raises potential issues including: (1) use of estimates versus actuals; (2) the appropriate time period to be utilized; and (3) firm versus non-firm distinctions. Accordingly, the issue of determining appropriate revenue credits is properly left for case-by-case determinations. However, we agree with APPA that revenue from the transmission component of all off-system uses of the transmission system (whether by the transmission provider or a transmission customer) must be treated on a comparable basis, whether through rate design or through revenue credits. Docket Nos. RM95-8-001 -85- and RM94-7-002 (b) Facilities and System Impact Studies In the Final Rule, the Commission explained that comparability mandates that to the extent a transmission provider charges transmission customers for the costs of performing specific facilities studies or system impact studies related to a service request, the transmission provider also must separately record the costs associated with specific studies undertaken on behalf of its own native load customers, or, for example, for making an off-system sale. 412/ Rehearing Requests No requests for rehearing addressed this matter. (c) Ancillary Services In the Final Rule, the Commission indicated that, at this time, it was 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. 413/ Rehearing Requests No requests for rehearing addressed this matter. (3) Miscellaneous Clarifications (a) Electronic Format In the Final Rule, the Commission required that public utilities, in addition to complying with the requirements of Part FERC Stats. & Regs. at 31,764; mimeo at 381-82. FERC Stats. & Regs. at 31,764-65; mimeo at 382-83. Docket Nos. RM95-8-001 -86- and RM94-7-002 35, submit a complete electronic version of all transmission tariffs and service agreements in a word processor format, with the diskette labeled as to the format (including version) used, initially and each time changes are filed. 414/ Rehearing Requests No requests for rehearing addressed this matter. (b) Administrative Changes In the Final Rule, the Commission set forth a number of tariff modifications that it indicated needed no further explanation. 415/ 8. Specific Tariff Provisions The Commission attached a pro forma tariff to the Final Rule as Appendix D. A number of entities have sought rehearing of various sections of that pro forma tariff. Their arguments and the Commission's responses are set forth below. Rehearing Requests Oklahoma G&E asks that the Commission add a definition for "Interconnection" that would be an interface where one or more points of delivery or points of receipt are located. Commission Conclusion We disagree with Oklahoma G&E that there is a need to add a definition for "Interconnection" to the Final Rule pro forma tariff. Oklahoma G&E has not supported its need for the proposed FERC Stats. & Regs. at 31,766; mimeo at 386. FERC Stats. & Regs. at 31,766-67; mimeo at 386-88. Docket Nos. RM95-8-001 -87- and RM94-7-002 change and has failed to identify any potential problems that may result if its definition is not included. Sections 1.12, 15.4 and 32.4 Rehearing Requests Cajun argues that the Commission should mandate joint planning in the development of Facilities Studies. It alleges that a transmission provider's independent long-range plans frequently include longer, higher voltage facilities than are needed for the transmission customers' requirements. It further alleges that absent mandatory joint transmission planning, the transmission customers will always be paying for the incremental capacity cost of transmission enhancements that only fit into the Transmission Provider's independent long-range plans. Commission Conclusion A joint planning mandate as recommended by Cajun, NRECA and others is beyond the scope of this proceeding. However, the Commission encourages utilities to engage in joint planning with other utilities and customers and to allow affected customers to participate in facilities studies to the extent practicable. Moreover, on a regional basis, the Commission encourages the formation of RTGs and ISOs to represent the needs of all participants in a region in the planning process. Section 1.14 Rehearing Requests CCEM asserts that the term Good Utility Practice is vague. It argues that the Commission should delete the reference to Docket Nos. RM95-8-001 -88- and RM94-7-002 regional practices, but if it does not, the term should be clearly defined in each utility's tariff. Commission Conclusion The Commission recognizes that unique operating practices and conditions exist on a regional basis throughout the industry. Accordingly, the Commission permits certain deviations to the non-price terms and conditions of the tariff. In the Final Rule, we stated that any proposed modifications by the utility to the tariff to recognize regional operations and practices must be demonstrated to be reasonable, generally accepted in the region, and consistently adhered to by the transmission provider. 416/ Sections 1.22 and 1.25 Rehearing Requests Blue Ridge requests clarification that a portion of a designated network resource need not consist of the entirety of a generating unit. Commission Conclusion Blue Ridge's request for clarification in the definition of "Network Load" in Tariff Section 1.22 and "Network Resource" in Tariff Section 1.25 is not necessary. Blue Ridge's concerns are based on the mistaken premise that a designated network resource FERC Stats. & Regs. at 31,770; mimeo at 397-98. The Commission has applied its approach to regional practices in filings made in compliance with Order No. 888. See, e.g., American Electric Power Service Corporation, et al., 78 FERC  61,070 (1997); Allegheny Power System, Inc., et al., 77 FERC  61,266 (1996); Atlantic City Electric Company, et al., 77 FERC  61,144 (1996). Docket Nos. RM95-8-001 -89- and RM94-7-002 must consist of the entirety of a generating unit. Tariff sections 1.25 and 30.1 explicitly specify that a network resource can be a portion of a generating resource or unit. Indeed, the Commission recently emphasized this point: Ohio Cooperatives have disregarded the fact that a designated resource can be a part of a unit. In this example, Ohio Cooperatives would make two network designations for the 300 MW unit: a 100 MW designation for the 100 MW load on one system and a 200 MW designation for the 200 MW on the other system. [417/] Sections 1.25 and 30.1 Rehearing Requests TDU Systems asserts that these sections should not be read to require assignment of specific Network Resources to specific control areas. They state that multiple control area network customers need to be able to dispatch their resources economically to serve their loads. They argue that the Commission would be in error to require that a transmission customer's resources be segmented if they are being dispatched to serve network load in one of several control areas and once so segmented, sales from such units be considered either third-party sales or become interruptible as to network load in a second control area and thus are not deemed Network Resources. They further argue that TDU systems with loads and resources in multiple control areas must be allowed to designate as Network Order On Non-Rate Terms and Conditions, 77 FERC  61,144 (mimeo at 15-16) (1996). Docket Nos. RM95-8-001 -90- and RM94-7-002 Resources for each control area the totality of their resources which meet the owned or purchased requirements of section 1.25. TDU Systems argues that these sections should be revised to include resources that are leased by a network customer on terms tantamount to ownership, or which, at a minimum, afford the network customer a first call right to that generating resource. Commission Conclusion TDU Systems' proposed revision to recognize leased resources appears reasonable and we revise these sections of the pro forma tariff, in relevant part, as follows (new text underlined, deleted text in brackets): 1.25 Network Resource: Any designated generating resource owned, [or] purchased or leased by a Network Customer under the Network Integration Transmission Service Tariff. 30.1 Designation of Network Resources: Network Resources shall include all generation owned, [or] purchased or leased by the Network Customer designated to serve Network Load under the Tariff. Sections 1.33 and 1.34 Rehearing Requests CCEM states that sections 1.33 and 1.34 should be changed to facilitate umbrella service agreements that include all points of receipt and delivery on a transmission provider's system. Docket Nos. RM95-8-001 -91- and RM94-7-002 Commission Conclusion Consistent with our ruling in section IV.G.6 (Umbrella Service Agreement) regarding umbrella type service agreements for short-term firm point-to-point transmission service, we will modify sections 1.33 and 1.34 to require that Points of Receipt and Points of Delivery be specified in the service agreement for only Long-Term (more than one year) Firm Point-to-Point Transmission service. Section 1.47 Rehearing Requests Wisconsin Municipals asks the Commission to clarify that a utility is not prevented from including the load of interruptible customers in the denominator of the fraction used to perform the load ratio calculation. It claims that this is important in Wisconsin where the transmission system is planned without regard to the distinction between firm and interruptible power customers (interruptible customers are not subject to interruption for transmission reasons). Commission Conclusion The treatment of interruptible loads in the planning and operation of the Wisconsin transmission grid present a unique, case-specific situation that is best addressed on a case-by-case basis. As the Commission stated in the Final Rule: all tariffs need not be "cookie-cutter" copies of the Final Rule tariff. Thus, under our new procedure, ultimately a tariff may go beyond the minimum elements in the Final Rule pro forma tariff or may account for regional, Docket Nos. RM95-8-001 -92- and RM94-7-002 local, or system-specific factors. The tariffs that go into effect 60 days after publication of this Rule in the Federal Register will be identical to the Final Rule pro forma tariff; however, public utilities then will be free to file under section 205 to revise the tariffs, and customers will be free to pursue changes under section 206. [418/] Section 1.48 Rehearing Requests Oklahoma G&E asks the Commission to clarify that the term "Transmission Service" as used in the pro forma tariff includes service provided on a network basis as well as on a point-to- point basis. Commission Conclusion The Commission used the term "Transmission Service" throughout the pro forma tariff to refer only to point-to-point service and not network service. We also note that the term "transmission service" (in lower case), which is also used throughout the pro forma tariff, was used to refer to both point- to-point and network service. Oklahoma G&E has not identified any problems associated with our use of these terms and therefore has not supported its proposed modification. Section 1.49 Rehearing Requests Santa Clara and Redding state that the transmission system is defined as facilities owned, controlled or operated and that FERC Stats. & Regs. at 31,770 n.514; mimeo at 399 n. 514. Docket Nos. RM95-8-001 -93- and RM94-7-002 this could result in the same transmission facilities being the part of the transmission system of two entities (e.g., COTP, which is owned by TANC, but operated by Western Area Power Administration (WAPA)). They ask the Commission to clarify that only one such entity should have the obligation to provide transmission service. Commission Conclusion This presents a fact-specific situation that is best addressed on a case-by-case basis. This situation would appear to arise for WAPA and TANC only if either utility receives a request for reciprocal transmission service or if either utility files a voluntary tariff. The appropriate entity to include the COTP facility in its transmission system for purposes of a transmission tariff may depend upon the circumstances of the transmission request. Therefore, a resolution of this question is appropriately deferred until such time as reciprocal service using the COTP facility is requested. Section 3 Rehearing Requests CCEM asks the Commission to clarify that a transmission customer may switch its supplier of ancillary services. Commission Conclusion The Final Rule requires that transmission customers obtain all necessary ancillary services for their transactions. They must purchase certain of these services from the transmission provider, but can self supply or obtain certain services from a Docket Nos. RM95-8-001 -94- and RM94-7-002 third party. Consistent with these requirements, a transmission customer may switch suppliers of ancillary services not required to be provided by the transmission provider if it continues to demonstrate that it satisfies its ancillary service obligations. Section 5.1 Rehearing Requests ConEd points out that this section applies to Transmission Service, which the tariff defines to mean point-to-point service only. It requests that this section be clarified to include network service. Commission Conclusion The use of the term "Transmission Service" in section 5.1 of the pro forma tariff was an inadvertent error. We will change the term "Transmission Service" used in section 5.1 to "transmission service" so as to include both point-to-point and network transmission service. Section 6 Rehearing Requests CCEM asks the Commission to require that the text of the required sworn statement by non-transmission owning entities that they are not assisting an Eligible Customer be included in the tariff. Commission Conclusion We will deny CCEM's request as unnecessary. The Commission does not believe that it must mandate the precise text of the required sworn statement. Rather, the entity requesting Docket Nos. RM95-8-001 -95- and RM94-7-002 transmission service properly has the burden of explaining in a sworn statement the circumstances of its service request, including on whose behalf it may be requesting service (for itself or for another party). Section 8 Rehearing Requests CCEM argues that, consistent with Commission policy for natural gas pipelines, transmission providers should be required to refund all "penalties" that are in excess of the costs incurred to balance transmitting system operations (citing Transco, 55 FERC  61,446 at 62,372 (1991) and TETCO, 62 FERC  61,015 at 61,117 (1993)). Commission Conclusion CCEM's argument is premature. Order No. 888 did not establish a rate or a penalty for Energy Imbalance Service. CCEM is free to raise this concern at such time as utilities file their proposed rates for Energy Imbalance Service. Section 11 Rehearing Requests CCEM contends that an unconditional and irrevocable letter of credit is extremely costly to obtain and could be used as subterfuge for discriminatorily denying service. CCEM argues that if an irrevocable letter of credit is used, a transmission provider should not be able to draw on it until it tenders a bill that has been improperly refused. (CCEM attached a proposed conditional letter of credit to its rehearing request). Several Docket Nos. RM95-8-001 -96- and RM94-7-002 entities argue that a letter of credit should not be required for existing customers with a satisfactory credit history and should only apply to new customers or those with a history of payment delinquency. 419/ Commission Conclusion While a transmission provider may require an unconditional and irrevocable letter of credit, if a customer believes that the transmission provider unreasonably rejected an alternative security proposal, it may seek relief through the dispute resolution procedures established in Tariff Section 12. Moreover, if a customer believes a transmission provider is attempting to use the unconditional and irrevocable letter of credit in an unduly discriminatory manner, it may file a complaint raising such concern in a section 206 filing. Section 12 Rehearing Requests According to Public Service Co of CO, the dispute resolution procedures: (1) should allow a party to appeal an arbitration award on the basis that arbitrators have misinterpreted the requirements of the pro forma tariff and (2) where a utility is a member of an RTG, should allow the RTG dispute resolution procedures to be exclusive. Otherwise, Public Service Co of CO argues, entities may perceive that the Commission's procedures are more favorable than the RTG's and decide not to join. E.g., Santa Clara, Redding, TANC. Docket Nos. RM95-8-001 -97- and RM94-7-002 Moreover, it asserts that when a utility that is a member of an RTG has a dispute with a customer that is a non-member, the customer's forum should be the Commission, or the RTG's procedures if those procedures apply to non-members. Dispute Resolution Associates asks the Commission to require that prior to submission of disputes for arbitration or Commission disposition, disputants should be required to pursue a mediated resolution with a qualified individual. If unsuccessful, it states that parties can elect arbitration or Commission disposition. If successful, it states that parties will have avoided litigation related costs and will not have jeopardized their ongoing business relationship. Dispute Resolution Associates also argues that representatives at all negotiating sessions should be authorized to enter into an agreement and asks that the Commission clarify that dispute resolution is one of the minimum requirements of the Final Rule. It also asks that the Commission require that any filed separate retail transmission tariffs must include section 12 type dispute resolution procedures. Commission Conclusion Concerning the first issue raised by Public Service Co of CO, even if the arbitrator misinterprets the requirements of the pro forma tariff, the dispute resolution procedures require such decision (as it affects terms and conditions of service) to be filed with the Commission. Section 12.2 provides: Docket Nos. RM95-8-001 -98- and RM94-7-002 The final decision of the arbitrator must also be filed with the Commission if it affects jurisdictional rates, terms and conditions of service or facilities. As to Public Service Co of CO's second concern, a utility's membership in an RTG with its own Dispute Resolution Procedures presents a fact specific situation to which a generic response is not appropriate. Whether both parties to a dispute are members of the RTG or only one of the parties is a member may have some bearing on which set of Dispute Resolution Procedures should apply. Regarding Dispute Resolution Associates concerns, a utility is free to propose an initial process using "mediated resolution with a qualified individual" prior to using the Dispute Resolution Procedures. However, we see no need to modify the tariff to introduce such a proposed requirement as the Commission is not aware of other parties similarly claiming excessive costs or the threat of "jeopardizing ongoing business relationship[s]" due to the present Dispute Resolution Procedures. Finally, any attempts to delete the Dispute Resolution Procedures from any tariff on file with the Commission would require the transmission provider to demonstrate that its proposed modifications are consistent with or superior to the pro forma tariff terms and conditions. Docket Nos. RM95-8-001 -99- and RM94-7-002 Section 13.2 Rehearing Requests CCEM asserts that the term "reserved service" should be changed to "requested service." Utilities For Improved Transition and Florida Power Corp assert that the limitations on unconditional reservations are too stringent and that the Commission should modify the third sentence of section 13.2 to provide: "If the Transmission System becomes oversubscribed, requests for longer-term service may preempt requests for shorter-term service up to a time period before the requested commencement of service that is equal to the requested term of service." Commission Conclusion We will deny CCEM's request to replace the term "reserved service" in tariff section 13.2 with "requested service." CCEM has not attempted to identify any uncertainties caused by the current wording of this section or explain any improvements that its proposed change would make. Utilities For Improved Transition and Florida Power Corp's proposal to revise the deadline for when reservations for short- term firm transmission become unconditional is contrary to the Commission's intent in adopting the conditional reservation approach for short-term firm transmission and is rejected. Specifically, for service requests greater than a single day, week or month, Utilities For Improved Transition and Florida Power Corp's proposal decreases the period of time that such Docket Nos. RM95-8-001 -100- and RM94-7-002 request is conditional; in other words, such request increases the unconditional reservation period, thus reducing the amount of longer-term transactions that the transmission provider can accommodate. Sections 13.2 and 14.2 Rehearing Requests CCEM notes that short-term firm point-to-point transmission service customers that have already reserved service have a right to match any longer-term requests for service before being preempted pursuant to section 13.2. However, CCEM states that these tariff sections do not establish a deadline for when such right must be exercised. Because the tariff established a conditional reservation period for short-term firm transmission service (during which time longer-term firm transmission requests can preempt shorter-term conditional reservations) CCEM suggests that a shorter-term firm transmission customer should be allowed to exercise its right to match longer-term service requests up until the end of the conditional reservation period. CCEM requests a similar clarification for non-firm transmission service but does not propose specific modification. Commission Conclusion While we agree with CCEM regarding the need to establish a deadline for exercising the right to match longer-term service requests for both short-term firm and non-firm transmission services, we will reject CCEM's proposed deadline for short-term firm transmission service. CCEM's proposed deadline would create Docket Nos. RM95-8-001 -101- and RM94-7-002 market inefficiency by allowing the holder of the shorter-term firm transmission service an excessive amount of time to exercise its right to match the longer-term service. We feel that such a proposal could constitute a form of hoarding that would stifle the consummation of potential transactions and should not be allowed. CCEM's proposal would work to the detriment of any and all potential customer(s) requesting longer short-term firm transmission service. By allowing the original transmission customer to delay its response, the subsequent potential customer will be disadvantaged and may be required to make last minute alternative arrangements. We believe that an especially quick response time is necessary for hourly non-firm transmission service customers to match longer-term service requests. Hourly non-firm transmission customers must exercise their right to match longer-term service requests immediately upon notification by the transmission provider of a longer-term competing request for non-firm transmission service. For non-firm transmission service other than hourly transactions and short-term firm transmission service, we believe a customer should exercise its right to match longer-term service requests as soon as practicable. The prompt exercising of such right is particularly critical where scheduling deadlines for such transactions are imminent. However, even for transactions with longer lead-times before service is to commence, we believe a response deadline of no more than 24 hours from being informed by the transmission provider of Docket Nos. RM95-8-001 -102- and RM94-7-002 a longer-term competing request for transmission service is appropriate. Accordingly, the customer will be required to respond to the transmission provider as soon as practicable after notification of a longer-term request for service, but no longer than 24 hours from being notified or earlier if required to comply with the scheduling requirements for such services in tariff section 13.8 and 14.6. Tariff sections 13.2 and 14.2 will be modified accordingly. Section 13.5 Rehearing Requests Several utilities argue that section 13.5 is too broad because it also applies to costs that are included in rates on an embedded cost basis (which they claim can be evaluated when the transmission provider makes a rate filing). 420/ They recommend that the Commission modify the last sentence of the section as follows: If redispatch costs or Network Upgrade costs are to be charged to the Transmission Customer on an incremental basis or costs relating to Direct Assignment Facilities that are to be charged to the Transmission Customer, the obligation of the customer to pay such costs shall be specified in the Service Agreement prior to the initiation of service." (Utilities For Improved Transition at 74-75). E.g., Florida Power Corp, Utilities For Improved Transition, VEPCO. Docket Nos. RM95-8-001 -103- and RM94-7-002 Commission Conclusion The Commission's intent in tariff section 13.5 was to require that any proposal to assess incremental charges to a customer must be specified in that customer's service agreement. Florida Power Corp and VEPCO correctly note that tariff section 13.5 inadvertently requires that any redispatch, network upgrade or direct assignment facilities, whether assessed on an incremental basis or included in embedded cost rates, must be specified in a customer's service agreement. To eliminate this unintended result, tariff section 13.5 is revised in relevant part as follows (new text underlined): Any redispatch, Network Upgrade or Direct Assignment Facilities costs to be charged to the Transmission Customer on an incremental basis under the Tariff will be specified in the Service Agreement prior to initiating service. Section 13.6 Rehearing Requests CCEM asserts that the term "Good Utility Practice" should be deleted. CCEM claims that the inclusion of regional practices in Good Utility Practice makes the phrase vague and unpredictable. CCEM proposes that the Commission replace this phrase with a qualifier that pertains only to reliability and safety. According to PA Coops, equal priority places inordinate and unwarranted pressure on state siting and regulatory authorities to approve transmission projects required to provide service that may primarily benefit out of state parties. NYSEG argues that Docket Nos. RM95-8-001 -104- and RM94-7-002 the Commission is not authorized to require curtailment of bundled retail service because it does not have jurisdiction over the rates, terms, and conditions of such service. It asserts that transactions subject to proportional curtailment should not include a transmitting utility's own use of its system to transmit its owned and purchased generation to native load customers as part of bundled retail service or services under rate schedules that are grandfathered. For transactions subject to proportional curtailment, NYSEG argues that allocation of curtailments will be comparable only if those multiple transactions being curtailed are of the same type of service and if each of the multiple transactions is for the same duration -- these curtailments should be made on the same basis as required for non-firm PTP service. It asks the Commission to clarify that the curtailment requirements are not applicable to existing transmission contracts. Commission Conclusion CCEM's concerns center on the inclusion of the phrase regional practices in the definition of Good Utility Practice in section 1.14 of the pro forma tariff. These concerns are answered in section 1.14 above. PA Coops' argument that long-term firm point-to-point transmission customers should be curtailed before network service customers and native load ignores the fact that the transmission provider has an obligation under the pro forma tariff to expand or upgrade its transmission system in response to requests for Docket Nos. RM95-8-001 -105- and RM94-7-002 such long-term point-to-point transmission requests. In turn, such long-term firm point-to-point transmission customers undertake an obligation to pay for any transmission facility additions necessary for the provision of service pursuant to the tariff. Comparability requires that all long-term firm transmission customer be treated on a not unduly discriminatory basis in terms of curtailment priority. Regarding NYSEG's arguments, the purpose of the curtailment provisions of the pro forma tariff is not to "requir[e] curtailment of bundled retail service" as NYSEG claims. Rather, the provision simply requires the transmission provider to curtail network and point-to-point transmission services on a basis comparable to the curtailment of the transmission provider's service to its native load. Indeed, we have repeatedly indicated that we do not have jurisdiction over bundled retail sales. NYSEG's concerns regarding curtailment provisions in existing contracts are addressed above in Section IV.G.3.a. (Pro- rata Curtailment Provisions). Section 13.7 Rehearing Requests Utilities For Improved Transition and Florida Power Corp state that section 13.7 of the pro forma tariff makes it uneconomic to engage in system sales transactions on a firm basis because it requires the transmission provider to impose a separate charge for transmission from each generating station. Docket Nos. RM95-8-001 -106- and RM94-7-002 They ask that the Commission clarify that if there is a sale from multiple generators, a reservation of transmission from each point of receipt will be required only in the amount of the expected relative contribution of each generating station to the energy that is sold. If it is not so clarified, they argue that the Commission should make one of the following modifications: (1) permit the customer to designate more than one generating station as a single point of receipt if it provides likely loadings of the units to the transmission provider; (2) provide that where the customer takes service from a group of generating stations on an economic dispatch basis, the reserved capacity is the sum of the reservations at the points of delivery (must also provide likely loadings); or (3) add a new subsection to Article 31 that provides that a network integration transmission customer may also reserve service on a contract demand basis for periods as short as one day (but do not reduce the one-year minimum term for load-based network service). CSW Operating Companies asserts that the Commission should permit sales of power from multiple points of receipt, but such multiple generating units should be considered a single point of receipt. According to CSW Operating Companies, this provides maximum flexibility, lessens the need to establish secondary points of receipt, and is consistent with FMPA v. FPL, 74 FERC  61,006 at 61,014 (1996). They ask that the Commission revise section 13.7(b) to provide: "The Transmission Customer may purchase transmission service to make sales of capacity and Docket Nos. RM95-8-001 -107- and RM94-7-002 energy from multiple generating units that are on the Transmission Provider's Transmission System. Such multiple generating units shall be considered a single Point of Receipt when the underlying sale is to be made on a system basis and not from specific generating units." (CSW Operating Companies at 10- 11). TAPS requests that the Commission clarify that a network customer may make system sales to third parties using the point- to-point provisions without designating each generating resource as a point of receipt. Moreover, it asks that if the Commission intends to depart from FMPA v. FPL, that transmission providers be held to the same burden. Commission Conclusion Several utilities request rehearing on the tariff's requirement that sales of capacity and energy from multiple generating units must be designated as multiple points of receipt under point-to-point transmission service. These parties generally claim that this tariff requirement makes system sales transactions uneconomical and is contrary to the Commission's determination in FMPA v. FPL, 74 FERC  61,006 at 61,014 (1996). As the Commission stated in the Final Rule: all tariffs need not be "cookie-cutter" copies of the Final Rule tariff. Thus, under our new procedure, ultimately a tariff may go beyond the minimum elements in the Final Rule pro forma tariff or may account for regional, local, or system-specific factors. The tariffs that go into effect 60 days after publication of this Rule in the Federal Register will be identical to the Final Rule pro forma tariff; however, public utilities then will be free to file under section 205 Docket Nos. RM95-8-001 -108- and RM94-7-002 to revise the tariffs, and customers will be free to pursue changes under section 206. [421/] Utilities that advocate modifying the pro forma tariff to accommodate system sales are free to file their specific proposals with the Commission in a section 205 filing. 422/ Such proposals are best reviewed on a case-specific basis where the type of system sales engaged in by the transmission provider or transmission customer can be identified and described in detail. In order to ensure comparability, any proposed tariff modifications submitted in order to facilitate system sales of the transmission provider must also apply for sales by transmission customers as well. Section 13.7(b) Rehearing Requests Blue Ridge argues that because units at the same geographic location can be connected to the system at different electrical locations, such as connections at different voltage levels (e.g., one unit connected at 500 kV and another unit connected at 230 kV), the Commission should replace the phrase "at the same generating plant" with "at the same electrical location." (Blue Ridge at 23-24). FERC Stats. & Regs. at 31,770 n.514; mimeo at 399 n. 514. See Commonwealth Edison Company and Commonwealth Edison Company of Indiana, Inc., 78 FERC  61,090 (January 31, 1997). Docket Nos. RM95-8-001 -109- and RM94-7-002 Commission Conclusion Blue Ridge's proposed change is unsupported. The rationale supporting the need for such change and its intended result is unclear and unexplained and appears to be unnecessary and overly restrictive. Many generating units at a single plant are connected to the transmission grid at multiple voltages. Therefore, taking Blue Ridge's proposal to its logical end, a customer could face an additional charge at a single unit for every voltage level connection. In contrast, the intent of section 13.7(b) of the pro forma tariff is to treat multiple units at a single plant as a single point of receipt to avoid charging a customer an unnecessary additional charge. Section 13.8 Rehearing Requests CCEM asks the Commission to clarify that permissible scheduling changes extend to changes in the amount of power scheduled, the generation source, and delivery and receipt points. AMP-Ohio asserts that if the transmission provider can accommodate a change, the customer should be able to change its schedule less than 20 minutes before the hour or during the hour, and during an emergency or when the customer is attempting to remain within the 1.5% deviation band. It also asks the Commission to clarify that customers should be allowed to aggregate multiple points of delivery of less than a whole megawatt to be stated in whole megawatts (as is allowed for points of receipt). Otherwise, AMP-Ohio asserts, this would Docket Nos. RM95-8-001 -110- and RM94-7-002 preclude small utilities from receiving service under a transmission provider's open access tariff. Commission Conclusion We agree with CCEM that permissible scheduling changes include the amount of power scheduled (up to the amount of capacity reservation stated in the customer's service agreement). However, a proposed modification to the generation source or to receipt and delivery points on a firm basis under the pro forma tariff is not simply a scheduling change, as maintained by CCEM, but is a new request for service, as set forth in pro forma tariff section 22.2. AMP-Ohio's request regarding scheduling changes ignores the optional language in section 13.8 of the pro forma tariff, which permits a reasonable time limitation (other than the stated twenty minute deadline) that is "generally accepted in the region and is consistently adhered to by the transmission provider." Accordingly, the pro forma tariff may be amended by the transmission provider to reflect the prevailing practice in the region. AMP-Ohio's request regarding scheduling changes to allow the customer to stay within the deviation band of 1.5 percent may not be feasible depending upon the ramping rates of the particular generating units and may allow erratic scheduling by customers that could interfere with the transmission provider's ability to provide load following service. Docket Nos. RM95-8-001 -111- and RM94-7-002 AMP-Ohio's request for clarification that customers should be allowed to aggregate multiple points of delivery of less than a whole megawatt is unnecessary. Tariff section 17.2 (viii) specifically allows customers to combine their requests for service for either points of receipt or points of delivery in order to satisfy the minimum transmission capacity requirement. Section 14.2 Rehearing Requests Tallahassee asks the Commission to clarify that a non-firm customer facing possible interruption for economic reasons will be allowed to match the duration and price of the surviving transaction and that once a non-firm transaction begins, it will not be preempted without whatever notice is sufficient and appropriate in the region, but the time period should be no shorter than 1-2 hours. Commission Conclusion The pro forma tariff does allow a customer to match a longer term reservation before being preempted. Moreover, non-firm transmission transactions, by definition, are interruptible for economic reasons (on a non-discriminatory basis) at any time. To the extent a prevailing regional practice exists regarding advance notice of interruption, the transmission provider may incorporate such a provision in its tariff. Docket Nos. RM95-8-001 -112- and RM94-7-002 Section 14.4 Rehearing Requests CCEM asks the Commission to clarify that a non-firm point- to-point service agreement is an Umbrella Agreement and a non- firm point-to-point customer should be able to schedule a transaction at different primary and secondary receipt points and schedule changes in primary points with no filing requirement. Commission Conclusion The form of service agreement for non-firm transmission service is a non-transaction specific umbrella service agreement (See Attachment B to the pro forma tariff). Therefore, the service agreement does not require a specification of receipt and delivery points for non-firm point-to-point transmission service. However, we note that changes to the receipt or delivery points for non-firm transmission service other than those points reserved by the transmission customer in its service request are not "schedule" changes as claimed by CCEM, but will require the submission of a new application for service pursuant to Tariff Section 18. Section 14.6 Rehearing Requests CCEM asks the Commission to clarify that "scheduling changes" for non-firm transmission include changes in the amounts scheduled, changes in receipt and delivery points, or changes in primary points. Docket Nos. RM95-8-001 -113- and RM94-7-002 Commission Conclusion This issue is addressed in Section 13.8 above. Sections 17, 18 and 29.2 Rehearing Requests The EPRI/NERC Working Group (formerly the "What and How Industry Working Group") identifies certain areas in the pro forma tariff "where the perceived scope of OASIS has grown beyond that which is feasible in Phase 1" of OASIS. (EPRI/NERC Working Group at 2). EPRI/NERC Working Group references various information required in the application process under the pro forma tariff that is required to be submitted via OASIS to the transmission provider. EPRI/NERC Working Group explains that a substantial amount of information required under the pro forma tariff "cannot be provided via the OASIS in Phase 1" (e.g., service agreements, requests for (A) non-firm point-to-point transmission service in the next hour, (B) multiple receipt and delivery points, (C) addition of new network loads or resources, loadflow and stability data). The EPRI/NERC Working Group also claims that tariff section 17.1 creates confusion as it first requires that "[a] request for Firm Point-To-Point Transmission Service . . . must contain a written Application . . ." to the transmission provider, but then requires "[a]ll Firm Point-To-Point Transmission Service requests should be submitted by entering the information listed below on the Transmission Provider's OASIS." (Emphasis added). The EPRI/NERC Working Group asserts that the above language confuses Docket Nos. RM95-8-001 -114- and RM94-7-002 the process of an "application for service agreement" versus the process of "a request for transmission service" by a customer who already has a service agreement. Commission Conclusion The Commission recognizes that implementation of the OASIS is being accomplished in phases. In recognition of this fact, section 17.1 of the pro forma tariff provides: Prior to implementation of the Transmission Provider's OASIS, a Completed Application may be submitted by (i) transmitting the required information to the Transmission Provider by telefax, or (ii) providing the information by telephone over the Transmission Provider's time recorded telephone line. Moreover, we clarify that if Phase 1 of OASIS implementation does not support the submission of certain information over the OASIS, such information may be submitted by telephone or telefax (facsimile), as provided in the pro forma tariff, and promptly (within one hour) posted on OASIS by the Transmission Provider. 423/ On December 27, 1996, the Commission issued an order that found that during Phase 1, a request for transmission service made after 2:00 p.m. of the day preceding the commencement of such service, will be "made on the OASIS" if it is made directly on the OASIS, or, if it is made by facsimile or telephone and promptly (within one hour) posted on the OASIS by the Transmission Provider. 77 FERC  61,335 (1996). Docket Nos. RM95-8-001 -115- and RM94-7-002 Concerning the EPRI/NERC Working Group's apparent confusion regarding service application processes, we previously explained in Section IV.G.6 that the Commission is modifying the application process for firm point-to-point transmission transaction of less than one year (short-term firm transactions). The Commission will permit an "umbrella service agreement" approach where all of a customer's short-term firm transactions can be arranged under a single non-transaction specific umbrella service agreement rather than requiring a new service agreement for each short-term firm transaction. In contrast, service agreements for firm point-to-point transmission transactions of one year or more (long-term firm transactions) are transaction specific and require a separate service agreement for each transaction. Section 17.1 Rehearing Requests CCEM states that the 60 days in advance to request service should be shortened to 6 days. For service shorter than one year, it argues that the procedures should not be left to negotiation with a monopolist. For service greater than one month but less than one year, it asserts that a request should be submitted 3 days in advance; for weekly service, schedules should be submitted by some specific hour the day before service is to commence; and for hourly or daily service, schedules should be submitted no later than 20 minutes in advance. Commission Conclusion Docket Nos. RM95-8-001 -116- and RM94-7-002 CCEM has provided no support for its proposal to shorten the lead time for requests for firm service from sixty days to six days. Sixty days in advance of the commencement of long-term (greater than one year) firm service is not an unreasonable time period. It provides transmission providers time to conduct security analyses, as well as perform system impact studies and facility studies that may be necessary. Accordingly, CCEM's request is denied. Section 17.2 Rehearing Requests CCEM argues that information concerning the location of the generating facility and the load ultimately served is not required in connection with a good faith request under the Policy Statement Regarding Good Faith Request for Transmission Services and should not be required in a Completed Application. However, if it is required, CCEM argues that it should remain confidential and not be disclosed. It further asks the Commission to clarify that a point-to-point customer can designate all receipt and delivery points in order to obtain umbrella-type service and can schedule receipt and delivery points as primary or secondary and can change primary points by filing another schedule. Commission Conclusion We will deny CCEM's proposed changes in part as unnecessary. The locations of generating facilities and loads are needed by the transmission provider to allow it to analyze whether the requested transmission service can be accommodated over the Docket Nos. RM95-8-001 -117- and RM94-7-002 existing transmission system, as well as to plan upgrades and transmission facility additions. 424/ Tariff section 17.2 already requires that "the transmission provider shall treat this [confidential] information consistent with the standards of conduct contained in Part 37 of the Commission's regulations." With respect to CCEM's request to permit umbrella-type service, we note that we have adopted an umbrella-type service agreement approach for short-term firm transmission service, as discussed in Section IV.G.6 (Umbrella Service Agreements). Section 17.3 Rehearing Requests CCEM asserts that a customer determined to be creditworthy should not have to submit a deposit for firm point-to-point transmission service. CCEM would limit this section to those customers found not to be creditworthy and asks the Commission to clarify that only the costs of system impact studies or facilities studies can be deducted from the deposit. We further note that CCEM's reference to the Commission's Policy Statement Regarding Good Faith Request for Transmission Services does not support its position. As we there stated, [a] good faith request for transmission service should also contain a specific, technical description of the requested services in sufficient detail to permit the transmitting utility to model the additional services or its transmission system. FERC Stats. & Regs.  30,975 at 30,863. Docket Nos. RM95-8-001 -118- and RM94-7-002 Commission Conclusion Section 17.3 reflects a standard requirement in many existing tariffs and other agreements on file with this Commission. CCEM provides no compelling reason to revise this tariff provision. We also deny CCEM's request regarding deductions from the deposit. We will not preclude a utility from demonstrating that it incurs costs other than system impact studies or facilities studies in processing a service application and arguing that these costs should be deducted from a deposit. Section 17.4 Rehearing Requests CCEM argues that a deficiency determination should be made in, at most, one day. Commission Conclusion CCEM provides no compelling reason to revise this tariff provision. CCEM's argument also ignores the fact that certain applications involve more complex unique transactions and associated arrangements which may require more time to review than other more standard applications. CCEM's apparent concern regarding deficient applications should be mitigated by the pro forma tariff requirement that the transmission provider must attempt to remedy minor deficiencies in the application informally with the transmission customer. Docket Nos. RM95-8-001 -119- and RM94-7-002 Sections 17.5 Rehearing Requests CCEM asserts that a transmission provider should respond to a completed application for firm transmission service within 10 minutes for hourly service, 10 minutes for daily service, 4 hours for weekly service, 1 day for monthly service, 2 days for service longer than one month but less than one year, and 5 days for service one year or longer. Commission Conclusion Section 17.5 requires the transmission provider to notify the eligible customer as soon as practicable, but no later than 30 days after receipt of a completed application if it can provide the service or if a system impact study will be required. We do not believe that further specificity in establishing deadlines for each type of service and duration of service is necessary. However, we are clarifying section 17.5 to require that all responses be made on a non-disriminatory basis. If CCEM believes the transmission provider is engaging in discriminatory behavior by delaying responses to service requests (or by responding to service requests by its wholesale merchant function more quickly than it responds to service requests by unaffiliated customers), it can file a section 206 complaint with the Commission. Docket Nos. RM95-8-001 -120- and RM94-7-002 Section 17.7 Rehearing Requests Several utilities ask the Commission to clarify that, if transmission facilities have been constructed to accommodate a request for transmission service, delays by the customer in commencing service should be prohibited or the customer should pay the full carrying charges on the facilities during the period of delay (less any revenues received). 425/ Similarly, EEI and Southern argue that if new facilities are constructed, but the customer postpones service by paying a reservation fee, fairness requires that the customer bear its cost responsibility for the new construction at the time the facilities are ready to be used. Commission Conclusion Because different factual circumstances could exist that may lead to alternative solutions to the problem, we will not adopt a generic resolution. Rather, the Commission believes it appropriate to allow each utility to propose solutions in subsequent section 205 filings with the Commission. Section 19 Rehearing Requests VA Com asks the Commission to clarify that determining the necessity of a transmission facility upgrade or addition remains a state prerogative. It asserts that native load customers may face reduced reliability, or may incur costs associated with E.g., Utilities For Improved Transition, Florida Power Corp, VEPCO. Docket Nos. RM95-8-001 -121- and RM94-7-002 premature additions, if calculations of ATC are incorrect. In addition, it asserts that generating facilities can also be used to relieve regional capacity constraints -- "For example, a current proposal by Virginia Electric and Power Company ("Virginia Power") seeks the Virginia Commission's approval of a major new transmission line. Virginia Power alleges that the line is needed since it would increase the availability of emergency off-system supplies and allow it to lower its capacity reserve requirements. If the Virginia Commission were to approve the line, it is conceivable that FERC could direct Virginia Power to use this additional interchange capability to facilitate wholesale wheeling transactions. In such an event, native load customers may be adversely affected since the utility would be forced to suffer diminished reliability or build additional generation or transmission facilities." (VA Com at 10-12). CCEM asks the Commission to require studies for short-term firm point- to-point service or requests for capacity that are posted on the OASIS. Commission Conclusion In the Final Rule, the Commission explicitly stated 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 Docket Nos. RM95-8-001 -122- and RM94-7-002 reassignment requirements, until such time as it is actually needed and used. [426/] This ability to reserve capacity to meet the reliability needs of native load would apply equally to transmission built in the future. VA Com requested clarification of the intended treatment by the Commission in the ATC calculation of a transmission line built in lieu of generation for purposes of lowering reserve requirements for native load. If it seeks to withhold capacity in response to a request for service by an eligible customer, the transmission provider will have the burden of proof to demonstrate that any reserved capacity is needed for meeting native load and network customers' load growth or for purposes of meeting a reserve requirement level that is reasonable. CCEM's request is unnecessary because system impact studies and facilities studies are required pursuant to tariff section 19 for both long-term and short-term firm point-to-point transmission service. Sections 19.2 and 32.2 Rehearing Requests Utilities For Improved Transition and VEPCO ask the Commission to modify these sections to require that a system impact study agreement specify the estimated charge instead of the maximum charge so that the transmission provider may collect all prudently incurred study costs. FERC Stats. & Regs. at 31,694; mimeo at 172. Docket Nos. RM95-8-001 -123- and RM94-7-002 Commission Conclusion Utilities For Improved Transition and VEPCO correctly note that the use of the phrase "maximum" in the language of tariff sections 19.2 and 32.2 may prevent a utility from collecting the full costs of conducting a system impact study despite acting in a prudent manner. Accordingly, the relevant portion of these sections are modified as shown below to eliminate this potential inequity (deleted text in brackets): (i) The System Impact Study Agreement will clearly specify [the maximum charge, based on] the Transmission Provider's estimate of the actual cost, and time for completion of the System Impact Study. The charge shall not exceed the actual cost of the study. Sections 19.3 and 19.4 Rehearing Requests TAPS asserts that the 15-day periods for customers to execute a service agreement after completion of a system impact study are too short and should be lengthened to 30 days or the transmission provider should be allowed to provide an extension for cause (with public notice) while the customer is pursuing an agreement in good faith. Commission Conclusion TAPS' proposed changes are not necessary because the eligible customer is provided a sufficient response time considering the situation to which the eligible customer is responding. Specifically, the 15-day period in section 19.3 refers to the situation where the transmission provider has Docket Nos. RM95-8-001 -124- and RM94-7-002 conducted a system impact study and concluded that the requested service can be provided without the need to modify its transmission system. TAPS provides no reason why the eligible customer requesting the service should not be prepared to immediately accept the offer to provide service at the transmission provider's standard rate (without the need for upgrades, the eligible customer would not be assessed incremental transmission charges). Similarly, the 15-day period in section 19.4 refers to the time in which the eligible customer has to execute a facilities study agreement in which it agrees to pay the transmission provider for the costs of conducting a facilities study. In contrast, when the facilities study is completed and the eligible customer is provided with a good faith estimate of any direct assignment facilities and/or share of any network upgrades, section 19.4 provides the eligible customer with 30 days to respond. Section 22.1(d) Rehearing Requests Utilities For Improved Transition and Florida Power Corp ask the Commission to modify this section to require that a request for modification of service on a non-firm basis be made by submitting a modification to the original application with an OASIS posting. Otherwise, they assert, this section implies that such modifications would occur without using the transmission provider's OASIS. Docket Nos. RM95-8-001 -125- and RM94-7-002 Commission Conclusion Utilities For Improved Transition and Florida Power Corp misinterpret this section of the tariff. The Commission's intention is simply to clarify that the customer's request to modify its firm transmission service to receive service over secondary receipt and delivery points on a non-firm basis would not require a separate application for non-firm transmission service. The concerns expressed with respect to posting on the OASIS are addressed in Order No. 889-A. Section 23.1 Rehearing Requests CCEM asserts that the Commission sHhould specify the filings necessary for assignment of service referenced in this section or delete the clause. In addition, CCEM asks the Commission to clarify that the identical services will be provided at no additional cost to the assignee or the reseller. Commission Conclusion The pro forma tariff is a tariff of general applicability. For administrative reasons, the listing of every conceivable situation in which an assignment or transfer of service from one entity to another may require a separate filing is not feasible. For example, if the Commission lists only a single situation that requires a separate filing and subsequently determines another situation would also require a filing, all of the pro forma tariffs on file with the Commission would need to be revised to reflect the change. Docket Nos. RM95-8-001 -126- and RM94-7-002 CCEM's request that the Commission clarify that reassigned services will be provided at no extra cost is also denied. CCEM ignores the fact that nothing in the pro forma tariff prevents the transmission provider from seeking a change in rates pursuant to a section 205 filing whether such filing relates to a general increase in rates to all transmission customers or to additional costs the transmission provider asserts it incurs due to providing service to an assignee. As always, the transmission provider bears the burden of proof of demonstrating that its proposal is just and reasonable. Section 23.2 Rehearing Requests CCEM asks the Commission whether an assignee can change primary points if there is only a partial assignment. Commission Conclusion Whether the assignment is full or partial is immaterial. If an assignee wishes to change its receipt or delivery points on a firm basis (full or partial), the request will be treated as a new request for service as required under tariff sections 22.1 and 23.1. However, if an assignee wishes to change receipt or delivery points on a non-firm (full or partial) basis, such change can be accomplished without the need for a new service agreement as provided in pro forma tariff section 22.1. Docket Nos. RM95-8-001 -127- and RM94-7-002 Sections 25 and 34 Rehearing Requests VT DPS asks the Commission to revise these sections to state that "all firm customers should share in non-firm revenues" consistent with the language of the preamble. Commission Conclusion VT DPS' request is denied. The Commission did not intend to mandate the rate methodology used to reflect any cost reductions that may be associated with the provision of non-firm transmission service. While the Commission would generally expect all firm customers to share in non-firm revenues, the use of revenue credits is not the only acceptable method of reflecting non-firm system usage. The transmission provider's method of reflecting revenues from non-firm service should be addressed on a case-by case basis. Section 29.1 Rehearing Requests TAPS contends that, to avoid improper use of operating agreements by transmission providers, the Commission should either permit network operating agreements to be filed in unexecuted form or include a network operating agreement as part of the pro forma tariff. Commission Conclusion The network operating agreement is expected to be a highly detailed agreement between the transmission provider and network customer that establishes the integration of the network customer Docket Nos. RM95-8-001 -128- and RM94-7-002 within the transmission provider's transmission system. Due to the unique characteristics of network customers' systems and the level of customer-specific information and arrangements required under a network operating agreement, it is likely that each network operating agreement will be different for each customer. Accordingly, the Commission does not believe it appropriate to mandate a particular form of network operating agreement for inclusion in the pro forma tariff. However, if a transmission provider wishes to include a generic form of network operating agreement in its pro forma tariff (to be modified as required and as mutually agreed to on a customer-specific basis), it may propose to do so in a section 205 filing or it may file an unexecuted network operating agreement in a section 205 filing. To the extent a customer believes a transmission provider is engaging in unduly discriminatory practices via the network operating agreement, the customer may file a section 206 complaint with the Commission. Section 29.4 Rehearing Requests TDU Systems asserts that this section does not identify who should determine what facilities are "necessary to reliably deliver capacity and energy. . . ." It asks the Commission to clarify that this is solely the responsibility of the transmission customer. Docket Nos. RM95-8-001 -129- and RM94-7-002 Commission Conclusion TDU Systems' argument ignores tariff section 35.1, which specifies: [t]he Network Customer shall plan, construct, operate and maintain its facilities in accordance with Good Utility Practice and in conformance with the Network Operating Agreement. (emphasis added) Accordingly, the determination of what network customer facilities are "necessary to reliably deliver capacity and energy. . ." is to be agreed upon by both the transmission provider and network customer and specified in the network operating agreement. To the extent the parties do not agree, the transmission provider will file an unexecuted network operating agreement with the Commission and we will resolve the dispute. Section 30.1 Rehearing Requests VT DPS argues that, consistent with section 30.7, section 30.1 should not require that a network resource be available on a strictly non-interruptible basis. Commission Conclusion VT DPS' request is denied. The Commission believes that a network customer should only be allowed to designate non- interruptible network resources. To allow otherwise would interfere with the planning process as well as the day-to-day operation of the transmission system to integrate resources with customer's loads (e.g., the transmission provider will be unable to plan for what generation resource will be available to meet a Docket Nos. RM95-8-001 -130- and RM94-7-002 customer's load in the event its designated resource is subject to interruption). Similarly, for operational purposes on a day- to-day basis, an interruption of a network customer's designated resource could cause a transmission constraint. 427/ Because constraints affecting reliability may lead to curtailment or redispatch of all network resources, other network customers would be affected by such interruptions on a load-ratio basis. However, to the extent a network customer wishes to use an interruptible generation source, it can still use this generation source on an as-available basis to import energy to serve its load pursuant to pro forma tariff section 28.4. Section 30.4 Rehearing Requests PA Coops ask the Commission to modify this section "to permit the Network Resources to be operated at outputs that exceed the Network Customer's designated Network Load plus losses when the Network Resource's output is being sold to a third party or the Network Resource is called upon to be operated by the Network Customer's power pool, ISO or control area operator." (PA Coops at 8-9). Similarly, Santa Clara and Redding ask the Commission to modify the last sentence to state: ". . . exceeds its designated Network Load, plus non-firm sales delivered under Part II, plus losses" so that network resources will not remain While firm resources can also go off line, the probability of this happening is less than that for interruptible resources. Docket Nos. RM95-8-001 -131- and RM94-7-002 idle when they could otherwise generate non-firm power and energy for sale at competitive prices. In addition, TDU Systems argues that the arbitrary limits on the ability of network customers to operate Network Resources prevents economic dispatch or the use of resources to meet load requirements and limits the ability to schedule the output of Network Resources between and among control areas, effectively preventing the network customer from operating an integrated system. 428/ TDU Systems asserts that the Commission should not presume that a network customer's economic dispatch will burden a transmission provider, but should require a transmission provider to demonstrate that such a burden will occur. TAPS asks the Commission to clarify this section so as to bar not the operation of network resources in excess of network load, but rather the usage of network service in connection with operation of such resources in excess of network load. TAPS adds that section 30.4 is contrary to FMPA v. FPL, 74 FERC at 61,014-15. AEC & SMEPA argues that the Commission should provide the necessary latitude for such resources to be used across multiple control areas to service the total load of transmission users. Commission Conclusion Preliminarily, TDU Systems and others' argument that a designated network resource must consist of the entirety of a generating unit is mistaken, as we explained in sections 1.22 and See also NRECA. Docket Nos. RM95-8-001 -132- and RM94-7-002 1.25 above. The Commission's intent in requiring that the output of network resources not exceed network load plus losses is to prevent designated network resources from being used to make firm sales to third parties. This is consistent with the pro forma tariff's requirement in sections 1.25 and 30.1 that: Network Resources may not include resources, or any portion thereof, that are committed for sale to non-designated third party load or otherwise cannot be called upon to meet the Network Customer's Network Load on a non- interruptible basis. Absent a requirement that network resources always be available to meet a customer's network loads, reliability of service to the network customer as well as to native load and other network customers could be affected, as we describe in detail in section 30.1 above. If a network customer desires to enter into a firm sale from its designated network resources or use such network resources for meeting reserve requirements, it must eliminate the appropriate resources or portions thereof from its designated network resources pursuant to pro forma tariff section 30. Santa Clara, Redding and others contend that this limitation improperly restricts the use of network resources for non-firm sales. It was not the Commission's intent to prohibit the network customer from engaging in non-firm sales from idle designated network resources. We find that the non-firm operation of network resources will not affect the availability of such resources on a firm basis because such non-firm uses are Docket Nos. RM95-8-001 -133- and RM94-7-002 subject to interruption. Accordingly, the Commission's concerns regarding the reliable provision of network service are satisfied. Furthermore, as noted by Pennsylvania Coops, emergencies could arise in which the transmission provider may request that a network customer alter the operation of its network resources in response to a contingency, which action could result in a violation of the limitation in section 30.4. Therefore, the Commission believes an exception to the network resources output limitation is also appropriate for such emergency situations. Accordingly, tariff section 30.4 is revised, in relevant part, consistent with the above findings, as shown below (added language is underlined): The Network Customer shall not operate its designated Network Resources located in the Network Customer's or Transmission Provider's Control Area such that the output of those facilities exceeds its designated Network Load, plus non-firm sales delivered pursuant to Part II of the Tariff, plus losses. This limitation shall not apply to changes in the operation of a Transmission Customer's Network Resources at the request of the Transmission Provider to respond to an emergency or other unforeseen condition which may impair or degrade the reliability of its Transmission System. The remaining concerns expressed by TDU Systems with respect to the economical operation of a network customer's loads and resources located in multiple control areas are addressed above in Section IV.G.1.b. (Network and Point-to-Point Customers' Uses of the System (so-called "Headroom")). Docket Nos. RM95-8-001 -134- and RM94-7-002 Section 30.6 Rehearing Requests CSW Operating Companies asks the Commission to clarify that a customer has the obligation to replace the loss of a resource that is not physically interconnected with the transmission provider's transmission system within the time that is customary in the region or be subject to curtailment and suggests language to be included as section 33.8. CSW Operating Companies indicates that it intends to include a provision addressing this issue in the form of a network operating agreement included in the individual companies' Final Rule compliance tariffs. Commission Conclusion The Commission agrees with CSW Operating Companies that the appropriate place to address detailed operational requirements such as this is the Network Operating Agreement. If disputes arise, they can be addressed on a case-by-case basis. Section 30.7 Rehearing Requests Wisconsin Municipals asks the Commission to clarify that, for purposes of comparability between network and point-to-point customers, a customer may not reserve capacity for firm point-to- point transmission service until the customer can show that it owns or has committed to purchase generation under an executed contract that it intends to use over the reserved transmission contract path. Wisconsin Municipals claims that without the requirement to demonstrate ownership or contractual rights to the Docket Nos. RM95-8-001 -135- and RM94-7-002 output of a generation resource, the point-to-point customers will have the advantage over network customers of being able to reserve transmission service over facilities with limited available transmission capacity earlier than network customers. Wisconsin Municipals also argues, in essence, that a single or a few point-to-point customers would be able to engage in hoarding of transmission capacity by reserving all available transmission capacity over certain transmission facilities. Commission Conclusion The arguments presented by Wisconsin Municipals in support of its proposal are misplaced. Wisconsin Municpals' assertion that point-to-point customers would be able to reserve transmission service over facilities with limited available transmission capacity earlier than network customers overlooks the fact that the Final Rule allows transmission providers to reserve existing transmission capacity needed for native load growth and network transmission customer load growth reasonably forecasted within the transmission provider's current planning horizon. 429/ Wisconsin Municipals' concerns regarding hoarding of transmission capacity are answered in Section IV.C.6. (Capacity Reassignment). Finally, Wisconsin Municipals' argument that comparability requires that both network and point-to-point customers be required to demonstrate ownership or contractual rights to the output of a generation resource is not persuasive. FERC Stats. & Regs. at 31,694; mimeo at 172. Docket Nos. RM95-8-001 -136- and RM94-7-002 Network and firm point-to-point transmission service are different services. Firm point-to-point transmission service is available for periods as short as one day, whereas network service is designed to accommodate a longer term of service with a minimum term of service of one year. The requirement to demonstrate ownership or contractual rights to generation for network service is necessary because the transmission provider must be able to serve the network load from any of the designated resources. In contrast, point-to-point service is a capacity reservation service between specified points of receipt and points of delivery. Accordingly, this network requirement does not need to be extended to firm point-to-point service under the guise of comparability. Section 31.2 Rehearing Requests TDU Systems asks the Commission to clarify that an application for new network load for an existing network customer need only address the additional network service needed to serve the new Network Load and does not in any way implicate the existing network service for which the network customer has already contracted. Commission Conclusion No clarification is necessary. Tariff section 31.2 explicitly states in relevant part: A designation of new Network Load must be made through a modification of service Docket Nos. RM95-8-001 -137- and RM94-7-002 pursuant to a new Application. (Emphasis added) Section 32.3 Rehearing Requests TDU Systems asserts that this section requires too short a time for customers to evaluate a system impact study. It argues that, at a minimum, customers should have 60 days to evaluate a study and, in the event of a dispute, the application should remain viable until the dispute is resolved (also argues that the time periods set forth in sections 19.1, 19.4, 32.1, 32.3 and 32.4 are too short). Commission Conclusion TDU Systems' proposed changes are not necessary as the pro forma tariff provides an eligible customer sufficient time to respond to a system impact study. Specifically, the 15-day period in section 32.3 refers to a situation where the transmission provider has conducted a system impact study and concluded that the requested service can be provided without the need to modify its transmission system. TDU Systems provides no reason why the eligible customer should not be prepared to immediately accept the offer of providing service at the transmission provider's standard rate (without the need for upgrades, the eligible customer would not be assessed incremental transmission charges). Similarly, the 15 day period in sections 19.1, 19.4, 32.1 and 32.4 refer to the time in which the eligible customer has to Docket Nos. RM95-8-001 -138- and RM94-7-002 agree to execute an agreement to pay the transmission provider for costs of conducting studies (a system impact study in sections 19.1 and 32.1 and a facilities study in sections 19.4 and 32.4). TDU Systems provides no reason why it should not be prepared to accept or reject the relatively minor costs of further studies to determine whether its requested transmission service can be accommodated by the transmission provider. In contrast, when the facilities study is completed and the eligible customer is provided with the a good faith estimate of any direct assignment facilities and/or share of any network upgrades, the eligible customer is given 30 days to respond, which is more than a sufficient time. Sections 33.2 and 34.4 Rehearing Requests TAPS asserts that the Commission cannot shunt aside the need for ongoing revenue crediting to reduce transmission charges as a rate issue, while allowing monthly redispatch costs to be collected monthly in charges under the tariff. It contends that the Commission must require revenues to be shared on an ongoing, load-ratio basis. Commission Conclusion As discussed above, redispatch of all Network Resources and the transmission provider's own resources is only to be performed to maintain the reliability of the transmission system, not for economic reasons. As a result, the frequency of redispatch charges being assessed to network customers is expected to be Docket Nos. RM95-8-001 -139- and RM94-7-002 infrequent. In addition, the Commission is according substantial flexibility to public utilities to propose appropriate pricing terms in their compliance tariff, which includes the treatment of revenue credits. As mentioned above, there are several methods that utilities can use to properly reflect a benefit from non- firm transmission service to firm transmission customers. We do not believe it appropriate to mandate a specific method, such as automatic monthly flow through of revenue credits, at this time. However, TAPS may pursue this issue when utilities file their compliance rates or subsequent 205 rate filings. Section 34.3 Rehearing Requests Several utilities assert that because the monthly transmission system load is composed in part of the contract demands of all firm point-to-point transmission customers and under the Rule the charge for firm point-to-point service may be derived by dividing the transmission cost of service by the sum of the transmission provider's 12 monthly peak firm transmission loads, the transmission provider is prevented from recovering its entire cost of service. 430/ Maine Public Service states that parties should be allowed to argue on a case-by-case basis that firm transmission revenues should be credited instead of including the demands in the E.g., Utilities For Improved Transition, Florida Power Corp, VEPCO (asserts that rates for firm point-to-point service should be developed in the same way). Docket Nos. RM95-8-001 -140- and RM94-7-002 denominator (it indicates that this issue is pending in Docket No. ER95-836). It asserts that the revenue credit method would prevent transmission providers that offered discounts from unjustly being penalized for that decision and is the only method that permits utilities to have an opportunity to recover their costs. It adds that the Commission established procedures to keep gas pipelines whole in this same situation. Commission Conclusion While the Commission established one method of calculating load ratios and allocating costs in Order No. 888, 431/ utilities are free to propose alternative pricing methodologies in a section 205 filing consistent with the Commission's Transmission Pricing Policy Statement. 432/ We note, however, such utilities will have the burden of demonstrating that these methods would not result in over-collections of their revenue requirement. Section 34.4 Rehearing Requests TDU Systems asks the Commission to clarify, as a matter of comparability, that any mechanism proposed by a transmission provider to collect charges based on opportunity costs associated with redispatch must provide for the collection of other customers' like costs and payments to those customers. FERC Stats. & Regs. at 31,738; mimeo at 304. See FERC Stats. & Regs. at 31,768-70; mimeo at 394-99. Docket Nos. RM95-8-001 -141- and RM94-7-002 Commission Conclusion This issue is addressed in Section IV.G.1.e. (Opportunity Cost Pricing). Schedules 7 and 8 Rehearing Requests TAPS asks the Commission to clarify that these schedules do not approve "heightened" charges for short-term services. Commission Conclusion The Commission did not specify transmission rates for any tariff services in Order No. 888. The rates for long-term firm transmission, short-term firm transmission and non-firm transmission services are to be proposed by the transmission provider, as listed on Tariff schedules 7 and 8, and filed with the Commission. TAPS' argument regarding "heightened" charges for these services is therefore premature. TAPS is free to raise this concern at such time as utilities file their proposed transmission rates. Attachment G Rehearing Requests Santa Clara and Redding ask the Commission to modify Attachment G so that, where interconnection/operational standards are in place and working effectively, additional standards are not imposed simply as a result of switching to the pro forma tariff from its current interconnection service. Docket Nos. RM95-8-001 -142- and RM94-7-002 Commission Conclusion The pro forma tariff does not specifically require that the network operating agreement between the transmission provider and network customer must be a new agreement. However, the network operating agreement is expected to be a highly detailed agreement between the transmission provider and network customer establishing the integration of the network customer within the transmission provider's transmission system. Existing agreements between the customer and transmission provider may not provide all of the information required or make all of the technical arrangements required under the pro forma tariff (e.g., redispatch and ancillary services information and arrangements.) Nevertheless, to the extent the transmission customer is currently receiving network integration transmission service or similar service and its present interconnection agreement fully comports with the requirements of the terms and conditions of the tariff including the informational requirements specified in tariff sections 33 and 35, then the present interconnection/operations agreement can be substituted for a network operating agreement or modified appropriately. 9. Miscellaneous Tariff Administrative Changes Due to administrative oversight, certain tariff sections require minor corrections or modifications. Because of the administrative nature of these changes, we believe that no further discussion is needed. Docket Nos. RM95-8-001 -143- and RM94-7-002 Section 12.1 Internal Dispute Resolution Procedures - Changes "Transmission Service" to "transmission service" Section 13.6 Curtailment of Firm Transmission Service - Changes the description regarding curtailment of multiple transactions to: the Transmission Provider will curtail service to Network Customers and Transmission Customers taking Firm Point-To- Point Transmission Service on a basis comparable to the curtailment of service to the Transmission Provider's Native Load Customers. 10. Pro Forma Tariff Compliance Filings Absent a waiver, all public utilities must submit, no later than [insert date 120 days after publication of this order in the Federal Register], a compliance filing that reflects the tariff changes set forth in this order on rehearing. 433/ A conforming pro forma tariff, containing all the revisions and clarifications contained in this order on rehearing, is attached as Appendix B. In addition, an electronic version of the conforming pro forma tariff will be made available on the Commission's electronic bulletin board service (Commission Issuance Posting System (CIPS)) in redline/strikeout form in WordPerfect 5.1 format. To the extent a public utility has been granted a waiver of the Order No. 888 tariff filing requirements (or a non- public utility for reciprocity purposes), it need not submit a request for a separate waiver of the requirements of this order on rehearing. Docket Nos. RM95-8-001 -144- and RM94-7-002 H. Implementation In the Final Rule, the Commission set forth the details of the implementation procedures and included special implementation requirements for coordination arrangements (power pools, public utility holding companies, and bilateral coordination arrangements). 434/ The Revised Procedures The Commission adopted slightly different implementation procedures for Group 1 public utilities (tendered for filing open access tariffs before the date of issuance of the Rule) and for Group 2 public utilities (did not tender for filing open access tariffs before the date of issuance of the Rule). 1. Group 1 Public Utilities In the Final Rule, the Commission required Group 1 public utilities, within 60 days following publication of the Final Rule in the Federal Register, to make section 206 compliance filings that contain the non-rate terms and conditions set forth in the Final Rule pro forma tariff and identify any terms and conditions that reflect regional practices, as discussed below. 435/ As to rates, the Commission noted that a transmission tariff rate is already in effect for all Group 1 public utilities, except for the few with recently-tendered applications that have not yet been accepted for filing. FERC Stats. & Regs. at 31,768-70; mimeo at 393-400. FERC Stats. & Regs. at 31,768-69; mimeo at 394-96. Docket Nos. RM95-8-001 -145- and RM94-7-002 The Commission noted, however, that if a Group 1 public utility determined that certain rate changes are necessitated by the revised non-rate terms and conditions, it may file a new rate proposal under FPA section 205. The Commission indicated that such filings must be "conforming" 436/ under the Transmission Pricing Policy Statement and must be made no later than 60 days after publication of the Final Rule in the Federal Register and intervenors may raise any concerns with the filings within 15 days after such filings. 437/ The Commission imposed a blanket suspension for any filings by Group 1 public utilities proposing rate changes necessitated by the new non-rate terms and conditions. The Commission further indicated that these rates will go into effect, subject to refund, 60 days after publication of this Rule in the Federal Register (the same day on which the non-rate terms and conditions of the Final Rule pro forma tariff go into effect). As described in the Transmission Pricing Policy Statement, a "conforming" proposal is one that meets the traditional revenue requirement and reflects comparability. FERC Stats. & Regs.  31,005 at 31,141. Given the brief comment period on the compliance filings, the Commission required public utilities to serve copies of their compliance filings (via overnight delivery) on: all participants in their current open access rate proceedings (if applicable); all customers that have taken wholesale transmission service from the utility after the date of issuance of the Open Access NOPR; and the state agencies that regulate public utilities in the states of those participants and customers. By order issued July 2, 199, the Commission extended the comment period from 15 days to 30 days. Docket Nos. RM95-8-001 -146- and RM94-7-002 2. Group 2 Public Utilities In the Final Rule, the Commission indicated that Group 2 public utilities will be treated the same as Group 1 public utilities with regard to non-rate terms and conditions, but will be treated slightly differently from Group 1 as to rates, since Group 2 utilities have not filed any proposed rates. 438/ The Commission required these utilities to either: (i) within 60 days following publication of the Final Rule in the Federal Register, make section 206 compliance filings that contain the non-rate terms and conditions set forth in the Final Rule pro forma tariff and identify any terms and conditions that reflect regional practices, as discussed below; and (ii) within 60 days following publication of the Final Rule in the Federal Register, make section 205 filings to propose rates for the services provided for in the tariff, including ancillary services; or (iii) make a "good faith" request for waiver. The Commission added that the rates must meet the standards for conforming proposals in the Commission's Transmission Pricing Policy Statement and comply with the guidance concerning ancillary services set forth in this order. The Commission explained that intervenors may raise any concerns with these filings within 15 days after the filing. 439/ FERC Stats. & Regs. at 31,769; mimeo at 396-97. The Commission held that Group 2 public utilities must serve a copy of their filings (via overnight delivery) on all customers that have taken wholesale transmission service from them since March 29, 1995 (the date of issuance of the Open Docket Nos. RM95-8-001 -147- and RM94-7-002 The Commission imposed a blanket suspension for all such rate filings and indicated that they will go into effect, subject to refund, 60 days after the publication of this Rule in the Federal Register (the same day on which the terms and conditions of the compliance tariffs go into effect). 3. Clarification Regarding Terms and Conditions Reflecting Regional Practices In the Final Rule, the Commission explained that it had built a degree of flexibility into the tariffs to accommodate regional and other differences. 440/ It explained that certain non-rate Final Rule pro forma tariff provisions specifically allow utilities either to follow the terms of the provision or to use alternatives that are reasonable, generally accepted in the region, and consistently adhered to by the transmission provider (e.g., time deadlines for scheduling changes, time deadlines for determining available capacity). In addition, it explained that other tariff provisions require utilities to follow Good Utility Practice (section 1.14 of the Final Rule pro forma tariff). Access NOPR) and on the state agencies that regulate public utilities in the states where those customers are located. By order issued July 2, 1996, the Commission extended the comment period from 15 days to 30 days. FERC Stats. & Regs. at 31,769-70; mimeo at 397-98. Docket Nos. RM95-8-001 -148- and RM94-7-002 4. Future Filings In the Final Rule, the Commission indicated that once the compliance tariff and conforming rates go into effect, which would be 60 days after publication of the Rule in the Federal Register, a public utility (either Group 1 or Group 2) may file pursuant to section 205 a tariff with terms and conditions that differ from those set forth in this Rule, provided that, among other things, it demonstrates that such terms and conditions are consistent with, or superior to, those in the compliance tariff. 441/ However, the Commission emphasized that the public utility may not seek to litigate fundamental terms and conditions set forth in the Final Rule. In addition, the Commission explained that the public utility may file whatever rates it believes are appropriate, consistent with the Transmission Pricing Policy Statement. 5. Waiver In the Final Rule, the Commission found that it is reasonable to permit certain public utilities for good cause shown to file, within 60 days after the Rule is published in the Federal Register, requests for waiver from some or all of the requirements of this Rule. 442/ The Commission explained that the filing of a request in good faith for a waiver from the requirement to file an open access tariff will eliminate the FERC Stats. & Regs. at 31,770; mimeo at 398-99. FERC Stats. & Regs. at 31,770; mimeo at 399-400. Docket Nos. RM95-8-001 -149- and RM94-7-002 requirement that such public utility make a compliance filing unless thereafter ordered by the Commission to do so. The Commission emphasized, however, that it will not exempt such public utility from providing, upon request, transmission services consistent with the requirements of the Final Rule. Rehearing Requests Wisconsin Municipals asserts that the Commission should "require utilities (if requested by their customers) to honor the settlements to which they have agreed and to file the pro forma tariff, modified to incorporate settlement provisions that exceed the minimum provisions of the pro forma tariff, as their implementational filing." Alternatively, it asks that the Commission "require parties with settlements to make a Section 205 filing one day following their implementation filing, change any rates, terms and conditions in the pro forma tariff as necessary to incorporate any superior provisions from their settlement tariffs into the pro forma tariff, and seek any waivers necessary to make the settlement tariff effective immediately." (Wisconsin Municipals at 7-10). Blue Ridge requests rehearing of the "unbalanced tariff implementation process that rolls over the due process rights of transmission customers." It asserts that utilities should not have the right to file a "'Good Utility Practices,' blank check variance for regional practices in the compliance docket." (Blue Ridge at 33-35). Blue Ridge further requests that Group 1 utilities file compliance tariffs in the same docket as their Docket Nos. RM95-8-001 -150- and RM94-7-002 pending open access dockets and asks that subsequent changes be in a separate docket as a new general rate case. Blue Ridge also states that the Commission should explicitly mention that customers have the right to file section 206 requests to change the tariffs. Indianapolis P&L argues that the pricing requirements are unjust, unreasonable, unlawful, confiscatory and an abuse of discretion as to Indianapolis P&L. It asserts that its rates are not based on embedded, original cost, but, as a matter of Indiana law, its utility property is valued at the "fair value," which exceeds the embedded original cost of such property. It declares that it is impossible for Indianapolis P&L to comply with both the comparability requirement and the requirement that transmission rates be based on original cost. It states that the requirement to provide transmission service and generation-based ancillary services at rates based on original cost is not comparable to Indianapolis P&L's own use of its assets. Accordingly, it argues that the Commission should allow Indianapolis P&L to set its initial open access rates on a fair value, long-run marginal cost basis. Alternatively, it states that the Commission could grant Indianapolis P&L a waiver from the requirements of the Open Access Rule. Indianapolis P&L further argues that the imposition of an obligation to enlarge generation to provide ancillary services is beyond the Commission's statutory authority. It explains that Indianapolis P&L is an incidental transmission owner and a Docket Nos. RM95-8-001 -151- and RM94-7-002 relatively small public utility and asks that the Commission grant it waiver from the requirements of open access and OASIS. In deciding whether to grant a waiver, it asserts that the Commission should also consider system size and configuration, the amount of wholesale revenues or MWH sales, or the availability of competing transmission paths. Union Electric argues that the final rules violate procedural due process and that the implementation schedule is unrealistically ambitious. It argues that where the final rules call for changes from the NOPRs that could not be reasonably anticipated, they amount to deprivation of due process and rights to fairness in the administrative process. Indeed, it points out, the Commission itself has not even completed its promulgation of the OASIS Final Rule. Union Electric is concerned that it has not had an adequate time to comply with and comment on the rules. Commission Conclusion Wisconsin Municipals has misinterpreted the Commission's findings in Order No. 888, and thus its concerns are without merit. While it is true that Order No. 888 requires all public utilities to make compliance filings containing the non-price terms and conditions set forth in the Final Rule pro forma tariff, 443/ Order No. 888 also states that "we are not abrogating existing requirements and transmission contracts FERC Stats. & Regs. at 31,768-69; mimeo at 394-96. Docket Nos. RM95-8-001 -152- and RM94-7-002 generically. . . . " 444/ In short, the Commission is not requiring (or even generically allowing) the abrogation of existing transmission contracts, but is only requiring that jurisdictional transmission providers must also offer transmission service under the Final Rule pro forma tariff in addition to whatever commitments the provider will continue to have under its existing contracts. 445/ As to Wisconsin Municipals' assertions that prior individual settlement provisions may exceed the minimum provisions of the pro forma tariff, the Commission believes that such arguments should be addressed on a case-by-case basis. 446/ Two additional points are pertinent. First, we note that although we are not generically abrogating existing transmission contracts, utilities retain whatever existing rights they had to propose unilateral changes under section 205 of the FPA if they want to convert a customer to service under the tariff, and customers retain their section 206 right to seek reformation of existing transmission contracts if they are unjust, unreasonable, unduly discriminatory or preferential. Second, where a utility has treated similarly-situated customers differently -- serving one under a more favorable bilateral contract and another under a FERC Stats. & Regs. at 31,665; mimeo at 87-88. See also discussion of prior settlements in Section IV.D.1.c.(2) (Energy Imbalance Bandwidth). See IES Utilities, Inc., et al., 78 FERC  61,023 (1997). Docket Nos. RM95-8-001 -153- and RM94-7-002 less favorable tariff provision -- traditional undue discrimination remedies may be available. We deny Blue Ridge's rehearing requests because the Commission does not intend to assume the regulatory responsibility of identifying in the first instance all of the regional practices around the country that could (and should) properly be reflected in the compliance tariffs. Transmission customers opposed to deviations related to regional practices not only had the opportunity to protest the compliance filings when they were tendered, 447/ but these customers also have the right to file section 206 requests to change these tariffs at any time. In addition, Blue Ridge's request that customers be given 45 days to respond to compliance filings instead of 15 days is moot. In an order issued July 2, 1996, 448/ we took three actions to address this concern: (1) we gave entities 30 days, instead of 15 days, to respond to Order No. 888 compliance filings; (2) we agreed to post an electronic version of all Order No. 888 compliance filings on the Commission's Electronic Bulletin Board; and (3) we required all public utilities making a compliance filing to also serve a copy of their filing on electronic diskette to any eligible customer or state regulatory agency We do note that most of these concerns have been addressed in our orders dealing with the compliance filings on non- rate terms and conditions. See, e.g., Atlantic City Electric Company, et al., 77 FERC  61,144 (1996); Allegheny Power System, Inc., et al., 77 FERC  61,266 (1996). 76 FERC  61,009 at 61,026-27 (1996) (July 2 Order). Docket Nos. RM95-8-001 -154- and RM94-7-002 requesting a copy. We believe that these actions not only provided all interested parties with access to the compliance filings more quickly, but also provided these parties sufficient time to analyze the information once they received it. 449/ Moreover, the time periods provided for making and responding to Order No. 888 compliance filings have expired. With regard to Blue Ridge's first clarification request, we provide the following guidance. Utilities that had pending open access filings at the time that the Final Rule was implemented had the non-price terms and conditions of those pending tariffs superseded by their Order No. 888 compliance filings. Any customer concerns about the non-rate tariff terms and conditions in the compliance filing should be raised in the compliance docket, and any future customer concerns should be raised in a separate, future section 206 complaint filed by the customer. Furthermore, we reject Indianapolis P&L's rate issue because, if this utility believes that it operates under special circumstances that require it to use "non-conforming" pricing methods, it is free to file such a proposal under section 205. The merits of Indianapolis P&L's arguments are more appropriately addressed in such a section 205 proceeding. The Commission will not alter its generic policy (which is the subject of this rulemaking) merely to address the particular needs of one party. We also note that utilities were required in Order No. 888 to explicitly identify any regional practices in their compliance filings. Docket Nos. RM95-8-001 -155- and RM94-7-002 In addition, with regard to both of Indianapolis P&L's concerns, we note that pursuant to the Commission's July 2 Order, the Commission indicated that it would not address waiver requests in a generic proceeding and that parties would have to file such requests separately for separate docketing. We further note that Indianapolis P&L filed a separate waiver request on July 9, 1996, which was docketed as OA96-81. 450/ We also reject Union Electric's argument that the final rules violate procedural due process. Union Electric has had every opportunity to raise arguments with regard to every step in the Commission's derivation and implementation of the final rules. Moreover, with regard to Union Electric's claim that it was given an inadequate amount of time to comprehend and implement the final rules, we note that virtually every public utility, including Union Electric, complied with the Open Access Rule on a timely basis, and there have been very few complaints that the rules are hard to comprehend. I. Federal and State Jurisdiction: Transmission/Local Distribution In the Final Rule, the Commission explained that after reviewing the extensive analysis of the FPA, legislative history, and case law contained in both the initial Stranded Cost NOPR and By order issued September 11, 1996, the Commission denied Indianapolis P&L's requested waiver of all the requirements of Order No. 888. On October 8, 1996, Indianapolis P&L sought rehearing of that order and a stay of the requirements of Order No. 888. These pleadings are now pending before the Commission. Docket Nos. RM95-8-001 -156- and RM94-7-002 in the Open Access NOPR, and the comments received on that analysis, it reaffirmed its assertion of jurisdiction over the transmission component of an unbundled interstate retail wheeling transaction. 451/ The Commission also reaffirmed and clarified its determinations regarding the tests to be used to determine what constitute Commission-jurisdictional transmission facilities and what constitute state-jurisdictional local distribution facilities in situations involving unbundled wholesale wheeling and unbundled retail wheeling. The Commission also explained that where states unbundle retail sales, it will give deference to their determinations as to which facilities are transmission and which are local distribution, provided that the states, in making such determinations, apply the seven criteria discussed in the NOPR and reaffirmed by the Commission. In addition, the Commission clarified that there is an element of local distribution service in any unbundled retail transaction, and further clarified other aspects of its jurisdictional ruling to preserve state jurisdiction over matters that are of local concern and will remain subject to state jurisdiction if retail unbundling occurs. The Commission reaffirmed its legal determination that if unbundled retail transmission in interstate commerce occurs voluntarily by a public utility or as a result of a state retail access program, this Commission has exclusive jurisdiction over FERC Stats. & Regs. at 31,780-85; mimeo at 427-42. Docket Nos. RM95-8-001 -157- and RM94-7-002 the rates, terms, and conditions of such transmission. The Commission found compelling the fact that section 201 of the FPA, on its face, gives the Commission jurisdiction over transmission in interstate commerce (by public utilities) without qualification. The Commission further explained that when a retail transaction is broken into two or more products that are sold separately, the jurisdictional lines change. In this situation, the Commission emphasized that the state clearly retains jurisdiction over the sale of the power, but the unbundled transmission service involves only the provision of "transmission in interstate commerce" which, under the FPA, is exclusively within the jurisdiction of the Commission. The Commission recognized that in asserting jurisdiction over unbundled retail transmission in interstate commerce by public utilities, it was in no way asserting jurisdiction to order retail transmission directly to an ultimate consumer. It explained that its assertion of jurisdiction is that if unbundled retail transmission in interstate commerce by a public utility occurs voluntarily or as a result of a state retail wheeling program, the Commission has exclusive jurisdiction over the rates, terms, and conditions of such transmission and public utilities offering such transmission must comply with the FPA by filing proposed rate schedules under section 205. The Commission further clarified that nothing in its jurisdictional determination changes historical state franchise Docket Nos. RM95-8-001 -158- and RM94-7-002 areas or interferes with state laws governing retail marketing areas of electric utilities. It explained that while its jurisdiction cannot affect whether and to whom a retail electric service territory (marketing area) is to be granted by the state, and whether such grant is exclusive or non-exclusive, neither can state jurisdiction affect this Commission's exclusive jurisdiction over transmission in interstate commerce by public utilities. The Commission also adopted a new section 35.27(b) as follows: Nothing in this part (i) shall be construed as preempting or affecting any jurisdiction a state commission or other state authority may have under applicable state and federal law, or (ii) limits the authority of a state commission in accordance with state and federal law to establish (a) competitive procedures for the acquisition of electric energy, including demand-side management, purchased at wholesale, or (b) non- discriminatory fees for the distribution of such electric energy to retail consumers for purposes established in accordance with state law. With respect to the Commission's adoption of the Open Access NOPR's functional/technical tests for determining what facilities are Commission-jurisdictional facilities used for transmission in interstate commerce and what facilities are state-jurisdictional local distribution facilities, the Commission concluded that it could not divine a bright line for unbundled retail transmission by the public utility that previously provided bundled retail service to the end user. The Commission added that the limited Docket Nos. RM95-8-001 -159- and RM94-7-002 case law, including Connecticut Light & Power Company v. FPC (CL&P) and Federal Power Commission v. Southern California Edison Company (the Colton case), 452/ supports a case-by-case determination. 453/ Accordingly, the Commission stated that its technical test, with its seven indicators, will permit reasoned factual determinations in individual cases. The Commission made two clarifications regarding local distribution in the context of retail wheeling. First, it explained that even if its technical test for local distribution facilities were to identify no local distribution facilities for a specific transaction, states have authority over the service of delivering electric energy to end users. Second, the Commission explained that through their jurisdiction over retail delivery services, states have authority not only to assess retail stranded costs but also to assess charges for so-called stranded benefits, such as low-income assistance and demand-side management. Thus, under this interpretation of state/federal jurisdiction, the Commission explained, customers have no incentive to structure a purchase so as to avoid using 324 U.S. 515 (1945) (CL&P); 376 U.S. 205 (1964) (Colton). The Commission included a detailed legal analysis in Appendix G to Order No. 888. The Commission explained that it was particularly persuaded by the Supreme Court's statement that whether facilities are used in local distribution is a question of fact to be decided by the Commission as an original matter. See CL&P, 324 U.S. at 534-35). Docket Nos. RM95-8-001 -160- and RM94-7-002 identifiable local distribution facilities in order to bypass state jurisdiction and thus avoid being assessed charges for stranded costs and benefits. The Commission further determined that it is appropriate to provide deference to state commission recommendations regarding certain transmission/local distribution matters that arise when retail wheeling occurs. In instances of unbundled retail wheeling that occurs as a result of a state retail access program, the Commission indicated that it will defer to recommendations by state regulatory authorities concerning where to draw the jurisdictional line under the Commission's technical test for local distribution facilities, and how to allocate costs for such facilities to be included in rates, provided that such recommendations are consistent with the essential elements of the Final Rule. 454/ Moreover, the Commission indicated that it will consider jurisdictional recommendations by states that take into account other technical factors that the state believes are appropriate in light of historical uses of particular facilities. As a means of facilitating jurisdictional line-drawing, the Commission stated that it will entertain proposals by public utilities, filed under section 205 of the FPA, containing In order to give such deference, the Commission noted its expectation that state regulators will specifically evaluate the seven indicators and any other relevant facts and make recommendations consistent with the essential elements of the Rule. Docket Nos. RM95-8-001 -161- and RM94-7-002 classifications and/or cost allocations for transmission and local distribution facilities. However, the Commission explained that, as a prerequisite to filing transmission/local distribution facility classifications and/or cost allocations with the Commission, utilities must consult with their state regulatory authorities. If the utility's classifications and/or cost allocations are supported by the state regulatory authorities and are consistent with the principles established in the Final Rule, the Commission indicated that it will defer to such classifications and/or cost allocations. Furthermore, the Commission stated that deference to state commissions with regard to rates, terms, and conditions may be appropriate in some circumstances. The Commission explained that when unbundled retail wheeling in interstate commerce occurs, the transaction has two components for jurisdictional purposes -- a transmission component and a local distribution component. It again emphasized that the Commission has jurisdiction over facilities used for the transmission component of the transaction, and the state has jurisdiction over facilities used for the local distribution component. Thus, the Commission stated, the rates, terms and conditions of unbundled retail transmission by a public utility must be filed at the Commission. However, the Commission added, if the unbundled retail wheeling occurs as part of a state retail access program, it may be Docket Nos. RM95-8-001 -162- and RM94-7-002 appropriate to have a separate retail transmission tariff 455/ to accommodate the design and special needs of such programs. In such situations, the Commission indicated that it will defer to state requests for variations from the FERC wholesale tariff to meet these local concerns, so long as the separate retail tariff is consistent with the Commission's open access policies and comparability principles reflected in the tariff prescribed by the Final Rule. In addition, the Commission indicated that the rates must be consistent with its Transmission Pricing Policy Statement, and the guidance set forth in Order No. 888 concerning ancillary services. 456/ The Commission also expressed concern, just as it did with buy-sell arrangements in the gas industry, that buy-sell arrangements can be used by parties to obfuscate the true transactions taking place and thereby allow parties to circumvent Commission regulation of transmission in interstate commerce. Thus, the Commission reaffirmed its conclusion that it has jurisdiction over the interstate transmission component of transactions in which an end user arranges for the purchase of generation from a third-party. Moreover, the Commission The Commission noted that such a tariff could be different from the tariff that applies to wholesale customers, but that such tariff would still be filed with the Commission under FPA section 205. In applying the principles of the Final Rule to retail transmission tariffs, the Commission emphasized that it clearly cannot order retail wheeling directly to an ultimate consumer. (citing FPA section 212(h)). Docket Nos. RM95-8-001 -163- and RM94-7-002 indicated that it will address these transactions on a case-by- case basis. Rehearing Requests Oppose Commission Assertion of Jurisdiction Over Unbundled Retail Transmission Several state commissions indicate that, recognizing that the case law is not dispositive concerning the question of unbundled retail transmission services (either because the cases do not involve the transmission of power to retail customers or "fence off" local distribution from federal regulation), at least one court (Wisconsin-Michigan Power Company v. FPC, 197 F.2d 472 (7th Cir. 1952), cert. denied, 345 U.S. 934 (1953)) explicitly applied the wholesale/retail distinction to distinguish transmission and local distribution services. 457/ Thus, they argue, the Commission should apply the wholesale versus retail analysis to the question of unbundled retail transmission. IL Com asserts that retail transmission by a public utility directly to an end user has always (even before the FPA was enacted) been subject to regulation by the states. It contends that no change in law has occurred which justifies the Commission's claim of expanded jurisdiction. Moreover, it disagrees with the Commission's conclusion that the unbundled delivery by the previous public utility generation supplier directly to an end user is in interstate commerce. It argues that the FPA was never intended to disturb the jurisdiction of state regulators that E.g., NARUC, WI Com, WY Com. Docket Nos. RM95-8-001 -164- and RM94-7-002 existed prior to its passage and that retail transmission of electric energy by a public utility to an end user was under state jurisdiction before the Attleboro decision and has remained under state jurisdiction in the over sixty years following Attleboro. Even after unbundling, according to IL Com, transmission to a retail customer still involves a retail sale of transmission. NARUC and VA Com assert that the legislative history provides little support for the Commission's conclusion that the act of unbundling generation from delivery serves to shift jurisdiction from a state commission to the Commission. If anything, they contend, the jurisdictional structure of the FPA is predicated on the distinction between retail and wholesale transactions, not bundled and unbundled services. They assert that the Commission should conclude that the rates, terms and conditions of service for delivery of power by a utility to an end-use customer are subject to the jurisdiction of the state commission regulating the utility, regardless of the identity of the party generating or reselling the power or the facilities used to transport the power. NARUC asserts that the Commission did not address a point raised in NARUC's reply comments as to how the removal of generation serves to unbundle the retail delivery function into separate transmission and distribution services. It maintains that the Commission simply assumes that a resulting transmission Docket Nos. RM95-8-001 -165- and RM94-7-002 transaction is created when power is sold to a retail consumer by someone other than the utility delivering the power. 458/ MI & NH Coms ask the Commission to vacate those portions of the Rule that find that the Commission has jurisdiction over the transmission component of an unbundled retail sale in a local retail wheeling transaction. They assert that the Commission should confine its activity to wholesale transactions or those interstate transactions that do not implicate matters of local concern. They argue that the dual federal/state regulatory scheme establishes that Congress' intent is that state regulation of retail wheeling is not preempted by federal law as established in FPA section 201. They oppose unnecessary federal intrusion into local matters under a one-size-fits-all approach and assert that the retail wheeling initiatives in New Hampshire and Michigan are tailored to the unique utility environment in each state. Central Illinois Light argues that unbundling of retail electric service does not change the states' longstanding jurisdiction over retail electric service and local distribution, even when that service involves the use of transmission in interstate commerce. It asserts that 201(b)(1) ("transmission of See also IA Com (use of a utility's transmission system to serve its own retail customers is a bundled part of the retail sale transaction, which supports a simpler jurisdictional test holding that a movement of power by the last utility in any chain of delivery to a retail customer is a distribution transaction). Docket Nos. RM95-8-001 -166- and RM94-7-002 electric energy in interstate commerce") cannot be read in a vacuum. MN DPS & MN Com and OH Com assert that the Commission should have no role in the regulation of retail services, be they bundled or unbundled. They argue that, in refusing to grant the Commission authority over retail wheeling, Congress left jurisdiction over retail electric service to the states. They conclude that the Final Rule contains insufficient legal and/or policy justification for the Commission's assertion of jurisdiction over unbundled retail transmission services. MN DPS & MN Com assert: "FERC bases its usurpation of state authority over retail transmission rates on its claim that balkanization would occur without the assertion of FERC authority. Therefore, the parties are entitled to rehearing so that this essential issue can be further analyzed." (MN DPS & MN Com at 1-3). FL Com argues that the Commission has not justified why the act of unbundling prices expands the Commission's jurisdiction into retail marketing areas. It argues that Section 212(g) of the FPA has the effect of prohibiting the Commission from usurping existing state jurisdiction over retail transmission service, whether bundled or unbundled. According to FL Com, FERC's jurisdiction over transmission terminates at the territorial boundary of each electric utility in Florida. It supports wheeling in jurisdiction for state commissions and Docket Nos. RM95-8-001 -167- and RM94-7-002 wheeling out and wheeling through jurisdiction for the Commission. IN Com opposes federalization of retail wheeling transactions within a state's boundaries as contrary to the FPA's legislative history and case law. NJ BPU asserts that by claiming jurisdiction over unbundled retail transmission, the Commission is creating a disincentive for states to implement retail access because, by ordering retail access, the states may be relinquishing their jurisdiction over unbundled retail transmission terms and conditions -- jurisdiction that they would maintain under a bundled scenario. 459/ PA Com argues that the Commission does not have the authority to order retail wheeling and that the jurisdictional formula is challengeable on engineering and legal grounds. It concludes that the Commission does not have jurisdiction over unbundled interstate retail transmission service. PA Com notes that the 1996 House and Senate hearings have raised the question whether the Commission has the statutory authority to restructure the electric industry. PA Com questions the Commission's definition of the "traditional tasks of state and federal regulators" on the basis of section 201(b) of the FPA, the Supremacy Clause, and the Tenth Amendment of the U.S. Constitution. See also PA Com. Docket Nos. RM95-8-001 -168- and RM94-7-002 Support Broader Assertion of Jurisdiction by the Commission Over Retail Wheeling NY Utilities declare that the Commission has jurisdiction over retail wheeling from the source to the load, but does not have jurisdiction over transmission in bundled retail service. They assert that the Commission's reliance on state jurisdictional local distribution as a predicate to abstain from allowing retail wheeling stranded cost recovery is without foundation. They further assert that a unique element that sets local distribution apart from transmission is not the size of the facility or the length of travel, but that transportation is bundled with a retail sale. According to NY Utilities, the plain meaning of the FPA shows that local distribution is bundled retail service. They claim that the legislative history, to the extent necessary, and court cases support FERC jurisdiction over all aspects of retail wheeling, but makes clear that the Commission cannot regulate bundled retail service. They add that the NGA also demonstrates that local distribution means bundled retail service. Commission Conclusion In concluding that this Commission has exclusive jurisdiction over the rates, terms and conditions of unbundled retail transmission by public utilities in interstate commerce, the Commission in Order No. 888 thoroughly examined the statutory language of the FPA and its legislative history, and relevant FPA and NGA case law. While the state commissions on rehearing would Docket Nos. RM95-8-001 -169- and RM94-7-002 like us to draw a bright line that gives them, to varying degrees, jurisdiction over retail interstate transmission by public utilities, no party on rehearing has raised any legislative history or case law that was not previously considered and that would support the proposition that states have jurisdiction over any unbundled transmission in interstate commerce. As explained below, we reaffirm our jurisdictional interpretation on rehearing and believe that it is supported by the recent decision in United Distribution Companies v. FERC. 460/ Many of the rehearing arguments focus on the fact that states historically (even prior to the FPA) regulated retail transmission insofar as it was a component of bundled electric service to an end user, and they argue that by asserting jurisdiction over unbundled retail transmission, the Commission is somehow "taking away" jurisdiction the states previously had. The flaw in these arguments is their inherent assumption that jurisdiction over transmission service turns upon the question of whether the transmission service is being provided for "wholesale" or "retail" power sales. That is not the case. The question of jurisdiction rather turns upon the extent of the Commission's exclusive jurisdiction over transmission in interstate commerce under the FPA. The fact that states historically regulated most retail transmission service as a part 88 F.3d 1105, 1152-53 (1996) (United Distribution Companies). Docket Nos. RM95-8-001 -170- and RM94-7-002 of a bundled retail power sale is not the result of a legal requirement; it is the practical result of the way electricity has historically been bought and sold. However, the shape of power sales transactions is rapidly changing. Rather than claiming "new" jurisdiction, the Commission is applying the same statutory framework to a business environment in which, as discussed below, retail sales and transmission service are provided in separate transactions. In the past, retails ales occurred almost exclusively on a bundled basis (i.e., the same entity provided a delivered product called electric energy and transmission was part and parcel of that product). The FPA clearly reserves the right to regulate retail sales of electric energy to the states. As we explained in the Final Rule, however, in today's markets, and increasingly in the future as more states adopt retail wheeling programs, retail transactions are being broken into products that are being sold separately: transmission and generation. Moreover, these products are being sold increasingly by two or more different entities. For example, a transaction may involve transmission service from one or more transmission providers who move power from a distant generation supplier, over the interstate transmission grid, to an end user. Because these types of products and transactions were not prevalent in the past, the jurisdictional issue before us did not arise and, contrary to IL Com's argument, the Commission cannot be viewed as "disturbing" Docket Nos. RM95-8-001 -171- and RM94-7-002 the jurisdiction of state regulators prior to and after the Attleboro case. 461/ As we also explained in the Final Rule, the legislative history of the FPA and the relevant case law similarly reflect the historical market structure in which electricity and transmission generally were bought on a bundled basis. 462/ Today's unbundled world simply was not contemplated and the cases do not resolve dispositively this jurisdictional issue. The case law focuses primarily on the bright line between wholesale sales and retail sales of energy, and transmission in interstate as opposed to intrastate commerce. It does not address unbundled retail interstate transmission. 463/ We therefore have interpreted the case law in light of changed circumstances and Public Utilities Commission v. Attleboro Steam & Electric Co., 273 U.S. 83 (1927). The case law is addressed extensively in Appendix G to the Final Rule and will not be repeated here. On rehearing, several parties argue that at least one court case, Wisconsin-Michigan Power Co. v. FPC, 197 F.2d 472 (7th Cir. 1952), cert. denied, 345 U.S. 934 (1953) explicitly applied the wholesale/retail distinction to distinguish transmission and local distribution services. The Commission discussed this case in detail in Appendix G to the Final Rule, FERC Stats. & Regs. at 31,974-75; mimeo at 22-25. As we stated there, the court's interpretation of the legislative history of the FPA was at odds with both the plain words of the statute as well as the language of the House Report on the FPA (H.R. Rep. No. 1318 at 27). It also did not mention the Senate Report on the FPA, which clearly recognized jurisdiction over all interstate transmission lines, whether or not a sale of energy is carried by those lines (S. Rep. No. 621 at 48). We therefore reject arguments that this single case is in any way dispositive of the issue before us. Docket Nos. RM95-8-001 -172- and RM94-7-002 have relied in the first instance on the plain wording of the statute. We find compelling that section 201 of the FPA, on its face, gives the Commission jurisdiction over transmission in interstate commerce without qualification; unlike our jurisdiction over sales of electric energy, which section 201 specifically limits to sales at wholesale, the statute does not limit our transmission jurisdiction over public utilities to wholesale transmission. Since the time Order No. 888 issued, the D.C. Circuit has addressed a similar issue in interpreting section 1(b) of the NGA, the provision that parallels section 201(b) of the FPA. Under section 1(b), the Commission's jurisdiction does not apply "to the local distribution of natural gas or to the facilities used for such distribution." Similarly, under section 201(b) of the FPA, the Commission shall not have jurisdiction, except as specifically provided, "over facilities used for the generation of electric energy or over facilities used in local distribution. . ." In responding to arguments regarding the scope of state authority over "local distribution" of natural gas, the court distinguished between bundled and unbundled sales: States have been -- and are still -- permitted to regulate LDCs' bundled sales of natural gas to end-users because those transactions include transportation over local mains and the retail sales of gas. In contrast, states have never regulated the terms and conditions of interstate pipeline transportation. When the gas sales element is severed -- i.e., unbundled -- from the transactions, FERC retains jurisdiction over the interstate transportation component." Docket Nos. RM95-8-001 -173- and RM94-7-002 [United Distribution Companies, 88 F.3d at 1153 (footnote omitted) (emphasis in original).] The court's reasoning is also applicable to and supports our jurisdictional determination in Order No. 888. Several state commissions point to section 212(h) of the FPA and argue that Congress, in refusing to grant the Commission authority to order retail wheeling, left all jurisdiction over retail transmission to the states. We disagree. What Congress did in section 212(h) was to prohibit us from ordering transmission directly to an ultimate consumer. We readily recognize and respect this prohibition. However, the ability to order retail wheeling is a separate issue from whether we have jurisdiction over the rates, terms and conditions of retail wheeling in interstate commerce that is ordered by a state or that is provided voluntarily. Congress, in enacting section 212(h), did nothing to modify our jurisdiction under sections 201, 205 and 206 over the rates, terms and conditions of interstate transmission by public utilities. Similarly, we reject FL Com's arguments that section 212(g) of the FPA prohibits the Commission from asserting any jurisdiction over unbundled retail transmission. Section 212(g) prohibits the Commission from issuing an order that is inconsistent with any state law that governs retail marketing areas of electric utilities. As we stated in the Final Rule, while our jurisdiction cannot affect whether and to whom a retail electric service territory (marketing area) is to be granted by Docket Nos. RM95-8-001 -174- and RM94-7-002 the state, and whether such grant is exclusive or non-exclusive, neither can state jurisdiction affect this Commission's exclusive jurisdiction over the rates, terms and conditions of transmission in interstate commerce by public utilities. We also reject arguments by the FL Com that this Commission's jurisdiction over transmission terminates at the territorial boundary of each electric utility in Florida. This argument is flatly contrary to the longstanding interpretation of the FPA by the United States Supreme Court. 464/ Commission's Seven Factor Test IL Com argues that the Commission should withdraw its technical test. It contends that retail wheeling jurisdiction should follow function and that the function served by public utility facilities in providing retail service does not change upon the unbundling of service to retail customers. According to IL Com, Commission jurisdiction would extend to the service of delivering electric energy by a public utility to wholesale customers, regardless of the nature and extent of the public utility's facilities used to make that delivery. Similarly, it asserts, state jurisdiction would extend to the service of delivering electric energy by a public utility directly to retail customers, regardless of the nature and extent of the public utility's facilities used to make that delivery. See FPC v. Southern California Edison Co., 376 U.S. 205 (1964) (Colton case). IN Com makes a similar argument and opposes "federalization" of retail wheeling within a state's boundaries. We reject this argument on the same basis. Docket Nos. RM95-8-001 -175- and RM94-7-002 NARUC argues that the seven-factor test does not result in the bright line discussed in FPC v. Southern California Edison Company, 376 U.S. 205 (1964). The facility-by-facility categorization of utility systems on a company-specific basis, it asserts, is hardly consistent with the Court's decision to make case-by-case analysis unnecessary. OH Com asserts that the seven factors provide no useful insight into the nature of local distribution service. It adds that reliance upon technical tests to determine local distribution lacks legal foundation. It further contends that the jurisdictional bright line established by Congress focuses upon the nature of the transaction, not the functional or technical characteristics of a particular wire, in determining whose jurisdictional authority attaches to a particular transaction and facilities. It concludes that the Commission should adopt the Ohio-proposed retail marketing area "wheeling in" jurisdictional approach. PA Com contends that the Commission's seven indicia are not acceptable measures of local distribution and challenges each factor. NH & MI Coms declare that the criteria for distinguishing transmission facilities from local distribution facilities should not be limited to the seven given in the Rule, but should allow consideration of any other relevant criteria for separating local concerns from matters legitimately federal in nature. Docket Nos. RM95-8-001 -176- and RM94-7-002 NJ BPU argues that the engineering-driven definition does not resolve many of the hazy areas. To the extent that the seven factors do not reflect or cannot be reconciled with the particular circumstances, it contends that the states may be hamstrung in their ability to make reasoned decisions that comport with Order No. 888. 465/ Similarly, NY Com argues that five of the seven factors (1, 2, 4, 6,and 7) are not accurate when applied to large metropolitan areas and remote rural areas. It asserts that local distribution facilities are not necessarily close to retail customers and the assumption that local distribution facilities are primarily radial in character fails to account for network systems. It adds that reconsignment or transportation of power to different markets can and does occur at the local distribution level. It further adds that the presence of meters is not a discerning characteristic of where interstate transmission ends and local distribution begins; meters are frequently not part of the transmission/local distribution interface. Nor, according to NY Com, are local distribution systems necessarily of reduced voltage. Instead of the 7 criteria, NY Com argues that the Commission should adopt a functional measure of local distribution based on factors 3 and 5 (interstate transmission See also WI Com (criteria do not appropriately reflect the mixed nature of many facilities in systems that are closely integrated and the application of the criteria to the electric system in Wisconsin would supplant state jurisdiction over a large number of facilities whose primary functions are local reliability and retail service). Docket Nos. RM95-8-001 -177- and RM94-7-002 ends and local distribution begins where electricity flows into a comparatively restricted geographic area and does not flow back out of that area and the power is consumed in that area) and on the traditional classification of the facilities by the state regulatory body (or what the utility has traditionally classified as local distribution). Commission Conclusion Several parties on rehearing do not like the seven-factor technical test for local distribution facilities that was set forth in Order No. 888. That test takes into account both technical and functional characteristics of the transaction involved. The parties on rehearing propose instead a variety of bright line tests. For example, IL Com wants state jurisdiction to extend to the "service" of delivering electric energy to retail customers, which it would define to give it jurisdiction regardless of the nature and extent of the facilities used to make the delivery. OH Com proposes that the Commission adopt a retail marketing area "wheeling in" jurisdictional approach which would give it jurisdiction over facilities within territorial boundaries. In response, we do not interpret the FPA to permit us in effect to rewrite the statute to give states jurisdiction over interstate transmission services. Moreover, we reject arguments of OH Com that our seven-factor test lacks legal foundation, and arguments of NARUC that we are somehow bound to develop a bright line test. While Congress established a jurisdictional bright Docket Nos. RM95-8-001 -178- and RM94-7-002 line between wholesale and retail sales of energy, there is no such bright line that we can divine with regard to transmission and local distribution facilities. The Supreme Court, in both Colton and CL&P, 466/ has instructed us that whether facilities are used in local distribution is a question of fact to be decided by the Commission as an original matter. The seven factors will permit us to undertake this fact-specific determination. We acknowledge the concerns raised by several state commissions that the seven-factor test does not, as NJ BPU puts it, resolve many of the hazy areas, and that there may be other factors that should be taken into account in particular situations. The seven-factor test is intended to provide sufficient flexibility to take into account unique local characteristics and historical usage of facilities used to serve retail customers. We specifically stated in the Final Rule that we will consider jurisdictional recommendations by states that take into account other technical factors that states believe are appropriate in light of historical uses of particular facilities. Moreover, we will defer to facility classifications and/or cost allocations that are supported by state regulatory authorities. For example, in the ongoing California electric utility restructuring proceeding, the Commission deferred to the State PUC's recommendations regarding the split between state- See Colton, 376 U.S. at 210 n.6; CL&P, 324 U.S. at 531-36. Docket Nos. RM95-8-001 -179- and RM94-7-002 jurisdictional local distribution facilities and Commission- jurisdictional transmission facilities. 467/ Oppose transmission of public utility purchases for sale at retail IL Com objects to the transmission unbundling requirement if it is intended to require public utilities to take transmission services under their own FERC tariffs for purchases of power intended for distribution by the public utility to retail customers. According to IL Com, a distinction must be made between the public utility's use of its transmission system in cases in which the public utility purchases wholesale power for sale for resale, and cases in which the public utility purchases wholesale power to serve native load retail customers. It argues that the Commission cannot legally regulate, or place conditions on, the manner in which a utility uses its transmission system to make sales of electric energy at retail. It contends that the Commission must exempt public utility power purchases for sale at retail from the unbundling requirement. It recommends that the Commission insert the words "for sale for resale" after the word "purchases" in section 35.28(c)(2) and after the word "purchase" in section 35.28(c)(2)(i). Commission Conclusion The Commission rejects arguments of IL Com that if unbundled retail wheeling occurs either voluntarily or as a result of a Pacific Gas and Electric Company, et al., 77 FERC  61,325 at 61,325 (1996). Docket Nos. RM95-8-001 -180- and RM94-7-002 state retail program, we cannot require the utility to take service under its own transmission tariff for sales to retail customers. This requirement is a term and condition of unbundled retail interstate transmission service and, as explained above, therefore is within our exclusive jurisdiction. Additionally, this should not in any way infringe on state retail programs or service to retail customers. Rather, it ensures that non- discriminatory transmission services are provided to all potential retail power competitors. Further, as stated previously in Section IV.C.1.b (Transmission Providers Taking Service Under Their Tariff), we clarify that a transmission provider does not have to "take service" under its own tariff for the transmission of power that is purchased on behalf of bundled retail customers. Oppose buy-sell transaction analysis PA Com asserts that there is a potential for jurisdictional conflict with respect to buy-sell transactions that is a direct consequence of the technical-functional test (which PA Com challenges). IL Com argues that states have exclusive authority to regulate buy-sell arrangements as bundled retail sales. It further argues that the Commission cannot make a bundled retail sale into an unbundled retail sale simply by characterizing it as the functional equivalent of an unbundled retail sale; by re- characterizing them the Commission is effectively ordering the unbundling of buy-sell arrangements. It asserts that buy-sell Docket Nos. RM95-8-001 -181- and RM94-7-002 arrangements on the electric side are not an end run around clear federal jurisdiction and that the Commission should withdraw its assertion of jurisdiction over the retail transmission component of unbundled retail sales. VT DPS contends that the Commission's rationale is flawed: "FERC's analysis rests on the same very shaky ground as its similar claim of jurisdiction over buy-sell arrangements by local gas distribution companies." According to VT DPS, all retail transactions are subject to state jurisdiction and asks the Commission to clarify that the Commission defines buy-sell as it did in the NOPR, but also acknowledge that it has no jurisdiction over such arrangements. IN Com asserts that in the absence of any record of abusive and undermining actions by states under the guise of buy-sell arrangements, there is not even a remedial justification to touch buy-sell transactions. It contends that a difference between the FPA and the NGA warrants different treatment -- the FPA exempts from FERC jurisdiction local distribution and transmission of electric energy in intrastate commerce. By redefining interstate transmission, IN Com claims that the Commission proposes to do away with the meaning history has accorded to a variety of transactions previously considered wholly intrastate in nature. According to IN Com, states should be allowed to experiment with and allow different forms of buy-sell transactions as part of the evolving marketplace. Docket Nos. RM95-8-001 -182- and RM94-7-002 Commission Conclusion Four parties (PA Com, IL Com, VT DPS and IN Com) have raised concerns regarding the Commission's determination that it has jurisdiction over the interstate transmission component of transactions in which an end user arranges for the purchase of generation from a third party. The Commission reiterates that we will have to address these situations on a case-by-case basis. We disagree with IL Com that States have exclusive authority to regulate the interstate transmission component of buy-sell transactions. Similarly, we deny the VT DPS request that we acknowledge no jurisdiction over such arrangements. The fact remains that these arrangements could be used by parties to obfuscate the true transactions taking place and thereby allow parties to circumvent Commission regulation of transmission in interstate commerce. We reserve our authorities to ensure that public utilities and their customers are not able to circumvent non-discriminatory transmission in interstate commerce. In response to VT DPS' contention that the Commission's analysis here rests on the same shaky ground as its similar claim of jurisdiction over buy-sell arrangements by local gas distribution companies, we note that the D.C. Circuit recently affirmed the Commission's assertion of jurisdiction over buy/sell arrangements under the Natural Gas Act. 468/ United Distribution Companies, 88 F.3d at 1154-57. Docket Nos. RM95-8-001 -183- and RM94-7-002 State jurisdiction over the service of delivering electric energy to end users Rehearing Requests IL Com states that it is far from clear what FERC contemplates by the "service" of delivery of electric energy by a delivering utility in the retail wheeling transaction. It is equally unclear to IL Com whether the "service" to which Order No. 888 refers is a public utility activity over which state regulators would have jurisdiction. IL Com argues that it is the Illinois legislature, not FERC, that determines whether IL Com can regulate something called "delivery service." 469/ MO/KS Coms ask the Commission to clarify the meaning of the statement that even when the test for local distribution facilities identifies no local distribution facilities, the Commission believes that states have authority over the service of delivering electric energy to end users. According to MO/KS Coms: The authority to shop at retail and to sell at retail do not exist in the FPA. If the Commission's goal is to recognize the States' authority to establish conditions on retail competition, it need only acknowledge the State jurisdiction to establish the opportunity to shop and sell at retail. If this is what the Commission is seeking to accomplish by its discussion of 'delivery See also AK Com (should not create a fictional concept of delivery service -- the legal reality is that, under retail competition, state law will establish a customer's right to be served and a generation owner's right to produce power. AK Com asserts that the state can then attach conditions to those rights). Docket Nos. RM95-8-001 -184- and RM94-7-002 service,' then we support the Commission." [470/] Coalition for Economic Competition asserts that the Commission failed to consider that the sale of electric energy may take place outside of the state into which the energy is transmitted, and that the local regulatory commission may have no jurisdiction over either the sale or the transmission of the energy. Commission Conclusion Several parties ask us to clarify our conclusion that even when the seven-factor test for local distribution facilities does not identify local distribution facilities, we believe states have authority over the "service" of delivering electric energy to end users. We clarify that states have the authority to determine the retail marketing areas of electric utilities within their jurisdictions, and the end user services that those utilities must provide, but we did not in Order No. 888 intend to opine on the extent of authority given by state legislatures to their state commissions. Rather, our statement regarding state authority over the "service" of delivering electric energy is intended to recognize the historical and local nature of delivering power to end users and the states' legitimate concerns and responsibilities in regulating local matters. MO/KS Coms at 1-13. Docket Nos. RM95-8-001 -185- and RM94-7-002 Deference to states Rehearing Requests Support broader deference NARUC and IL Com argue that the Commission should not simply defer to state recommendations concerning the application of the seven-factor test or the recovery of stranded costs, but should conclusively rely on the findings by state commissions. NY Com argues that the Commission should not limit deference to instances in which states order retail wheeling, but should defer to all state commission recommendations regarding the definition of local distribution facilities. FL Com asserts that the Rule fails to say where deference will be given. It argues that the Rule should state that when a state commission has held a proceeding on matters related to the requirements of the Rule, the Commission shall give deference to the state commission decisions. Moreover, it asserts that the Commission should codify the deference standard: "When a state commission has held a proceeding on matters related to the requirements of this rule, the Commission shall give deference to the state commission decisions." (FL Com at 7-9). The commitment to defer to a state regulatory commission or agency, argues NE Public Power District, should be clarified with respect to utilities located in Nebraska, which has no such commission or agency. NE Public Power District assumes that deference will be accorded to decisions of NE Public Power Docket Nos. RM95-8-001 -186- and RM94-7-002 District's Board of Directors; if not, it asks the Commission to clarify. PA Com asks the Commission to clarify what a state regulatory agency must demonstrate to secure deference and to define the term "consult." PA Com states that, in discussing the seven indicia, the Commission states that it will "consider" jurisdictional recommendations by states, which PA Com asserts is much different from deference. It also asserts that the Commission must clarify what it will do if a utility's classifications and/or cost allocations are not supported by state regulatory authorities. Oppose deference to state authorities TANC argues that the Commission erred in deferring to state regulatory authorities in drawing jurisdictional lines for local distribution facility classifications and/or cost allocations. According to TANC, the Commission unlawfully and unnecessarily abdicated its jurisdiction under the FPA (citing New England Power Co. v. New Hampshire, 455 U.S. 331, and Nantahala Power and Light Co. v. Thornburg, 476 U.S. 953). With respect to ISOs, it asserts that the Commission should not defer to state authority in making determinations with respect to classifications of facilities. Commission Conclusion In response to NARUC and IL Com's arguments that this Commission should not simply defer to state commissions regarding application of the seven-factor test but instead should Docket Nos. RM95-8-001 -187- and RM94-7-002 conclusively rely on the findings of state commissions, we believe this is inconsistent with the case law which states that local distribution it is a matter of fact for the Commission to determine as an original matter. 471/ Additionally, we have an independent obligation to ensure that we are fulfilling our responsibilities under the FPA to regulate facilities that are used in interstate commerce. We cannot delegate our jurisdiction. However, we intend to provide broad deference to states in determining what facilities are Commission- jurisdictional transmission facilities and what facilities are state-jurisdictional local distribution facilities, so long as our comparability principles are not compromised and we are able to fulfill our responsibilities under the statute. We reject FL Com's suggestion that we codify the deference standard. This is neither necessary nor appropriate. In response to NE Public Power District's request that we clarify to whom we would give deference in Nebraska, we clarify that because Nebraska does not have an electric regulatory commission or agency, there is no appropriate regulatory entity to whom our deference standard would apply; accordingly, we will address the transmission/local distribution issue for Nebraska without giving deference to any particular entity. In response to PA Com's request that we clarify what we will do if a utility's classifications and/or cost allocation proposals are not See Colton and Connecticut Light and Power, supra. Docket Nos. RM95-8-001 -188- and RM94-7-002 supported by state regulatory authorities, we will make a determination based on the factual record before us in a particular case, taking into account the views of the state regulatory authority. TANC has argued that we have unlawfully abdicated our jurisdiction by deferring to state recommendations. TANC confuses delegation of jurisdiction, which we cannot do, with willingness to defer to states based on their application of criteria that we have provided. Even in the cases in which the Commission defers to states' views, we will still independently evaluate all material issues and proceed only where substantial evidence supports the states' views. The Commission clearly can entertain requests for deference in these circumstances. J. Stranded Costs As indicated in our prior discussion in Section IV.A.5, there are two major overlapping transition issues that arise as a result of this rulemaking: stranded cost recovery and how to deal with contracts entered into under the prior regulatory regime. We here address stranded cost recovery and, as in the prior discussion, we believe it is important to explain the general context in which our stranded cost determinations have been made before addressing the various rehearing requests on this issue. In Order No. 888, the Commission removed the single largest barrier to the development of competitive wholesale power markets by requiring non-discriminatory open access transmission as a Docket Nos. RM95-8-001 -189- and RM94-7-002 remedy for undue discrimination. This action carries with it the regulatory public interest responsibility to address the difficult transition issues that arise in moving from a monopoly, cost-based electric utility industry to an industry that is driven by competition among wholesale power suppliers and increasing reliance on market-based generation rates. The most critical transition issue that arises as a result of the Commission's actions in this rulemaking is how to deal with the uneconomic sunk costs that utilities prudently incurred under an industry regime that rested on a regulatory framework and a set of expectations that are being fundamentally altered. The Commission determined in Order No. 888 that it must address stranded costs, and that it must do so at an early stage -- particularly in light of the lessons learned from our experience with similar issues in the natural gas area. We noted that when we did a similar restructuring in the gas industry, the D.C. Circuit invalidated the Commission's efforts precisely because the Commission had failed to deal with the stranded cost problem in a satisfactory manner. 472/ We explained that, based on the lesson of AGD, the Commission cannot change the rules of the game without providing a mechanism for recovery of the costs caused by such regulatory-mandated change. Since the time Order No. 888 issued, we have been provided with additional guidance from the court in the natural gas area, Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988) (AGD). Docket Nos. RM95-8-001 -190- and RM94-7-002 which has further helped to inform our decisions here. In its decision on review of Order No. 636, 473/ the D.C. Circuit upheld the Commission's decision to allow the recovery of gas supply realignment costs. In so doing, the court, while questioning a specific feature of the stranded cost recovery mechanism employed in Order No. 636, has nevertheless again reaffirmed the basic principle that stranded cost recovery is an appropriate component of a regulatory policy aimed at accomplishing a fair and reasonable transition to competitive markets. The question as to the Commission's ability to allow the recovery of stranded costs has been laid to rest. The task before the Commission in this rulemaking is thus to determine how best to meet its responsibility to address the costs of the transition to a competitive industry, particularly insofar as those costs are stranded, or in effect rendered unrecoverable, as a result of the transmission access required by us under the FPA. 474/ As the rehearing arguments demonstrate, there is no consensus on how the Commission should address the stranded cost issue. In fact, petitioners are at polar extremes as to what the Commission should do regarding stranded costs. Some argue that the Commission has gone too far in permitting utilities to seek recovery of stranded costs, whether such costs United Distribution Companies v. FERC, 88 F.3d 1105 (1996) (United Distribution Companies). Such access may be the open access required under this Rule or case-by-case transmission access ordered pursuant to FPA section 211. Docket Nos. RM95-8-001 -191- and RM94-7-002 are associated with wholesale requirements contracts, with retail-turned-wholesale customers, or with retail customers that obtain retail wheeling. 475/ Others argue that the Commission has not gone far enough and that it must broaden the scope of stranded cost recovery permitted under the Rule. Indeed, some would have us be the guarantor for recovery of all uneconomic costs that might be stranded in the move to more competitive markets, no matter how tenuous the nexus to this Rule, and irrespective of state-Federal jurisdictional complexities. Some support the Commission's decision to recover stranded costs directly from the departing customers. Others would prefer that the Commission require utilities to absorb a portion of their stranded costs or that the Commission spread the burden of stranded costs among all of the utility's customers. Some object that the Commission's approach to stranded costs in the electric industry is different from that adopted in the gas industry. Some entities support the Commission's revenues lost approach for We note that the regulations implementing this Rule use "wholesale stranded cost" and "retail stranded cost" as shorthand terms to refer to the different situations in which a utility may experience stranded costs. However, as the definitions of those terms make clear, it is not the nature of the costs (wholesale vs. retail) that is controlling for purposes of stranded cost recovery under this Rule. Rather, the controlling factors are the status of the customer (wholesale transmission services customer vs. retail transmission services customer) with whom the costs are associated, and whether the transmission tariffs used by the customer to escape its former power supplier (thus causing the stranding of costs to occur) were required by this Commission or by a state commission. As a result, "retail stranded costs" refers to stranded costs associated with retail wheeling customers. Docket Nos. RM95-8-001 -192- and RM94-7-002 measuring a departing customer's stranded cost obligation. Others propose different methods for computing stranded costs. Given the plethora of positions that entities have raised both initially and on rehearing concerning stranded costs, the Commission has taken a careful, measured approach with regard to stranded cost recovery. The Commission has balanced a number of important interests in order to achieve what it believes will be a fair and orderly transition to competitive markets. These interests include the financial stability of the electric utility industry, upholding the regulatory bargain under which utilities made major capital investments, and not shifting costs to customers that had no responsibility for causing those costs to be incurred. The Commission also has adopted an approach that, for purposes of stranded cost recovery from wholesale transmission customers, relies on the nexus between stranded costs and the use of transmission tariffs required by this Commission and, for purposes of stranded cost recovery from retail customers, recognizes state commission jurisdiction but fills potential regulatory gaps that could arise in the transition to new market structures. The balancing of interests and considerations described above is reflected in the following central components of the Rule's stranded cost provisions, which are reaffirmed herein. 476/ First, the Commission has determined that the most We reaffirm below our basic determinations, but make certain (continued...) Docket Nos. RM95-8-001 -193- and RM94-7-002 reasonable, legally supportable approach is one that permits utilities to seek recovery of wholesale stranded costs under this Rule (whether the stranded costs are associated with a departing wholesale requirements customer or with a retail-turned-wholesale customer) only in those cases in which there is a direct nexus between the availability and use of Commission-required transmission access 477/ and the stranding of costs. In order for the utility to be eligible to seek recovery of stranded costs from a departing customer, the customer must have obtained access to a new generation supplier through the use of the former supplying utility's Commission-required transmission tariff (i.e., its open access tariff or a tariff ordered pursuant to FPA section 211), not through the use of another utility's transmission system. Other cost recovery issues are more appropriately addressed outside the context of this Rule. For example, the Rule is not intended to apply to costs associated with the normal risks of competition, such as self-generation, cogeneration, or loss of load, that do not arise from the new, accelerated availability of (...continued) clarifications on limited issues and grant rehearing on the municipal annexation issue. As we explain below, by "Commission-required transmission access" we mean the open access transmission required under this Rule or required pursuant to a section 211 order, as well as transmission provided prior to Order No. 888 (and not pursuant to a section 211 order) where such transmission was provided on a case-by-case basis to comply with the Commission's comparability requirement. See note 484 infra. Docket Nos. RM95-8-001 -194- and RM94-7-002 Commission-required transmission access. If a customer leaves its utility supplier by exercising options that could have been undertaken prior to mandatory transmission under Order No. 888 or the Energy Policy Act, or that do not rely on access to the former seller's transmission, there is no direct nexus to Commission-required transmission access and thus no opportunity for stranded cost recovery under the Rule. Second, the Commission has limited the opportunity to seek stranded cost recovery under the Rule primarily to two discrete situations: (1) costs associated with customers under wholesale requirements contracts executed on or before July 11, 1994 (referred to in the Rule as "existing wholesale requirements contracts") that do not contain an exit fee or other explicit stranded cost provision; and (2) costs associated with retail- turned-wholesale customers. With regard to the existing wholesale requirements contracts, the Commission also has made a finding that it is in the public interest to permit amendments to add stranded cost provisions to these contracts, even if they contain Mobile-Sierra clauses, if case-by-case evidentiary burdens are met. We do not interpret the Mobile-Sierra public interest standard as practically insurmountable in extraordinary situations such as this one where historic statutory and regulatory changes have converged to fundamentally change the obligations of utilities and the markets in which they and their customers will operate. Docket Nos. RM95-8-001 -195- and RM94-7-002 Third, Order No. 888 does not guarantee that a utility will be allowed to recover stranded costs. Rather, it provides an opportunity for such recovery. To be eligible to recover stranded costs from a departing customer in a particular case, the utility must demonstrate that it incurred costs to provide service to the customer based on a reasonable expectation of continuing service to that customer beyond the contract term. 478/ In the case of stranded costs associated with wholesale requirements contracts customers, if the contract contains a notice of termination provision, that provision is strong evidence that the parties were aware that at some point in the future the customer might seek to find another supplier. Therefore, there is a rebuttable presumption of no reasonable expectation, and therefore no opportunity for stranded cost recovery unless the utility can overcome the presumption. The Commission has concluded that direct assignment of stranded costs to the departing customer (through either an exit fee or a surcharge on transmission) is the appropriate method for recovery of stranded costs under the Rule. In reaching this conclusion, the Commission carefully weighed the arguments supporting direct assignment of stranded costs against those supporting a more broad-based approach, such as spreading stranded costs to all transmission users of a utility's system, We have made a minor revision to the regulatory text, section 35.26(c)(2), to conform the language of that section with sections 35.26(b)(1) and (5). A conforming revision has been made to section 35.26(d)(2)(i). Docket Nos. RM95-8-001 -196- and RM94-7-002 and also took into account the fact that we applied a different approach in the natural gas area. The central considerations that support a direct assignment approach in the electric industry are that the approach follows the traditional regulatory concept of cost causation, it avoids shifting costs to customers that had no responsibility for causing them to be incurred or for causing them to be stranded, and it is still possible to apply such an approach at this stage of the industry's evolution. There is no question that, without the stranded cost recovery mechanism, some customers would be far more likely to switch to lower-cost suppliers and enjoy sooner the benefits of a competitive power market. But, as detailed in Order No. 888, such an approach may result in higher costs for other customers. We thus have had to balance the potential for earlier benefits for some customers against other public interest considerations, most particularly the need to provide a fair mechanism by which utilities can recover the costs of past investments under traditional regulatory concepts of prudently incurred costs and cost causation. The result is not to deny competitive advantages, but only to delay their full realization for some customers so that all customers ultimately will benefit. While Order No. 888's cost causation approach is different from the Order No. 636 cost spreading approach that was affirmed in the United Distribution Companies case, we believe it is the preferable approach given the early stage of the electric utility's competitive transition. We do not read the court's Docket Nos. RM95-8-001 -197- and RM94-7-002 opinion as precluding the Commission from adopting a direct assignment approach in Order No. 888, particularly where, as here, the Commission has fully explained and justified the reasons for following traditional cost causation principles. In addition, although the United Distribution Companies court remanded for further consideration (in light of Order No. 636's cost spreading approach) the decision not to require any pipeline absorption of gas supply realignment costs, the Commission has fully explained how its decision in Order No. 888 not to require any utility absorption of stranded costs is consistent with its decision to follow traditional cost causation principles. With respect to the fundamental conclusion that utilities should be permitted an opportunity to recover their prudently incurred costs, Order No. 888 is fully consistent with Order No. 636. Although the Commission in Order No. 888 chose a direct assignment method (rather than the cost-spreading approach in Order No. 636) for purposes of allocating stranded cost responsibility among customers, the approach used by the Commission in Order No. 888 is not governed by decisions in Order No. 636, but in either event the Commission must demonstrate that its choice of methods is based on reasoned decision-making. In considering the stranded cost issues that may arise in the transition to competitive markets, the Commission also has taken cognizance of significant changes involving retail customers and the stranded cost issues that arise as retail customers convert to wholesale customer status (e.g., through Docket Nos. RM95-8-001 -198- and RM94-7-002 municipalizations) in order to obtain the open access afforded by Order No. 888, or as they obtain retail wheeling required by state commissions. These situations involve new and complex jurisdictional issues and represent the bulk of potential stranded costs facing the industry. We believe it is important to clarify the Commission's decisions as to when it will entertain requests for stranded cost recovery in these situations, and our reasons for doing so. The Commission's determination that it, rather than the states, should be the primary forum for addressing stranded costs associated with a retail-turned-wholesale customer 479/ is limited to those cases in which there is a direct nexus between the availability and use of Commission-required transmission access and the stranding of costs. We believe we have both the authority and the obligation to provide an opportunity for In Order No. 888 and here, we sometimes use the shorthand expression "retail-turned-wholesale" customer. By this we do not mean that a retail customer who is an ultimate consumer ceases to be an ultimate consumer, or that this customer begins to purchase electric energy for resale. Rather, in a "retail-turned-wholesale customer" situation, such as the creation of a municipal utility system, a newly- created entity becomes a wholesale power purchaser on behalf of retail customers who were formerly bundled customers of the historical local utility power supplier. The new municipal utility is the conduit by which retail customers, if they cannot obtain direct retail access, can reach power suppliers other than their historical local utility power supplier. Although the retail customers remain bundled retail customers, in that they become the bundled customers of the new entity, we call this a "retail-turned-wholesale customer" situation because the new entity in effect "stands in the shoes" of the retail customers for purposes of obtaining wholesale transmission access and new power supply. Docket Nos. RM95-8-001 -199- and RM94-7-002 stranded cost recovery in these situations because the bundled retail customer would not be able to obtain access to the new supplier but for the Commission's order requiring transmission. The creation of a new wholesale entity to purchase power on behalf of retail customers would not, by itself, trigger stranded costs. In the absence of transmission access from the historical supplier of the retail customers, the new entity would have to remain on the historical supplier's generation system because it would have no way to reach other power suppliers, and stranded costs would not occur. 480/ Therefore, there is a causal nexus between the stranded costs and the availability and use of the tariff services required by the Commission. 481/ Moreover, because of this causal nexus between the use of a jurisdictional utility's Commission-required transmission tariff and the potential for foregone revenues by that jurisdictional utility as Exceptions would be self-generation or construction by the new entity of its own transmission line, in which case, as noted earlier, the stranded cost provisions of Order No. 888 would not apply because such options have always been available as alternatives to purchasing power from the historical supplying utility and do not involve the use of the utility's transmission facilities under an open access tariff. Thus the departure of customers under these circumstances cannot be linked to the open access requirements of this Rule. As discussed in greater detail in Sections IV.J.6 and IV.J.12 below, we clarify that the opportunity for recovery of stranded costs in a retail-turned-wholesale situation is limited to cases in which the former bundled retail customer subsequently becomes, either directly or through another wholesale transmission purchaser, an unbundled wholesale transmission services customer of its former supplier. We have revised section 35.26(b)(1)(i) of the Commission's regulations accordingly. Docket Nos. RM95-8-001 -200- and RM94-7-002 a result of the Commission-required access, the stranded costs associated with a retail-turned-wholesale customer are properly viewed as economic costs that are jurisdictional to this Commission. In contrast, in the situation in which a bundled retail customer obtains retail wheeling, stranded costs are directly caused by the availability and use of unbundled retail services required by the state commission, not this Commission. 482/ Thus, the Commission believes that states, not the Commission, should be the primary forum for costs associated with a bundled retail customer that obtains retail wheeling. The Commission's decision to entertain requests to recover stranded costs caused by retail wheeling in only a limited circumstance (where the state regulatory authority does not have authority under state law to address stranded costs when the retail wheeling is required) is based on a policy decision by this Commission that it will step in to fill a regulatory "gap" that could result in no effective forum in which utilities would have an opportunity to seek recovery of prudently incurred costs. Finally, after considering various proposals regarding how stranded costs should be calculated, and reviewing the arguments Unbundled retail transmission services required by a state commission could be taken under the same pro forma open access tariff used by wholesale customers or, if determined appropriate by the Commission, under a separate retail tariff filed at the Commission. The critical point, however, is that in either case, the unbundled services are required by the state and not by this Commission. Docket Nos. RM95-8-001 -201- and RM94-7-002 of petitioners on rehearing, the Commission continues to believe that the revenues lost approach is the fairest and most efficient way to determine the amount of stranded cost assigned to a departing customer during the transition to a competitive wholesale bulk power market. The Commission has rejected an asset-by-asset approach as overly complicated and costly. We respond below to the specific arguments raised on rehearing and elaborate on the above determinations. 1. Justification for Allowing Recovery of Stranded Costs In Order No. 888, the Commission concluded that utilities should be given the opportunity to seek recovery of legitimate, prudent and verifiable stranded costs associated with a limited set of wholesale requirements contracts executed on or before July 11, 1994. 483/ We stated that utilities that entered into contracts to make wholesale requirements sales under an entirely different regulatory regime should have an opportunity to recover stranded costs that occur as a result of customers leaving the utilities' generation systems through Commission-jurisdictional open access tariffs or FPA section 211 orders to reach other power suppliers. We explained that utilities that made large capital expenditures or long-term contractual commitments to buy power years ago to supply their customers should not now be held responsible for failing to foresee the actions this Commission would take to alter the use of their transmission systems in FERC Stats. & Regs. at 31,788-91; mimeo at 451-58. Docket Nos. RM95-8-001 -202- and RM94-7-002 response to the fundamental changes that are taking place in the industry. We found that recent significant statutory and regulatory changes are central to the circumstances that now place at risk the recovery of past investment decisions of utilities. We indicated that we will not ignore the effects of these changes as we fashion policies that will govern possible recovery of these costs in the transition to an open access regulatory regime. We stated that while there has always been some risk that a utility would lose a particular customer, in the past that risk was smaller. It was not unreasonable for the utility to plan to continue serving the needs of its wholesale requirements customers and retail customers, and for those customers to expect the utility to plan to meet their future needs. We concluded that with the new open access transmission, 484/ the risk of losing a customer is radically increased. If a former wholesale requirements customer or a former retail customer uses the new In Order No. 888, we explained that by "new open access" or "open access transmission" we were referring to Commission- jurisdictional open access tariffs or to a tariff ordered pursuant to FPA section 211. Although we generally refer in the text of Order No. 888 and the text of this order to the open access tariffs required under this Rule and to tariffs required pursuant to a section 211 order, we clarify that the "new open access" or "open access transmission" described in this Rule also includes transmission provided prior to Order No. 888 (and not pursuant to a section 211 order) where such tariff filings were made on a case-by-case basis to comply with the Commission's comparability requirement. To avoid any confusion on this point, we refer in this order to all such open access transmission as "Commission-mandated transmission access" or "Commission- required transmission access." Docket Nos. RM95-8-001 -203- and RM94-7-002 open access to reach a new supplier, the utility is entitled to seek recovery of legitimate, prudent and verifiable costs that it incurred under the prior regulatory regime to serve that customer. The utility, however, would have the burden of demonstrating that it had a reasonable expectation of continuing to serve the departing customer. Rehearing Requests Opposing, or Seeking Limitations on, Stranded Cost Recovery Several entities challenge the Commission's decision to give utilities an opportunity to recover legitimate, prudent and verifiable stranded costs. NASUCA argues that the transition to wholesale competition was underway before and apart from the NOPR. It asserts that the drivers of the developing competition include voluntary open access filings by utilities seeking mergers or market-based rate authority and section 211 of the FPA, as amended by the Energy Policy Act of 1992 (Energy Policy Act). According to NASUCA, stranded investment results from legislative, not regulatory action, and the stranded cost issue does, and would, exist without the Open Access Rule. It contends that an acceleration of the competitive wholesale transformation does not change its nature or origins. NASUCA also contends that the issuance of the Open Access Rule does not justify stranded cost recovery on "regulatory compact" grounds because it is not a fundamental change. Other entities object that there is no basis for the Commission to impute an extra-contractual obligation to serve Docket Nos. RM95-8-001 -204- and RM94-7-002 wholesale requirements customers. 485/ These entities argue, for example, that utilities could and should have protected themselves from any potential stranded costs through individual customer contracts. IN Consumer Counselor and IN Consumers object that Order No. 888 attempts to transform the obligation to provide a utility with an "opportunity" for a fair return when prices are regulated into an "entitlement" to "recover legitimate, prudent and verifiable costs that it incurred under the prior regulatory regime." 486/ Several entities submit that the Commission has not adequately addressed the potential anticompetitive impact of stranded cost recovery. 487/ Some argue that giving utilities the opportunity to recover wholesale stranded costs will delay the opportunity for historically captive customers to benefit from competitive alternatives. 488/ Central Illinois Light contends that the Rule is arbitrary and capricious because it will have different impacts on different customers, which Central E.g., American Forest & Paper, Blue Ridge, TDU Systems, IN Consumer Counselor, IN Consumers, IL Com. IN Consumer Counselor at 9 (citing Order No. 888, mimeo at 452-53); IN Consumers at 10 (same). E.g., APPA, IN Consumer Counselor, IN Consumers, Suffolk County, TDU Systems, Specialty Steel, Occidental Chemical, Central Illinois Light, American Forest & Paper, Nucor, Blue Ridge. E.g., APPA, IN Consumer Counselor, IN Consumers, Suffolk county, TDU Systems, Specialty Steel. Docket Nos. RM95-8-001 -205- and RM94-7-002 Illinois Light asserts will be due to accidents of circumstance rather than the conscious application of rational policy choices. IN Consumers objects that two similarly-situated customers of the utility for identical transmission services will be required to pay substantially different rates for the same service (where one previously purchased its power requirements from the utility, while the other used an alternate source of supply). Central Illinois Light also objects that even a partial allowance of stranded costs will likely encourage predatory pricing. It says that the Commission has failed to adequately address the harm that stranded cost "subsidies" pose to low-cost utilities with little or no stranded costs. Others contend that the Rule would subvert economic efficiency by unjustly enriching utilities that have not attempted to meet the new market demands, to the detriment of those utilities that have. 489/ According to Occidental Chemical, the Commission has made no finding that the pro-competitive goals of Order No. 888 can be accomplished in light of the costs and uncertainties presented by stranded cost recovery. Several entities also challenge the adequacy of the factual record for allowing wholesale stranded cost recovery and argue that utilities have not provided the hard data on wholesale stranded costs that the Commission needs to justify Order No. E.g., American Forest & Paper, Nucor, Blue Ridge. Docket Nos. RM95-8-001 -206- and RM94-7-002 888. 490/ Central Illinois Light objects that the Commission failed to note or to discuss data presented by commenters showing that only a small group of high-cost utilities need some stranded cost protection. American Forest & Paper argues that the Commission has failed to demonstrate on the record the existence of any stranded wholesale investment that was or could be caused by the transition to open access transmission. SC Public Service Authority repeats its earlier request that the Commission deny market-based rate authority to any utility that elects to recover stranded costs from departing customers. 491/ It objects that the Commission failed to specifically respond to its previous comments on this issue. American Forest & Paper objects that utilities that voluntarily filed open access tariffs cannot use the stranded cost rule because their loss of customers cannot be said to have occurred only because of the Rule. It submits that only those utilities who had to be forced to offer open access transmission are being rewarded. San Francisco asks that the Commission include "exercise of pre-existing contract rights for transmission and designation of E.g., ELCON, TDU Systems, Central Illinois Light, American Forest & Paper. See also American Forest & Paper (unless a utility agrees not to seek stranded costs under the Rule, the utility should not be found to have mitigated its transmission market power for purposes of charging market-based rates, merging with other utilities or otherwise, simply by filing an open access tariff). Docket Nos. RM95-8-001 -207- and RM94-7-002 wholesale loads" or similar language as one of the examples (listed in footnote 718) of situations for which stranded costs may not be sought. San Francisco explains that it wants to ensure that PG&E would not have any basis to argue that any load loss PG&E suffers as a result of San Francisco's designation of municipal loads would be eligible for stranded cost recovery. Commission Conclusion We will deny the requests for rehearing of our decision to allow utilities an opportunity to seek recovery of legitimate, prudent, and verifiable stranded costs. As we indicated in Order No. 888, we learned from our experience with natural gas that, as both a legal and a policy matter, we cannot ignore these costs. The U.S. Court of Appeals for the District of Columbia Circuit invalidated the Commission's first open access rule for gas pipelines because the Commission failed to deal with the uneconomic take-or-pay situation that many pipelines faced as a result of regulatory changes beyond their control. 492/ That same court has subsequently affirmed the Commission's decision to allow the recovery of costs that are stranded in the transition to a competitive natural gas industry, most recently by upholding the Commission's decision in Order No. 636 to allow the recovery of gas supply realignment costs. 493/ AGD, 824 F.2d at 1021. United Distribution Companies, 88 F.3d 1105 (1996). Although the court remanded that aspect of Order No. 636 that allows pipelines to recover 100 percent of their gas (continued...) Docket Nos. RM95-8-001 -208- and RM94-7-002 Here we are faced, once again, with an industry transition in which there is the possibility that, as a result of statutory and regulatory changes beyond their control, certain utilities may be left with large unrecoverable, legitimate and prudent costs or that those costs will be unfairly shifted to other (remaining) customers. Thus, in order to satisfy our regulatory responsibilities, we must directly and timely address the costs of the transition by allowing utilities to seek recovery of legitimate, prudent and verifiable stranded costs. 494/ While the transition to wholesale competition may have begun before the NOPR, we strongly disagree with NASUCA's claim that the Open Access Rule does not justify stranded cost recovery because an acceleration of the transition does not change its nature or origins. The driving force behind the development of wholesale competitive markets is the widespread transmission access made available through Commission-mandated transmission tariffs, 495/ including transmission tariffs ordered pursuant to FPA section 211 and the transmission tariffs required by the Commission's (...continued) supply realignment costs without requiring any pipeline absorption, we explain in Section IV.J.3 below how Order No. 888 is fully consistent with that remand. See FERC Stats. & Regs. at 31,789; mimeo at 453-54. As we explain above, Commission-mandated transmission tariffs is meant to include all open access tariffs filed pursuant to Commission order, including tariffs filed under this Rule, tariffs ordered pursuant to FPA section 211, and tariffs that were filed on a case-by-case basis to comply with the Commission's comparability requirement. Docket Nos. RM95-8-001 -209- and RM94-7-002 Open Access Rule. 496/ Furthermore, as explained in the Rule and as further discussed below, it is the ability of customers to obtain readily available Commission-mandated transmission access that significantly increases the potential for wholesale stranded costs. Order No. 888 requires the functional unbundling of a public utility's wholesale services. Under the Rule, all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce were required by July 9, 1996 to file open access transmission tariffs that contain minimum terms and conditions of non-discriminatory service (or to seek waiver), and to take transmission service (including ancillary services) for their own new wholesale sales and purchases of electric energy under the open access tariffs. As a result of Order No. 888, wholesale requirements customers As a result of the Open Access Rule, 47 Group 2 public utilities, which had no open access transmission tariff available prior to Order No. 888, submitted and had available on July 9, 1996 non-discriminatory open access transmission tariffs. In addition, 101 Group 1 public utilities, which had some version of open access available prior to Order No. 888, filed new open access tariffs effective July 9, 1996 in order to conform to the terms and conditions of non-discriminatory open access service specified in the pro forma tariff. Thus, as of July 9, 1996, 148 of the 166 public utilities had filed Order No. 888 open access tariffs. At least ten others filed open access tariffs after July 9, 1996 (e.g., after the Commission dealt with their waiver requests). This, in the Commission's view, represents an unprecedented acceleration of the transition to competitive bulk power markets. From the issuance of the Open Access NOPR in March 1995 until the effective date of Order No. 888 on July 9, 1996 is only a little more than one year. Docket Nos. RM95-8-001 -210- and RM94-7-002 that previously were captive customers of their public utility suppliers (i.e., they had no choice but to take bundled sales and transmission services from their suppliers) will be able at the expiration of their contracts to take unbundled transmission service (i.e., transmission-only service) from their former suppliers in order to reach new suppliers. While in the past there has been some risk of stranded costs due to customers "leaving" a supplier's system through self-generation or perhaps municipalization, there was little or no ability to shop for alternative power such as that which will occur as a result of readily available Commission-mandated transmission access. Contrary to NASUCA's claims, Order No. 888, coupled with section 211 of the FPA, creates the opportunity, as a matter of law, for an existing wholesale requirements customer to use the transmission owner's facilities to reach a new supplier. 497/ NASUCA and other petitioners offer no persuasive evidence that meaningful competition took root prior to the availability of the new transmission access requirements. The few utilities that did provide transmission service under open access tariffs prior to the announcement of the Commission's comparability requirement did not offer third parties comparable service. To the contrary, such tariffs contained numerous disparities in the transmission service that the utilities provided to third parties in comparison to their own uses of the transmission system. See, e.g., Entergy Services, Inc., 58 FERC  61,234, order on reh'g, 60 FERC  61,168 (1992), remanded, sub nom., Cajun Electric Power Cooperative, Inc. v. FERC, 28 F.3d 173, 179-80 (D.C. Cir. 1994) (tariff contained limitations on point-to-point service and did not provide network service; tariff reserved transmission provider's right to cancel service in certain instances, even where a customer had paid for transmission system modifications). While the desire of customers for competitive power markets may have preceded Commission-mandated open access, customers had no (continued...) Docket Nos. RM95-8-001 -211- and RM94-7-002 This leaves the former supplying utility with significant risk that it will be unable to recover costs that the utility incurred based on a reasonable expectation that it would continue to serve the departing customer. Thus, the regulatory and statutory changes contained in Order No. 888 and in amended section 211, which will act in tandem to provide the transmission access necessary to develop the competitive wholesale markets envisioned by Congress in the Energy Policy Act, have a direct nexus to the potential for wholesale stranded costs. This nexus makes it critical that the Commission address this transition issue responsibly and equitably. Having balanced the goals of competition, the nexus between potential stranded costs and transmission access, and the regulatory bargain under which utilities invested billions of dollars in reliance on the prior regulatory regime, we believe that utilities are entitled to an opportunity to seek recovery of stranded costs and that our actions in Order No. 888 are not only legally supportable, but also represent sound public policy. In response to those entities who argue that there is no basis for imputing an extra-contractual obligation to serve wholesale requirements customers, as we explained in Order No. 888, we believe there previously has been an implicit obligation to serve at wholesale in many cases. Such obligation is based, (...continued) assurance they could reach alternative suppliers until the Commission required utilities to provide transmission service on a comparable basis. Docket Nos. RM95-8-001 -212- and RM94-7-002 in large part, on the recognition that historically most wholesale requirements customers were captive and had no means of reaching alternative suppliers. The local utility supplied bundled generation and transmission services to these customers on the assumption that they would remain as customers. Accordingly, the utility had a concomitant obligation to plan to supply these customers' continuing needs, and planned its system taking account of the wholesale load. In many cases the wholesale customers participated by supplying load forecasts. Consistent with this practical obligation to serve, the Commission viewed the supplying utility as the supplier of first resort, and did not allow a utility to terminate service without prior Commission approval. Before Order No. 888, the Commission's regulations required prior notification and approval of the proposed cancellation or termination of a wholesale requirements contract. We note that although Order No. 888 eliminates the prior notice of cancellation or termination requirement for power sales contracts executed on or after July 9, 1996 (the effective date of the Open Access Rule) that are to terminate by their own terms, 498/ it expressly retains the prior The Rule requires that the utility notify the Commission of the date of termination for this class of contracts within 30 days after the termination takes place. The Rule retains the prior notice of cancellation or termination requirement for power sales contracts executed on or after July 9, 1996 if termination is on grounds other than expiration of the contract by its terms at the end of the contract. See Portland General Electric Company, 75 FERC  61,310, reh'g denied 77 FERC  61,171 (1996) (Commission authorization (continued...) Docket Nos. RM95-8-001 -213- and RM94-7-002 notice of cancellation or termination requirement for any power sales contract executed before that date. It is important to note, however, that while the stranded cost recovery provisions of the Rule are based on the implicit obligation to serve, the Rule does not guarantee any extra- contractual wholesale stranded cost recovery, much less across- the-board recovery of such costs by all public utilities. To the contrary, it provides an opportunity for such recovery only for a discrete set of requirements contracts (those executed on or before July 11, 1994 that do not contain an exit fee or other explicit stranded cost provision), and the Rule requires that a utility must meet a heavy burden of proving eligibility to recover costs in a particular case: before a departing customer is required to pay a stranded cost exit fee or transmission surcharge, the utility must demonstrate that it incurred costs to provide service to a customer based on a reasonable expectation of continuing service to that customer beyond the end of the contract. 499/ (...continued) required for termination of power sales contract in the event of the commencement of a bankruptcy proceeding, failure to perform any obligation under the contract, or failure to provide adequate assurance of the ability to perform). To the extent there is any misunderstanding, we clarify that the intent of the Rule to permit the "opportunity" to recover stranded costs is not an "entitlement" to recover such costs. As a result, the passage in Order No. 888 to which IN Consumer Counselor and IN Consumers object (FERC Stats. & Regs. at 31,789, mimeo at 452-53) should read "we believe that the utility is entitled to an opportunity to recover (continued...) Docket Nos. RM95-8-001 -214- and RM94-7-002 We believe that we adequately address in both Order No. 888 and in Section IV.J.2 below the concerns various entities have expressed as to the potential anticompetitive impact of stranded cost recovery. Although we recognize that stranded cost recovery may delay some of the benefits of competitive bulk power markets for some customers, we believe that customers as a whole will benefit from a fair and orderly transition. Indeed, we are particularly concerned that the failure to assign stranded cost responsibilities to customers that have access to alternative suppliers will leave captive customers exposed to the risk of greater cost burdens, thereby shifting to captive customers the costs that were originally incurred for the benefit of the (typically larger) customers who have the flexibility to take early advantage of competing power suppliers. Avoiding this potential cost shifting problem is an important goal of our decision to address the stranded cost problem as part and parcel of the decision to mandate open access. As we said in Order No. 888: such transition costs must nevertheless be addressed at an early stage if we are to fulfill our regulatory responsibilities in moving to competitive markets. The stranded cost recovery mechanism that we direct here is a necessary step to achieve pro- competitive results. In the long term, the Commission's Rule will result in more (...continued) legitimate, prudent and verifiable costs that it incurred under the prior regulatory regime to serve that customer" (emphasis to show added language). Docket Nos. RM95-8-001 -215- and RM94-7-002 competitive prices and lower rates for consumers. [500/] We do not believe that allowing utilities an opportunity to seek stranded cost recovery will prevent us from achieving the pro-competitive goals of Order No. 888. To the contrary, as discussed below in Section IV.J.3, we think that it is necessary to provide utilities the opportunity to seek to recover stranded costs if we are to have a fair and orderly transition to more competitive bulk power markets. The opponents of Order No. 888's stranded cost approach argue that the transition to fully competitive bulk power markets will be slower if we allow utilities an opportunity to seek to recover stranded costs from departing customers, and with respect to some customers that may well be true. As noted earlier, some customers because of their size and limited contractual obligations with their current utility suppliers have the ability immediately to leave the system. If they are allowed to do so without paying the costs incurred to provide them expected future service, the economic attractiveness of departing the system is obviously enhanced and the benefits of competition, for these customers, obviously come sooner rather than later. However, the pace at which fully competitive markets are achieved, while important, is not the only consideration. It is the Commission's responsibility to ensure that the costs of open access are fairly assigned and that the benefits of Order No. 888's open access requirements will be FERC Stats. & Regs. at 31,794; mimeo at 468-69. Docket Nos. RM95-8-001 -216- and RM94-7-002 fairly available to all customers. These dual goals compel us toward a balanced approach that, although perhaps delaying somewhat the benefits of competition, nevertheless ensures that all customers will share in those benefits without undermining historic principles of cost recovery upon which utilities were entitled to rely in planning their systems. Moreover, as we explain in Section IV.J.3 below, we have carefully examined different methods of allocating stranded costs that are found to be properly recoverable, including assigning the costs directly to the departing customer or spreading the costs to all transmission users of a utility's system. We recognize that the direct assignment approach to stranded cost recovery delays competition for some customers because it attaches a price tag for customers who have the immediate ability to leave the system. However, we have identified the advantages and disadvantages of each approach and have concluded, on balance, that direct assignment is the preferable approach for both legal and policy reasons. In response to the concerns of some entities that stranded cost "subsidies" may harm low-cost utilities with little or no stranded costs, or otherwise may unjustly enrich utilities that have not attempted to meet the new market demands to the detriment of those that have, we again emphasize the limited and transitional nature of the stranded cost recovery opportunity Docket Nos. RM95-8-001 -217- and RM94-7-002 allowed under Order No. 888. 501/ It is clearly not the Commission's intent that utilities with little or no stranded cost exposure be competitively disadvantaged by the Open Access Rule. Those utilities with little or no stranded costs will be similarly situated with other new suppliers in the sense that they will all face the potential of not being able to compete immediately for certain wholesale customers who are determined to have an obligation to pay stranded costs. These customers may find it to be uneconomic to shop from new power suppliers because they may have to pay costs they caused to be incurred under the prior industry regime before they are able to switch suppliers. However, this will be during a transition period only, and only with respect to a discrete set of contracts and only where the utility meets its burden of proof with respect to a particular departing customer. We reject as misplaced IN Consumers' argument that the Open Access Rule is discriminatory because two "similarly-situated" customers for "identical" transmission services (one who previously purchased transmission bundled with its power requirements from the utility and now seeks to purchase only unbundled transmission, and the other who previously used an alternative source of supply and seeks to purchase unbundled transmission from the utility) will pay substantially different As we indicate in Section IV.J.9 below, we disagree that the Rule's definition of stranded costs artificially and unjustifiably improves the competitive position of an inefficient utility. Docket Nos. RM95-8-001 -218- and RM94-7-002 rates for the same service. The error in this argument is that the two customers in the example are not "similarly-situated" precisely because one of them was a former bundled wholesale requirements customer of the utility for whom the utility may have incurred costs to meet reasonably expected customer demand, whereas the other was never a generation customer of the utility and thus appropriately bears no cost responsibility for stranded generation costs incurred by that utility. Indeed, this example illustrates precisely the reason underlying the Commission's stranded cost mechanism. If a utility had previously served a customer as a seller of generation as well as a transmitter, it is allowed an opportunity to show that it incurred costs based on a reasonable expectation of continuing to serve the power needs of that customer beyond the contract term. Similarly, contrary to Central Illinois Light's claim, if different treatment of different customers were to occur, it would not be due to "accidents of circumstance" -- it would be the result of the conscious application by the Commission of its decision to give a utility the opportunity to recover stranded costs from a wholesale requirements customer if the utility can demonstrate that it incurred costs to provide service to the customer based on a reasonable expectation that it would continue to serve the customer after the contract term. In response to the claims of those entities that challenge the factual record for allowing wholesale stranded cost recovery, we believe that the record in this proceeding clearly Docket Nos. RM95-8-001 -219- and RM94-7-002 demonstrates the need to give utilities the opportunity to recover wholesale stranded costs. We have shown that the Rule's open access requirement will significantly alter historical relationships among traditional utilities and their customers. Indeed, that is one of its objectives. In the longer term, we seek to have all power supply arrangements priced by the competitive marketplace. However, utilities prudently incurred costs under a prior regulatory regime that created an expectation of an opportunity for recovery of those costs. Common sense indicates that a utility that historically supplied bundled generation and transmission services to a wholesale requirements customer and that reasonably expected to continue to serve the customer may have incurred costs to provide service to that customer that could be stranded if the customer uses open access transmission to reach a new generation supplier. 502/ As we learned from our experience in restructuring of the natural gas industry, open access and unbundling did in fact exacerbate the take-or-pay problems in the gas industry because it gave customers more options. That is what we are doing in the electric industry as well. As a result, we have concluded that utilities should be permitted to seek recovery of stranded costs in certain limited and defined circumstances. As the AGD court noted: "Agencies do not need to conduct experiments in order to rely on the prediction that an unsupported stone will fall." 824 F.2d at 1008. Docket Nos. RM95-8-001 -220- and RM94-7-002 We disagree with those entities that argue that utilities have not provided sufficient data on the existence of wholesale stranded costs to justify the approach adopted by the Commission in Order No. 888. Presumably these entities would require us to calculate specific stranded cost estimates for every public utility before we could act to address this critical issue. However, where the Commission decides to act by means of a generic rule, 503/ the Commission is not required to make individual findings on a utility-by-utility basis. 504/ Moreover, the Rule does not say that all utilities with wholesale contract customers will be allowed to recover stranded costs, only that those utilities that have requirements contracts that were executed on or before July 11, 1994 that do not contain an exit fee or explicit stranded cost provision and that can meet the required evidentiary showing would be allowed such recovery. On this basis, our decision to give utilities the opportunity to seek stranded cost recovery for certain wholesale requirements contracts is not dependent on a showing that any particular utility will actually be eligible to recover stranded costs as a result of the open access requirement. 505/ As we noted in Order No. 888, there is no question that it is within the Commission's discretion to decide whether to act through rule or through case-by-case adjudication. FERC Stats. & Regs. at 31,679; mimeo at 127-28. See AGD, 824 F.2d at 1008. Indeed, we are somewhat puzzled by the argument that we may not act in the absence of "hard data" that the potential (continued...) Docket Nos. RM95-8-001 -221- and RM94-7-002 We also will reject SC Public Service Authority's request that the Commission deny market-based rate authority for all utilities seeking stranded cost recovery. SC Public Service Authority has failed to demonstrate that the ability to seek stranded cost recovery would, by definition, eliminate the potential for mitigation of any generation or transmission market power. If an entity believes that a utility seeking market-based rate authority does not satisfy the Commission's criteria for the grant of market-rate authority (e.g., because the utility has, or has failed to mitigate, market power in generation or transmission), that entity will have ample opportunity to present its case in the market-based rate proceeding. American Forest & Paper's objection that utilities that voluntarily filed open access tariffs cannot utilize the stranded cost provisions and therefore that only utilities who were forced to offer open access transmission are being rewarded is misplaced. First, there is nothing in Order No. 888 that prohibits a utility that voluntarily filed an open access transmission tariff from seeking recovery of stranded costs if it can demonstrate a reasonable expectation of continuing to serve a (...continued) stranded cost problem is widespread and huge. Here we provide only the opportunity to seek stranded cost recovery for a concededly narrow subset of cases that we believe may give rise to a valid claim for extracontractual recovery. If as petitioners suggest the problem is modest and confined to a small number of utilities, the evidentiary process will sort that out, and the potential effect on departing customers and on the pace of competition will be similarly modest. Docket Nos. RM95-8-001 -222- and RM94-7-002 particular wholesale customer beyond the term of its existing contract. Second, many of the "open access" tariffs accepted prior to Order No. 888, while an improvement upon the status quo of no access, did not contain the minimum terms and conditions of non-discriminatory service, including functional unbundling. Order No. 888 required utilities that tendered for filing open access tariffs prior to the issuance of the Rule (Group 1 public utilities) to make section 206 compliance filings that contain the non-rate terms and conditions set forth in the Open Access Rule pro forma tariff. That tariff expressly includes provisions allowing a transmission provider to seek to recover stranded costs in accordance with the terms, conditions and procedures set forth in Order No. 888. Of the 101 public utilities that had some version of open access available prior to Order No. 888, all now have open access tariffs on file that contain provisions that expressly allow the transmission provider to seek to recover stranded costs as provided in Order No. 888. We also will decline San Francisco's request that the Commission include "exercise of pre-existing contract rights for transmission and designation of wholesale loads" or similar language as an example of a situation for which stranded costs may not be sought. 506/ We are not prepared to make individual In making this determination we do not decide whether such situations demonstrate the presence or lack of a reasonable expectation of continuing to serve a customer after the expiration of an existing wholesale requirements contract (i.e., one that was executed on or before July 11, 1994). Docket Nos. RM95-8-001 -223- and RM94-7-002 factual determinations in the context of this Rule. 507/ As specific requests for stranded cost recovery are presented to the Commission, they will be addressed based on the facts presented and the merits of the particular request. Rehearing Requests Seeking Broader Stranded Cost Recovery In sharp contrast to the entities seeking rehearing of the Commission's decision to allow stranded cost recovery, other entities ask the Commission to expand the scope of the stranded cost recovery allowed by Order No. 888. Various entities ask that the scope of stranded cost recovery be expanded to include situations in which the departing customer does not take unbundled transmission from the former supplier and in which previously existing municipal utilities annex additional territory or otherwise expand. 508/ These entities disagree with the Commission's analysis in Order No. 888 that the opportunity to seek recovery should be precluded in situations in which the departing wholesale customer ceases to purchase power from the utility but does not use the utility's transmission system to reach another supplier. The Commission excluded these situations because the costs would not be stranded as a result of the Commission's open access transmission requirement, but rather as San Francisco will have sufficient opportunity to raise the argument in any PG&E stranded cost recovery case. E.g., EEI, Coalition for Economic Competition, Puget, Centerior, Southern. The issue of expanding the rule to encompass municipal annexations and expansions is discussed in greater detail in Section IV.J.6 below. Docket Nos. RM95-8-001 -224- and RM94-7-002 a result of the exercise of a preexisting competitive option. The entities argue on rehearing that such costs are attributable to the Commission's efforts to restructure the wholesale power market. Several argue that there is no good policy reason for addressing stranded costs only where linked directly to the Open Access Rule or section 211 orders because a variety of federal actions, not just the Open Access Rule and section 211 orders, have created a competitive wholesale power market and the specter of stranded costs caused by customers departing their traditional utility. They contend that, but for the Commission's creation of a vibrant power market, EPAct, and other pre-Order No. 888 efforts by the Commission to expand transmission access, the preexisting options would not have been (and historically were not) exercised. Puget argues that even when a departing customer can import its new power supply without using its former supplier's transmission system, it frequently will be the case that the power supply would not be available to the customer if open access transmission rules were not in place to permit that power to move from distant generators over intervening utilities' transmission facilities. 509/ EEI expresses concern that strict application of the "but for open access" test would create new incentives to evade Puget submits that the potential for customers not taking unbundled transmission services from their former suppliers is particularly acute in the Pacific Northwest due to BPA's ownership of much of the region's transmission facilities. Docket Nos. RM95-8-001 -225- and RM94-7-002 stranded cost recovery. 510/ According to EEI, the Rule would deny recovery for costs stranded pursuant to a voluntarily negotiated transmission service agreement, but would permit recovery if such agreement were ordered pursuant to FPA section 211. In this manner, EEI contends that the Rule will discourage parties from settling transmission disputes. It says that any transmission agreement negotiated under "the threat" of section 211 should be entitled to stranded cost recovery if providing service results in the stranding of legitimate and prudent costs. PSE&G and Carolina P&L express concern that denying stranded cost recovery where the departing customer does not use the former supplier's transmission system will create an artificial incentive to build "contract path" lines designed to thwart stranded cost recovery. They maintain that the existence of alternative transmission paths should not be a bar to stranded cost recovery where the departing customer avails itself of the Commission's Mobile-Sierra finding permitting customers to challenge the terms of their contracts under the just and reasonable standard. They assert that, notwithstanding the NIMO contends that the Commission erred by failing to address the extent to which Order No. 888's exceptions to the general policy of full stranded cost recovery (e.g., no recovery for customer use of new transmission provider or municipal annexations) create an opportunity for customers to avoid payment of part or all of their share of utility stranded costs, will enable customers to take advantage of such opportunities in ways that will reduce rather than enhance overall economic efficiency, and will deprive utilities of a reasonable opportunity to recover their prudently incurred costs or will shift costs unfairly among customers. See also Puget. Docket Nos. RM95-8-001 -226- and RM94-7-002 availability of alternative transmission, the only way that the customer could have availed itself of the Mobile-Sierra finding was as a result of the Commission's Open Access Rule. Several entities contend that the FPA's requirement of just and reasonable rates and the Fifth Amendment's requirement to avoid confiscation require the Commission to address stranded costs that result when a departing customer does not use the former supplier's transmission system or that result from municipal annexation. 511/ According to Puget, the ultimate Constitutional test will be whether Order No. 888 will afford a fair overall return on all prudent utility investments under the Constitutional standards set forth by the Supreme Court. 512/ Coalition for Economic Competition submits that, as was the case in the context of the unbundling of natural gas pipelines, the Commission cannot ignore stranded costs resulting from the unbundling of electric services and should acknowledge its E.g., Puget, Coalition for Economic Competition, NIMO. These parties make a similar argument in the case of stranded costs that result from retail wheeling. See Section IV.J.7 below. Puget cites in support Stone v. Farmers' Loan & Trust Company, 116 U.S. 307, 331 (1886); Federal Power Commission v. Hope Natural Gas Company, 320 U.S. 591, 602 (1944); and Duquesne Light Company v. Barasch, 488 U.S 299, 307-08 (1989). Puget objects that the stranded cost recovery mechanism in Order No. 888 is too narrow and too easy to circumvent; it can be denied for failure to satisfy the reasonable expectation test or based on a finding that costs are not legitimate and verifiable. Puget argues that stranded cost recovery is constitutionally required and that the recovery mechanism must be amended to ensure full recovery of prudently incurred stranded costs, including PURPA contract costs. Docket Nos. RM95-8-001 -227- and RM94-7-002 Constitutional obligations to address the recovery of all stranded costs, including those that result from municipal expansion and those that result when a customer does not obtain transmission services from its former supplier. SC Public Service Authority also asks the Commission to allow the recovery of stranded costs that result from the loss of indirect customers (e.g., customers of wholesale requirements customers). It argues that if such indirect customers can get access to a new source of power through open access tariffs, the requirements of the utility's direct customer will decrease, and the supplying utility will suffer stranded costs. SC Public Service Authority states that because of the nexus between open access and the departure of the indirect customer, utilities that suffer stranded costs in the event of the loss of an indirect customer should have an opportunity to recover those costs under the reasonable expectation standard. A number of entities also ask the Commission to find that open access transmission and stranded cost recovery are necessary to accomplish the remedy ordered by the Commission and thus are not severable. 513/ To this end, they submit that if the Commission's ability to provide for stranded cost recovery is reduced or substantially modified, public utilities should be E.g., EEI, Oklahoma G&E, Nuclear Energy Institute, Southern. Southern requests that the Commission add a section 35.29 to the regulatory text providing: "Sections 35.26 and 35.28 of this part constitute unseverable portions of a unitary action of the Commission." Docket Nos. RM95-8-001 -228- and RM94-7-002 able to withdraw filed tariffs or to file amended tariffs. It is their position that deletion or substantial change of the open access or stranded cost provisions by the Commission or by a court would vitiate the basis on which the Commission premised the Rule. In an effort to ensure that stranded cost recovery procedures do not become a vehicle for lengthy and expensive litigation over whether there is a sufficient nexus to open access, several entities ask the Commission to place on the departing generation customers the burden to demonstrate the absence of a nexus between their actions and the availability of open access transmission under the Rule in those cases where: (i) the contract has no term or termination provision; (ii) the Commission issues an order under section 206 reducing the term of the contract; or (iii) there is legitimate municipalization. 514/ Commission Conclusion We will deny the requests for rehearing that ask us to expand the scope of stranded cost recovery to include situations in which the departing customer does not take unbundled transmission from its former supplier but instead obtains transmission from another utility or obtains power from a third party supplier who is located in the customer's service territory and thus requires no transmission from the former supplier. 515/ E.g., Carolina P&L, PSE&G. We discuss in Section IV.J.6 below our disposition of the (continued...) Docket Nos. RM95-8-001 -229- and RM94-7-002 As the Commission stated in Order No. 888, the premise of the Rule is that where the former requirements supplier had a reasonable expectation of serving beyond the contract term and the customer uses the open access transmission tariff of its former requirements supplier to obtain power from a new generation supplier, the customer must pay the costs that were incurred on its behalf under the prior regulatory regime. The Rule is not intended, however, to apply to the recovery of costs associated with the normal risks of competition, such as self- generation, cogeneration, or loss of load, that do not arise from the new, accelerated availability of non-discriminatory open access transmission. If a customer leaves its utility supplier by exercising options that could have been undertaken prior to mandatory transmission under Order No. 888 or the Energy Policy Act, or that do not rely on access to the former seller's transmission (such as access to another power supplier through (...continued) rehearing requests that support recovery of costs stranded as a result of municipal annexation or expansion. In response to EEI's argument that the Rule would deny recovery for costs stranded pursuant to a voluntarily-negotiated transmission service agreement and would discourage parties from settling transmission disputes, we find EEI's arguments in support of its position to be vague and cursory. However, we do not interpret the Rule in any way as precluding parties from addressing stranded cost issues through settlement, including settlement of a transmission dispute. To the contrary, we fully expect that the renegotiation of contracts, including transmission agreements, would provide parties with a useful means for resolving stranded cost issues without litigation. We believe that a negotiated rate that includes an amount for stranded cost recovery could be found to be just and reasonable. Docket Nos. RM95-8-001 -230- and RM94-7-002 another utility's transmission system or self-generation), there is no direct nexus to Commission-mandated transmission access. For example, if a customer is able to obtain power from a new supplier by using the transmission system of another utility, it is likely that the customer could have made these arrangements in the absence of the new open access rules. The new transmission provider would have had little incentive to deny transmission services to the customer in order to protect another utility's existing power supply arrangement, since it was not the customer's power supplier in the first place. As Order No. 888 suggested, it is likely that the neighboring utility would have a positive incentive to provide the transmission service in order to increase its transmission revenues, and that this incentive is unchanged by open access transmission. 516/ Although EEI and others argue that EPAct and the Commission's pre-Order No. 888 efforts to expand transmission access have facilitated the exercise of pre-existing competitive options, the fact remains that such options historically were available before open access. For this reason, we conclude that costs incurred as a result of the exercise of pre-existing competitive options do not fall within the scope of Order No. 888. A number of entities argue that, even where the departing customer obtains access to another power supplier through the FERC Stats. & Regs. at 31,849-50; mimeo at 624-26. Docket Nos. RM95-8-001 -231- and RM94-7-002 transmission system of another utility (i.e., not that of its former supplier), the power supply would not have been available to the customer if open access transmission rules were not in place to permit that power to move from distant generators over intervening utilities' transmission facilities. Some argue that there is no good policy reason for addressing stranded costs only where linked directly to the Open Access Rule (or to a section 211 order) because a variety of federal actions have created a competitive wholesale power market and the specter of stranded costs caused by customers departing their traditional utility. While these arguments may have superficial appeal, the effective result would be to provide for recovery of stranded costs from departing customers under the Rule no matter how tenuous the nexus to Commission-mandated transmission access. The Commission has to exercise reasonable judgment and reasonable line drawing regarding the link between its actions in this Rule and the decision to allow an opportunity for extra-contractual stranded cost recovery from the departing customer. The Commission believes that requiring a direct nexus between Commission- mandated transmission access (namely, requiring that the departing customer obtain access to another power supplier through the use of its former supplier's Commission-required tariff -- i.e., an open access tariff or a tariff ordered pursuant to section 211) and the special stranded cost recovery procedures of this Rule is the most reasoned and supportable approach because it establishes a clear link between availability Docket Nos. RM95-8-001 -232- and RM94-7-002 of the transmission tariff and the decision of the customer to seek an alternative supplier. With regard to potential stranded costs associated with situations that could have occurred prior to the Open Access Rule and prior to the Energy Policy Act (such as self-generation), under traditional ratemaking such costs (albeit not previously labeled as potential "stranded" costs) would in most cases be reallocated in the next rate case to remaining customers. The fact that this Rule does not permit a utility to seek recovery of these types of costs from the departing customer does not mean that the Commission may not, in appropriate circumstances, permit their recovery through traditional ratemaking means. However, many factors will influence cost recovery in the future, including whether the utility is selling at cost-based or market- based rates and the transitional period to more competitive bulk power markets. The Commission will address these matters on a case-by-case basis. We do not agree with those commenters who contend that the Commission's failure in Order No. 888 to allow for the recovery of costs incurred by a utility when a departing customer does not use the former supplier's transmission system to reach a new supplier would be confiscatory in violation of the Constitution. As the Supreme Court explained in Duquesne, "[t]he guiding principle has been that the Constitution protects utilities from being limited to a charge for their property serving the public Docket Nos. RM95-8-001 -233- and RM94-7-002 which is so 'unjust' as to be confiscatory." 517/ However, Order No. 888 addresses only the recovery of legitimate, prudent and verifiable costs that are stranded if a former wholesale requirements customer or a former retail customer uses a Commission-mandated transmission tariff to reach a new supplier. As discussed above, Order No. 888 does not by its terms bar the recovery of costs that do not result from the use of Commission- required transmission access (i.e., costs that result when a departing customer does not use the former supplying utility's open access tariff). Utilities may, as before, seek recovery of such non-open access-related costs on a case-by-case basis in individual rate proceedings. The Commission will not prejudge those issues here. As a result, the argument that the Commission's treatment of stranded costs in Order No. 888 (i.e., its failure to treat certain costs as costs for which recovery may be sought under the Rule) will result in rates that will be so unjust as to be confiscatory is misplaced. We deny SC Public Service Authority's request that the Commission allow a utility to seek recovery of stranded costs that result from the loss of indirect customers (i.e., the loss of the utility's customer's customers). The Commission does not believe it is appropriate or feasible to allow a public utility (or a transmitting utility under section 211 of the FPA) to seek recovery of stranded costs from an indirect customer (i.e., a 488 U.S. at 307. Docket Nos. RM95-8-001 -234- and RM94-7-002 customer of a wholesale requirements customer of the utility). The reasonable expectation analysis would apply only to the direct wholesale customer of the utility, not to the indirect customer. A utility may seek to recover stranded costs from a direct wholesale customer (subject to the requirements of the Rule), but it is up to the direct wholesale customer, through its contracts with its customers or through the appropriate regulatory authority, to seek to recover stranded costs from its customers. We also deny PSE&G's and Carolina P&L's request that a utility be allowed to seek stranded cost recovery in cases where the departing customer uses the Commission's Mobile-Sierra finding to get out of the contract under the just and reasonable standard and uses alternative suppliers and alternative transmission. 518/ We disagree with their argument that the only way that the customer could have availed itself of a Mobile- Sierra finding was as a result of the Commission's open access rules and thus the necessary nexus is met. A customer to a Mobile-Sierra contract always has the option of instituting a proceeding under section 206 of the FPA and making a showing of why, under Mobile-Sierra, it is in the public interest to modify the contract. These parties appear to refer to a situation in which a customer is able to modify or terminate its contract, but would use the transmission system of a utility other than that of its former supplier in order to reach a new generation supplier. In this circumstance, the Rule would not permit the former supplier to seek stranded costs. Docket Nos. RM95-8-001 -235- and RM94-7-002 We will not, at this time, make any determination whether or not the requirements of open access transmission and stranded cost recovery are severable. As we indicated in Order No. 888, we issued the Stranded Cost Final Rule simultaneously with the Open Access Rule because we believe that the recovery of legitimate, prudent and verifiable stranded costs is critical to the successful transition of the electric industry to a competitive, open access environment. 519/ We believe that our decision to allow stranded cost recovery will be upheld by the courts. Moreover, as we discuss in Section IV.A.1 above, it would be premature to consider at this time what the Commission would do if one or more of the provisions of the Rule are not upheld. Circumstances at the time of any court order would dictate how we should proceed and we would consider all such circumstances, and the entirety of our policy decisions, before determining how to respond to a court decision. Further, we decline to place on departing generation customers the burden of demonstrating that no nexus exists between their actions and the availability of open access transmission under the Rule in cases involving no term or termination provision, an order under section 206 reducing the term of the contract, or municipalization. The proponents of such a proposal, Carolina P&L and PSE&G, attempt to justify it as a means to ensure that stranded cost recovery procedures do not FERC Stats. & Regs. at 31,789-90; mimeo at 454-55. Docket Nos. RM95-8-001 -236- and RM94-7-002 become a vehicle for lengthy and expensive litigation over whether there is a sufficient nexus to open access in the three identified situations. However, Order No. 888 places the burden on the utility seeking stranded cost recovery to demonstrate that the costs for which it seeks recovery fall within the scope of the Rule and that it had a reasonable expectation of continuing service. In this regard, the Rule tracks the requirement of sections 205 and 206 of the FPA that a public utility demonstrate the justness and reasonableness of its proposed rates. Carolina P&L and PSE&G fail to explain why it would be appropriate for customers (as opposed to the utilities seeking recovery) in the three identified situations to bear the initial burden of demonstrating why costs should not be recovered from them under the Rule. 520/ As a result, we reject their proposal. 521/ Rehearing Requests -- Stranded Cost Recovery By Transmitting Utilities That Are Not Public Utilities A number of entities contend that the Commission's decision to limit stranded cost recovery for transmitting utilities that are not public utilities to section 211 proceedings is In addition, the proposal would not eliminate lengthy litigation. It would only change the burden of proof in whatever litigation occurs. We note, however, that in a section 206 proceeding brought by a customer seeking to shorten or terminate a contract, the customer has the burden (as it would in any section 206 case that it initiates) of presenting sufficient evidence that the contract is no longer just and reasonable. As we stated in the Rule, the utility must present any stranded cost claim at that time. See FERC Stats. & Regs. at 31,664, 31,813; mimeo at 86-87, 521-22. Docket Nos. RM95-8-001 -237- and RM94-7-002 inconsistent with its decision to impose the reciprocity requirement on those utilities, violative of the principle of comparability, and unduly discriminatory and anticompetitive. 522/ NRECA submits that if the Commission has the statutory authority to require non-public utilities to render transmission service outside of a section 211 proceeding through the reciprocity, RTG and power pool provisions of the Rule, then it must exercise that authority to ensure stranded cost recovery by such non-public utilities. Noting that the Rule does not address how a non-public utility that chooses voluntarily to provide an open access tariff can recover its stranded costs, SC Public Service Authority asks the Commission to confirm on rehearing that non-jurisdictional utilities can include a provision for recovery of stranded costs in their tariffs provided pursuant to the Final Rule. Commission Conclusion The Commission's jurisdiction over the recovery of stranded costs by non-public utilities, and thus our ability to permit an opportunity for recovery of such costs, is limited by statute. While we have the statutory authority to ensure that non-public utilities have the opportunity to seek recovery of stranded costs in proceedings under sections 211 and 212 of the FPA, 523/ we do E.g., NRECA, TDU Systems, Dairyland Coop. Stranded costs could also conceivably arise as a result of an ordered interconnection under section 210. However, the rates for such an interconnection would be established (continued...) Docket Nos. RM95-8-001 -238- and RM94-7-002 not have such authority under sections 205 and 206 of the FPA. However, we clarify that nothing in the Final Rule was intended to preclude non-public utilities from including stranded cost provisions in voluntary reciprocity tariffs or from otherwise recovering stranded costs under applicable law. We discuss these matters in detail below. As we stated in Order No. 888 in response to commenters' objections that the Rule would give public utilities a greater opportunity than other transmitting utilities to recover stranded costs, our jurisdiction over transmitting utilities that are not also public utilities is limited. If the selling utility is a transmitting utility that is not a public utility, its power sales contracts are not subject to this Commission's jurisdiction under sections 205 and 206 of the FPA. Thus, we can provide such a transmitting utility an opportunity to recover stranded costs only through Commission-jurisdictional transmission rates fixed under sections 211 and 212 of the FPA. 524/ The open access tariff reciprocity provision, which applies to all open access customers that own, operate, or control (...continued) pursuant to section 212 and could therefore also include stranded costs. FERC Stats. & Regs. at 31,791; mimeo at 458. If such a transmitting utility seeks stranded cost recovery in a proceeding under sections 211 and 212, it would, consistent with the provisions of the Rule, be limited to recovery associated with requirements contracts executed on or before July 11, 1994 that do not contain an exit fee or other explicit stranded cost provision. Docket Nos. RM95-8-001 -239- and RM94-7-002 transmission facilities or are affiliates of entities that own, operate or control such facilities, and that do not obtain a waiver of the provision, does not create jurisdiction for the Commission to fix the rates for these utilities. Contrary to the suggestions of some, the tariff reciprocity provision is not based on any statutory authority of the Commission to require non-public utilities to render transmission service outside of a section 211 proceeding. As we make clear in Order No. 888, we do not have authority under sections 205 and 206 of the FPA to require non-public utilities to file tariffs (or rate schedules for that matter) with the Commission. 525/ In permitting a public utility to deny transmission service to any person that requests service under an open access tariff unless that person provides reciprocal non-discriminatory transmission services to the transmission provider, we are not acting under any statutory authority to require non-public utilities to provide transmission access. Rather, out of fairness, we are conditioning the use of open access services by all customers, including non-public utilities, on an agreement to offer comparable transmission services in return to the public utility transmission provider. 526/ We clarify that a non-public utility that chooses voluntarily to offer an open access tariff for purposes of FERC Stats. & Regs. at 31,691; mimeo at 162. FERC Stats. & Regs. at 31,760-62; mimeo at 370-74. Docket Nos. RM95-8-001 -240- and RM94-7-002 demonstrating that it meets the reciprocity provision can include a stranded cost provision in its tariff. However, adjudication of any stranded cost claims under that tariff is not subject to the Commission's jurisdiction. 527/ With the exception of our section 210 interconnection and sections 211-212 transmission rate jurisdiction, we do not have jurisdiction over the rates of non-public utilities. If a non-public utility wishes to recover stranded costs pursuant to a tariff or otherwise, it can seek to do so subject to the review of the appropriate regulatory authority. 528/ Rehearing Requests -- Stranded Cost Recovery for Transmission Dependent Utilities NRECA and TDU Systems challenge the Commission's decision not to guarantee a transmission dependent utility that is not a public utility stranded cost recovery when the transmission dependent utility's customers leave its system by using the open Although the Commission would not determine the rate, including the stranded cost component of the rate, of a non- public utility, we would review a public utility's claim that it is entitled to deny service to a non-public utility because the stranded cost component of the non-public utility's transmission rate is being applied in a way that violates the principle of comparability. We note that in the case of stranded cost claims presented to the Commission by BPA or one of the other PMAs, our review would be limited to that set forth in the applicable statutes and any relevant delegation of authority from the Secretary of Energy. See, e.g., Pacific Northwest Electric Power Planning and Conservation Act, 16 U.S.C.  839-839h (1985) (Northwest Power Act); Department of Energy Delegation Order No. 0204-108, as amended, 48 FR 55,664 (1983), amended, 51 FR 19,744 (1986), amended, 56 FR 41,835 (1991), amended, 58 FR 59,716 (1993) (delegation order relating to Western Area Power Administration). Docket Nos. RM95-8-001 -241- and RM94-7-002 access tariff of another utility. They submit that the ability of transmission dependent utilities to compete with public utility transmission providers in an open access environment would be severely affected by their inability to recover stranded costs on a basis comparable to those transmission providers. They argue that the open access provisions of Order No. 888 will result in the stranding of costs incurred by non-transmission owning, non-public utilities to serve customers that depart to other suppliers. They contend that these customers are already located in close proximity to, and interconnected to, public utilities; thus it is likely that they would use the open access tariffs of these public utilities to obtain their new power supplies. NRECA and TDU Systems argue that this situation should meet the "but for open access" nexus. On this basis, they assert that Order No. 888 is no less the proximate cause of the departure of customers of transmission dependent utilities than it is of the departure of public utility transmission owners' customers. They object that the Commission takes no account of the anticompetitive effects of disregarding costs stranded on transmission dependent utilities' systems as a result of open access. Dairyland Coop asks the Commission to recognize a generation and transmission (G&T) cooperative and its member distribution cooperatives as a single economic unit for purposes of stranded cost recovery (such that conversion of a distribution cooperative's retail customer to a wholesale customer may result Docket Nos. RM95-8-001 -242- and RM94-7-002 in stranded costs for the G&T cooperative). It objects that the Commission implicitly rejected comments to this effect without discussion in Order No. 888. Commission Conclusion We deny the requests for rehearing of our decision not to permit transmission dependent utilities and electric cooperatives to seek stranded cost recovery unless they are public utilities or transmitting utilities that would otherwise qualify under the Rule. With regard to transmission dependent utilities, as we indicated in Order No. 888, the limited opportunity for stranded cost recovery contained in the Rule would not likely apply in the case of transmission dependent utilities, who own little or no transmission and the majority of whom would not be public utilities or transmitting utilities subject to the Commission's jurisdiction. 529/ The opportunity for extra-contractual wholesale stranded cost recovery is allowed only where the departing customers use open access (or section 211 access) on the transmission systems of their former generation suppliers and only for a discrete set of requirements contracts executed on or before July 11, 1994 that do not contain explicit stranded cost provisions (involving the bundled provision of generation and transmission) and retail-turned-wholesale situations for which the utility can demonstrate that it had a reasonable expectation of continuing service. Even though it may be the case that FERC Stats. & Regs. at 31,790; mimeo at 456-57. Docket Nos. RM95-8-001 -243- and RM94-7-002 transmission dependent utilities lose generation customers that are able to use open access tariffs of other utilities to reach new suppliers, there was nothing to keep these other utilities from offering such transmission service before Order No. 888. These other utilities had no economic incentive to deny such service before Order No. 888. Thus, in the scenario posited in the rehearings, the transmission dependent utilities do not meet the fundamental premise of the Rule: that a utility that historically has supplied bundled generation and transmission services to a wholesale requirements customer and incurred costs to meet reasonably expected customer demand should have an opportunity to recover legitimate, prudent and verifiable costs that may be stranded because open access use of the utility's transmission system enables a generation customer to shop for power. 530/ However, this is not to say that a transmission dependent utility that is not a public utility, or other non-public utility entities (such as RUS-financed cooperatives), cannot seek recovery of the cost of any resulting uneconomic assets through their contracts with their customers or through the appropriate regulatory authority. The Commission has no objection to these entities being able to seek such cost recovery through the appropriate regulatory channels. However, because the Commission does not have jurisdiction over these entities (other than FERC Stats. & Regs. at 31,790; mimeo at 456-57. Docket Nos. RM95-8-001 -244- and RM94-7-002 through sections 211 and 212 in the case of non-public utility transmitting utilities), it does not have authority to allow them to recover these costs. 531/ We also deny Dairyland Coop's request that the Commission recognize a G&T cooperative and its member distribution cooperatives as a single economic unit for purposes of stranded cost recovery. If a cooperative obtains its financing through RUS, it is not a public utility subject to our jurisdiction under sections 205 and 206 of the FPA. Although the Commission has no objection to these G&T cooperatives being able to seek cost recovery (including recovery of costs on behalf of their distribution cooperatives) through the appropriate regulatory channels, this Commission does not have authority to allow them to seek recovery of stranded costs unless access is obtained through a section 211 order. 532/ In the case of a G&T cooperative that is a public utility (of which there are just a handful at the present time), such a cooperative would have to have a jurisdictional wholesale Unless these entities own some transmission used in interstate commerce or are engaged in sales for resale, and are not otherwise exempt under FPA section 201(f), they would not be public utilities under sections 205 and 206. Most transmission dependent utilities are not public utilities. A G&T cooperative that is a transmitting utility could seek recovery of stranded costs if it is ordered to provide transmission services that permit its distribution cooperative to reach another supplier and if it had a requirements contract with the distribution cooperative that was executed on or before July 11, 1994. Docket Nos. RM95-8-001 -245- and RM94-7-002 requirements contract with its distribution cooperative in order to be able to seek recovery of stranded costs under the Rule. In the case of a jurisdictional G&T cooperative, the request that the G&T be treated as a single economic unit with the distribution cooperative (such that departure of a distribution cooperative's retail customer would be treated as resulting in stranded costs for the G&T cooperative for which the G&T could seek recovery) is, in effect, a request for recovery of stranded costs from an indirect customer. As we discuss above, the Commission does not believe it is appropriate or feasible to allow a public utility (or a transmitting utility under section 211 of the FPA) to seek recovery of stranded costs from an indirect customer (i.e., a customer of a wholesale requirements customer of the utility) under this Rule. The reasonable expectation analysis would apply only to the direct wholesale customer of the utility, not to the indirect customer. It is up to the direct wholesale customer of the utility, through its contracts with its customers or through the appropriate regulatory authority, to seek to recover such costs from its customers. Commenters have provided no basis for making an exception in the case of cooperatives. Moreover, to treat a G&T cooperative and its member distribution cooperatives as a single economic unit for stranded cost purposes would be inconsistent with the Commission's decision not to treat cooperatives as a single unit for purposes of Order No. 888's reciprocity provision. Docket Nos. RM95-8-001 -246- and RM94-7-002 In Order No. 888, in response to arguments raised by cooperatives, the Commission agreed to limit the reciprocity requirement to corporate affiliates. In other words, if a G&T cooperative seeks open access transmission service from the transmission provider, only the G&T cooperative (not its member distribution cooperatives) would be required to offer transmission service. If a member distribution cooperative itself receives transmission service from the transmission provider, then it (but not its G&T cooperative) must offer reciprocal transmission service over its interstate transmission facilities, if any. 533/ Dairyland has provided no basis to support treating cooperatives differently for stranded cost purposes and reciprocity purposes. We accordingly will deny Dairyland's request for rehearing on this issue. Rehearing Requests Opposing Limitation of Recovery to Wholesale Requirements Customers PA Munis argues that it is inequitable and anticompetitive for "wholesale requirements customers" but not other "wholesale customers" to have to pay stranded costs, repeating an argument that it made in its comments on the supplemental stranded cost NOPR. It says that there is no difference in the firm power provided by public utilities to "wholesale requirements customers" and to "wholesale customers" and no difference in the generating facilities required and the costs of operation between the production of firm capacity and energy required for FERC Stats. & Regs. at 31,763; mimeo at 377-78. Docket Nos. RM95-8-001 -247- and RM94-7-002 "wholesale requirements sales" and "wholesale sales." PA Munis submits that the total amount of wholesale requirements power purchased in the United States is less than two percent of the total amount of firm power sales. It argues that requiring only wholesale requirements customers to pay stranded costs would restrict the ability of such customers to switch suppliers while not similarly restricting large firm wholesale customers. It contends that wholesale firm requirements customers therefore will not have equal access under the Rule because of the increased transmission rates for stranded costs that would not be levied on other large wholesale firm customers. Pa Munis says this produces the same result found unlawful in the Maryland People's Counsel case 534/ -- equal access to all wholesale customers is virtually denied by the chilling effect of stranded costs borne only by wholesale requirements customers. Commission Conclusion In Order No. 888, the Commission fully addressed the concerns of PA Munis. We again address below the major distinctions between requirements and other customers and deny rehearing. In Order No. 888, we explained that the historical and practical relationship between a utility and its wholesale requirements customers, including the expectation of continued Maryland People's Counsel v. FERC, 761 F.2d 780 (D.C. Cir. 1985) (Maryland People's Counsel I). See also Maryland People's Counsel v. FERC, 761 F.2d 768 (D.C. Cir. 1985) (Maryland People's Counsel II). Docket Nos. RM95-8-001 -248- and RM94-7-002 service, justifies allowing public utilities the opportunity to seek to recover the stranded costs covered by this Rule from only those customers and not from non-requirements customers that contract separately for transmission services to deliver their purchased power or from wholesale customers that purchase non- requirements power. Requirements customers historically were long-term customers who by definition depended upon their local suppliers because they were captive customers. Utilities had no obligation to provide transmission service that would allow these customers to reach other suppliers, and there were no other transmission facilities in proximity to those of the supplying utility. And the service involved requirements power; that is, these customers were dependent upon the wholesale supplier for all or part of their power. Utilities thus assumed they would continue serving these customers and may have made significant investments based on that long-term expectation. These same assumptions cannot be made for short-term, non-firm transactions and other wholesale non-requirements firm transactions. Unlike requirements customers, these customers had other options. Thus, the supplying utility could not assume that these customers would remain on its system. With regard to short-term transactions, utilities did not (and do not today) generally make investments for short-term economy-type transactions. Rather, such transactions were entered into only when the utility temporarily had available capacity or energy that could be provided to the buyer at a price Docket Nos. RM95-8-001 -249- and RM94-7-002 higher than the seller's incremental cost and lower than the buyer's decremental cost. The utility was not obligated in any way -- either explicitly or implicitly -- to provide for the needs of coordination customers. Because coordination transactions were not the cause of stranded investment decisions, it would be inappropriate to allocate such costs to non- requirements customers. 535/ With regard to long-term, non-requirements firm transactions, such as unit power sales contracts, we note that there was no implied obligation to serve customers to these transactions as there was for requirements customers. Generating units were not built for the purpose of entering into these arrangements. Therefore, because utilities did not incur costs on behalf of non-requirements firm power sales customers, such customers have not caused costs to be stranded and should not be required to pay stranded cost charges. Accordingly, we reaffirm limiting the opportunity for stranded cost recovery to costs associated with wholesale requirements contracts. 536/ FERC Stats. & Regs. at 31,790-91; mimeo at 457-58. We clarify, however, that a contract may meet our definition of wholesale requirements contract even though it does not carry the label "requirements contract." The definition refers to a contract that provides any portion of a customer's bundled wholesale power requirements. As discussed above, whether or not a contract meets this definition hinges upon whether the customer depended upon the wholesale supplier for all or part of its power because it could not obtain transmission access to reach other suppliers, i.e., it was captive to the historical local supplier. Docket Nos. RM95-8-001 -250- and RM94-7-002 We recognize PA Munis' concern that if a utility meets the evidentiary requirements of the Rule and is allowed to recover stranded costs from wholesale requirements customers, such customers may see little or no savings in the short-term by switching power suppliers, since a stranded cost charge (in the form of either an exit fee or a surcharge on transmission) would be paid in addition to the power price paid a new supplier. However, as we discuss above and in Section IV.J.2 below, we believe that stranded costs are transition costs that must be addressed at an early stage if we are to fulfill our regulatory responsibilities in moving to competitive markets. Further, as we explain in Section IV.J.3 below, although spreading the costs to all transmission users of a utility's system (rather than imposing them directly on the departing wholesale requirements customer) might enable the customer to see earlier power cost savings than would result if stranded costs were directly assigned to the customer, we have concluded that this potential benefit to a broad-based approach is outweighed by a significant countervailing disadvantage -- namely, the violation of the cost- causation principle of ratemaking. The Commission rejects a broad-based approach for the electric industry primarily because the potential power cost savings to the departing generation customer would be realized only by shifting costs that are directly attributable to the departing generation customer to the other users of the utility's transmission system. Docket Nos. RM95-8-001 -251- and RM94-7-002 Contrary to PA Munis's claim, we believe that the circumstances surrounding the opportunity to seek stranded cost recovery from wholesale requirements customers that is permitted in Order No. 888 are distinguishable from the issues that were before the court in the Maryland People's Counsel cases. Those cases involved challenges to Commission orders that permitted pipelines to transport gas at lowered prices to "non-captive consumers" (large industrial end users capable of switching to alternative fuels) without any obligation to provide the same service to "captive consumers" such as local distribution companies and their residential customers. In Maryland People's Counsel I, the court invalidated the Commission's authorization of a "special marketing program" under which a pipeline and its producer would agree to amend their high-priced gas purchase contract to permit the producer to sell the committed gas elsewhere at market prices and to credit the volume of such sales against the pipeline's high-priced purchase obligations. Eligibility to purchase the cheaper released gas was limited to industrial users. The court found that the Commission had failed to provide a reasonable basis for its decision to exclude "captive customers" from eligibility to purchase the cheaper released gas. 537/ In Maryland People's Counsel II, the court invalidated the Commission's approval of blanket authority for interstate transportation of natural gas sold directly by See 761 F.2d 768. Docket Nos. RM95-8-001 -252- and RM94-7-002 producers to fuel-switchable end users. The court held that the Commission had failed to consider the anticompetitive effects of failing to require the pipelines to provide the same service to captive consumers on nondiscriminatory terms. 538/ In contrast to the Maryland People's Counsel cases, the Commission in Order No. 888 is not discounting services for one class of customers to the exclusion of another, nor is it ordering that public utilities provide transmission access to only a specified customer group. To the contrary, Order No. 888 requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to provide open access transmission to any "eligible customer," with "eligible customer" defined broadly to include "any electric utility (including the Transmission Provider and any power marketer), Federal power marketing agency, or any person generating electric energy for sale for resale." 539/ Among other things, Order No. 888 gives wholesale requirements customers that previously were captive customers of their public utility suppliers the opportunity at the expiration of their contracts to take unbundled transmission service from their former suppliers in order to reach new suppliers. At the same time, the Commission recognizes that the departure of a wholesale requirements customer in this circumstance may strand costs that See 761 F.2d at 781-82. Pro Forma Open Access Transmission Tariff, section 1.11. Docket Nos. RM95-8-001 -253- and RM94-7-002 the former supplying utility incurred based on a reasonable expectation that it would continue to serve the customer beyond the contract term. As a result, Order No. 888 gives the former supplying utility the opportunity to seek recovery of costs stranded by the wholesale requirements customer's departure. In further contrast to the Maryland People's Counsel cases, the Commission addresses in this Order (above) PA Munis' claim that it is inequitable and anticompetitive that only wholesale requirements customers and not other wholesale customers are subject to the stranded cost provisions of Order No. 888. The Commission has explained in detail the rationale for its decision that public utilities should be allowed an opportunity to seek to recover the stranded costs covered by this Rule only from wholesale requirements customers. The Commission has also addressed in Section IV.J.2 below the concerns expressed by some as to the potential anticompetitive effect of stranded cost charges. Rehearing Request -- ERCOT Docket Nos. RM95-8-001 -254- and RM94-7-002 The TX Com 540/ asks the Commission to clarify that ERCOT utilities may not use a section 211 proceeding as a vehicle to obtain wholesale or retail stranded cost recovery. 541/ It notes that based on the definitions in section 35.26 of "wholesale stranded cost" 542/ and "wholesale transmission service," 543/ TX Com's request for rehearing was filed out-of-time on May 29, 1996 with a request that the Commission accept the rehearing request for filing as of May 24, 1996. TX Com explains it had made arrangements with a courier company to pick up its rehearing request on May 23, 1996 and deliver and file the rehearing request with the Commission before 5 p.m. on May 24, 1996. TX Com states that the courier company failed to pick up the rehearing request on May 23 as previously arranged. TX Com says that when it became aware on May 24 that its rehearing request was not enroute to the Commission, it faxed a copy of the rehearing request to a copier and delivery service in Washington, D.C. The pleading, which was not signed, was delivered to the Commission prior to 5 p.m. on May 24. TX Com states that Commission personnel rejected the filing apparently because it was not signed. TX Com asks that the Commission find good cause under Rule 2001 of the Commission's Rules of Practice and Procedures, 18 CFR 385.2001 (1996), to accept its rehearing request for filing as of May 24, 1996. Under the circumstances, we will accept the rehearing request for filing as of May 24, 1996. Texas Utilities Electric Company filed on June 21, 1996 a motion for leave to file and response to TX Com's rehearing request. Texas Utilities opposes TX Com's positions on rehearing. While answers to requests for rehearing generally are not permitted, 18 CFR 385.213(a)(2) (1996), we will depart from our general rule because of the significant nature of this proceeding and will accept Texas Utilities' response. "Wholesale stranded cost" is defined as "any legitimate, prudent and verifiable cost incurred by a public utility or a transmitting utility to provide service to: (1) a wholesale requirements customer that subsequently becomes, in whole or in part, an unbundled wholesale transmission services customer of such public utility or transmitting utility; or (ii) a retail customer, or a newly created wholesale power sales customer, that subsequently becomes, (continued...) Docket Nos. RM95-8-001 -255- and RM94-7-002 the Rule applies only to interstate service and does not apply to the intrastate service provided by the utilities within ERCOT, yet the Commission suggests that it might permit a utility in ERCOT to recover stranded costs in a section 211 proceeding. Even if the Commission concludes that it has the authority to resolve stranded cost issues for ERCOT utilities, TX Com asks the Commission to establish a preference for resolution of transmission and stranded cost issues in ERCOT by TX Com. It suggests that uncertainty and gaming as to the choice of a forum could be avoided by executing a Memorandum of Understanding between TX Com and the Commission that would require interested persons to submit disputes to TX Com. Further, to the extent that the new ERCOT transmission access rules adopted by the TX Com may be deemed as the cause of stranded costs in ERCOT, TX Com asserts that it should be allowed to resolve issues related to such stranded costs. Commission Conclusion In City of College Station, Texas, 544/ the Commission repeated its view, first articulated in 1979, that sections 211 (...continued) in whole or in part, an unbundled wholesale transmission services customer of such public utility or transmitting utility." Order No. 888, mimeo at 768. "Wholesale transmission services" is defined as "ha[ving] the same meaning as provided in section 3(24) of the Federal Power Act (FPA): the transmission of electric energy sold, or to be sold, at wholesale in interstate commerce." Order No. 888, mimeo at 768. 76 FERC  61,138 (1996). Docket Nos. RM95-8-001 -256- and RM94-7-002 and 212 of the FPA clearly give the Commission jurisdiction to order transmission services within ERCOT, subject to the special rate provision for ERCOT utilities in section 212(k). 545/ The Commission indicated that if it issues a final order in that case setting rates for transmission services within ERCOT, it will comply with section 212(k) and give deference to the TX Com's ratemaking methodology insofar as practicable and consistent with section 212(a). Our jurisdiction to order transmission services within ERCOT includes the authority to address costs that are stranded by a section 211 transmission order. 546/ Consistent with the special rate provision in section 212(k), we clarify that we will give deference to the TX Com's ratemaking methodology, including any Section 212(k), added by EPAct, provides as follows: (1) RATES. - Any order under section 211 requiring provision of transmission services in whole or in part within ERCOT shall provide that any ERCOT utility which is not a public utility and the transmission facilities of which are actually used for such transmission service is entitled to receive compensation based, insofar as practicable and consistent with subsection (a), on the transmission ratemaking methodology of the Public Utility Commission of Texas. 16 U.S.C.  824k(k) (1994). To clarify that the Order No. 888 stranded cost provisions apply to the intrastate utilities within ERCOT, solely in the context of a section 211 proceeding, we will revise the definition of "wholesale transmission services" in section 35.26(b)(3) to read: "Wholesale transmission services means the transmission of electric energy sold, or to be sold, at wholesale in interstate commerce or ordered pursuant to section 211 of the Federal Power Act (FPA)." Docket Nos. RM95-8-001 -257- and RM94-7-002 provisions or procedures related to stranded cost recovery, insofar as it is practicable and consistent with section 212(a) and consistent with the principle of comparability set out in Order No. 888. 2. Cajun Electric Power Cooperative, Inc. v. FERC 547/ In Order No. 888, the Commission explained why it does not interpret the Cajun court decision as barring the recovery of stranded costs and why the record developed in this generic proceeding fully addresses the court's concerns regarding meaningful access to alternative suppliers. 548/ We also addressed the court's concern that the method of recovery in that case (a charge in the departing customer's transmission rate) might constitute an anticompetitive tying arrangement. We explained that the stranded cost recovery procedure we prescribe in the Open Access Rule is only a transitional mechanism that is intended to enable utilities to recover costs prudently incurred under a different regulatory regime. The purpose and effect of the stranded cost recovery mechanism that we approved in the Rule is to facilitate the transition to competitive wholesale power markets. We concluded that while stranded cost recovery may temporarily delay some of the benefits of competitive bulk power markets for some customers, such transition costs must be addressed at an early 28 F.3d 173 (D.C. Cir. 1994) (Cajun). FERC Stats. & Regs. at 31,793-95; mimeo at 464-70. Docket Nos. RM95-8-001 -258- and RM94-7-002 stage if we are to fulfill our regulatory responsibilities in moving to competitive markets. In reaching these conclusions, the Commission applied the traditional regulatory concept of cost causation. We stated that it is not an illegal tying arrangement to hold a customer accountable for the cost consequence of leaving an incumbent supplier if, under our rules, the incumbent supplier must show a reasonable expectation of providing continuing service to that customer before it can recover stranded costs from the customer. In addition, in response to the Cajun court and commenters in this proceeding as to the need to provide as much certainty as possible for departing customers concerning their potential stranded cost obligation, the Commission included a formula for calculating a departing customer's potential stranded cost obligation. We explained that the revenues lost formula is designed to provide certainty for departing customers and to create incentives for the parties to address stranded cost claims between themselves without resort to litigation. Rehearing Requests Arguing that the Commission Has Not Resolved the Cajun Court's Concerns Several entities submit that the Commission has not resolved the Cajun court's tying concerns. They argue that tying arrangements are still the essence of the stranded cost recovery method mandated by Order No. 888, and that a tying arrangement is a per se antitrust violation that is not subject to justification by reference to the reasons for the restraint or the expected Docket Nos. RM95-8-001 -259- and RM94-7-002 ancillary benefits. 549/ A number of these entities object that the Commission does not address the court's substantive concern that a stranded cost provision is the antithesis of competition. 550/ Several object that the Commission brushes aside the acknowledged anticompetitive effects of the rule as being "transitional only," suggesting that short-term anticompetitive impacts are acceptable as long as the Commission is doing something that will be good for customers in the long term. 551/ They also contend that the anticompetitive effects would not be limited to a transitional period, or that the transitional period could last indefinitely, thereby diluting or even nullifying the benefits of competition for years to come. 552/ Several entities submit that the Commission erred in concluding that the stranded cost rules contained in Order No. 888 would allow customers "meaningful" access to alternative power suppliers. 553/ Among other things, these entities contend that there is no showing in the Order that transmission providers will not continue to exercise monopoly power over their See, e.g., ELCON, Suffolk County, Central Illinois Light, American Forest & Paper, TDU Systems, Blue Ridge, Nucor, IN Consumer Counselor, IN Consumers, APPA, PA Munis, VT DPS, Valero. E.g., Central Illinois Light, American Forest & Paper. E.g., American Forest & Paper, PA Munis. E.g., American Forest & Paper, Occidental Chemical, Pa Munis. E.g., Arkansas Cities, IN Consumer Counselor, IN Consumers, Occidental Chemical, PA Munis. Docket Nos. RM95-8-001 -260- and RM94-7-002 transmission systems and that competition in generation will not be stifled by the stranded cost recovery mechanism. Some entities also object that the stranded cost procedures contained in Order No. 888 fail to provide certainty in the computation of recoverable stranded costs. They argue that the prospect of stranded cost liability and related litigation add costs of potential deal-killing magnitude to any power supply acquisition considered by a customer. 554/ APPA and ELCON challenge the Commission's description of Western Resources, Inc. v. FERC 555/ as affirming the Commission's ability to allow stranded cost recovery. APPA argues that Western Resources does not justify the stranded cost provisions of Order No. 888 because it was a filed rate doctrine case, not a stranded cost case. APPA says that Western Resources involved no consideration of any allegation of anticompetitive conduct and no allegation that the utilities' proposal constituted an illegal tying arrangement. Commission Conclusion We will deny the requests for rehearing advanced on the basis of the Cajun case. We disagree with those entities that contend that the Commission has not resolved the Cajun court's tying concerns. As an initial matter, we note that the parties that have raised this issue on rehearing ignore the fact that E.g., APPA, Arkansas Cities. 72 F.3d 147 (D.C. Cir. 1995) (Western Resources). Docket Nos. RM95-8-001 -261- and RM94-7-002 while this Commission has a responsibility to consider the anticompetitive effects of regulated aspects of interstate utility operations, 556/ it has other statutory and regulatory public interest considerations which it must balance in order to engage in reasoned decisionmaking. In this proceeding, we have carefully balanced our responsibilities to remedy undue discrimination and to consider anticompetitive effects, our goal to eliminate market power of utilities and anticompetitive effects in the long-run, and the need to provide a transition to competitive markets that is fair, that maintains a stable electric utility industry, and that recognizes the obligations incurred in a past, non-competitive regulatory regime. As discussed below, we do not believe that the stranded cost proposal adopted in the Rule results in an illegal tying arrangement, as argued on rehearing. We believe we have given reasoned consideration to any potential transitory anticompetitive effects of our stranded cost policy and that we have met the directives of the court in Cajun. The Commission's power under the FPA carries with it the responsibility to consider, in appropriate circumstances, the anticompetitive effects of regulated aspects of interstate operations pursuant to sections 202 and 203, and under like directives contained in sections 205, 206, and 207. Gulf States Utilities Company v. FPC, 411 U.S. 747 (1973). While the Commission lacks principal responsibility for implementing antitrust policy, it retains an obligation to give reasoned consideration to the bearing of antitrust policy on matters within its jurisdiction. Alabama Power Company, et al. v. FPC, 511 F.2d 383 (D.C. Cir. 1974). Docket Nos. RM95-8-001 -262- and RM94-7-002 In considering the Cajun decision, it is important to note that the Cajun court assumes the presence of a competitive market in the electric utility industry, but such a competitive market does not now exist. Instead, the Commission is in the process of trying to bring about a competitive market and to manage the transition thereto. 557/ When the Commission undertook a similar restructuring in the gas industry, the D.C. Circuit invalidated the Commission's efforts precisely because the Commission had failed to deal with the stranded cost problem in a satisfactory manner. 558/ As we indicated in Order No. 888, we do not believe it is an illegal tying arrangement to hold a customer accountable for the consequences of leaving an incumbent supplier if, before the incumbent supplier can recover legitimate, prudent and verifiable stranded costs from the departing customer, it must show that it incurred costs to provide service to the customer based on a reasonable expectation of continuing to serve the customer. Order No. 888 provides no guarantee of stranded cost recovery. Moreover, Order No. 888 provides the opportunity to recover stranded costs only for a discrete set of wholesale requirements contracts -- those executed on or before July 11, 1994 that do In contrast to the situation in Order No. 888, the Cajun court did not have before it a generic, Commission-imposed recovery mechanism for distinguishing stranded costs associated with the Commission's ordering of industry-wide open access from all uneconomic costs. See AGD, 824 F.2d at 1021. Docket Nos. RM95-8-001 -263- and RM94-7-002 not contain an exit fee or other explicit stranded cost provision -- and for retail-turned-wholesale customers. Thus, it is not necessarily the case that customers will have to pay stranded costs when they leave their current suppliers. To the contrary, before a utility can recover stranded costs from a customer, the utility must overcome certain evidentiary hurdles (including a rebuttable presumption of no reasonable expectation of continuing service if the contract contains a notice of termination provision). Particularly given the narrowly tailored circumstances under which stranded cost recovery is permissible under the Rule, we do not view it as the antithesis of competition. We dismiss as misplaced the claims that Order No. 888's stranded cost recovery mechanism is a tying arrangement that is a per se antitrust violation that cannot be justified by reference to the reasons for the restraint or the expected ancillary benefits. Any "tying" that might result from the Rule is by regulatory order, not through monopoly power, and is justified as a means to avoid unfair cost shifting and to achieve the pro- competitive benefits of the Rule. As we stated in Order No. 888, the purpose and effect of the stranded cost recovery mechanism that we approve are to facilitate the transition to competitive wholesale power markets, not to prevent a generation customer of Docket Nos. RM95-8-001 -264- and RM94-7-002 a utility from being able to reach alternative suppliers through its former supplier's transmission. 559/ To be sure, imposing a stranded cost charge might, in the short run, make some customers indifferent to whether they stay with their current suppliers and avoid stranded costs, or go with new suppliers but pay stranded costs to the former suppliers. 560/ There is no question that, without the stranded cost recovery mechanism, some customers would be far more likely to switch to lower-cost suppliers and enjoy sooner the benefits of a competitive power market. But, as detailed in Order No. 888, such an approach may result in higher costs for other customers. We thus have had to balance the potential for earlier benefits for some customers against other public interest considerations, most particularly the need to provide a fair mechanism by which utilities can recover the costs of past investments under Cf. Eastman Kodak Company v. Image Technical Services, Inc., 504 U.S. at 486-87 (Scalia, J. dissenting) ("Per se rules of antitrust illegality are reserved for those situations where logic and experience show that the risk of injury to competition from the defendant's behavior is so pronounced that it is needless and wasteful to conduct the usual judicial inquiry into the balance between the behavior's procompetitive benefits and its anticompetitive costs."). In effect, we recognize that we may have to endure some short-term delay in the transition from monopoly suppliers to competitive suppliers. However, this is not anticompetitive; it is a necessary part of a scheme that is procompetitive overall. See American Gas Association v. FERC, 888 F.2d 136, 149 (D.C. Cir. 1989) ("If conditioning access is a necessary part of a scheme that is procompetitive overall, however, then it does not violate the NGPA [Natural Gas Policy Act] even if it may seem to be anticompetitive when viewed in isolation."). Docket Nos. RM95-8-001 -265- and RM94-7-002 traditional regulatory concepts of prudently incurred costs and cost causation. The result is not to deny competitive advantages, but only to delay their full realization for some customers. In any event, we do not believe that the Commission-imposed mechanism of allowing the utility to recover stranded costs from the departing customer through its transmission rates falls within the category of an illegal tying arrangement under the antitrust laws. As the Supreme Court has defined it, "[a] tying arrangement is 'an agreement by a party to sell one product but only on the condition that the buyer also purchases a different (or tied) product, or at least agrees that he will not purchase that product from any other supplier.'" 561/ Here there is no "tying" of "products." 562/ Instead, the Rule provides a mechanism for recovering costs associated with a prior contract. We have not adopted a rule under which a customer may purchase transmission from a utility only on the condition that the customer also purchases a different product, namely, power, from the utility. 563/ To the contrary, the Eastman Kodak Company v. Image Technical Services, 504 U.S. 451, 461 (1992). A "service" can constitute a "product" for purposes of a tying analysis. See Eastman Kodak Company v. Image Technical Services, Inc., 504 U.S. at 462. The Rule requires all transmission customers to purchase at least some reactive supply and voltage control service from the transmission provider. However, the Commission found that the cost of such services is "part of the cost of basic (continued...) Docket Nos. RM95-8-001 -266- and RM94-7-002 Commission, through the Order No. 888 open access transmission requirement, is attempting to provide the customer with the opportunity to obtain unbundled transmission from a former supplying utility as a means to reach a new generation supplier. Whatever else, the stranded costs are not charges for "products" and thus there is no "tying" in the conventional sense. At best, there is only a condition: in obtaining unbundled transmission, the customer must also pay appropriate costs stranded by its use of Commission-required transmission access. Finally, it is not clear how often departing customers will be obligated to pay stranded costs. Stranded cost recovery is by no means guaranteed under the Rule, nor is it clear what portion of a utility's uneconomic investment will be recoverable as stranded costs. Even when a utility is able to meet the evidentiary standard and the Commission approves imposition of a stranded cost charge, the customer is free to pay off its obligation immediately. If it chooses to pay off the stranded cost obligation over time, that charge would not be imposed indefinitely on the customer. We have limited the scope of contracts and costs for which utilities may seek stranded cost recovery. This limitation -- to certain contracts and demonstrated costs -- in our judgment fairly allocates between (...continued) transmission service." FERC Stats. & Regs. at 31,706; mimeo at 209. That is, it is a necessary part of providing the service and thus, by definition, not a "tying." Docket Nos. RM95-8-001 -267- and RM94-7-002 utility and customer the burdens and benefits of open access transmission. Nor is it true that the Rule does not allow customers "meaningful" access to alternative power suppliers. The Final Rule pro forma tariff contains terms and conditions ensuring the provision of non-discriminatory transmission service. The requirements that a public utility take service under its own tariff for wholesale sales and purchases, adopt a non- discriminatory transmission information network, and separate power marketing and transmission functions further ensure non- discrimination and remove constraints to fair competition. The result is meaningful access to alternative suppliers that goes far beyond what was offered in the transmission tariff under review in Cajun. Contrary to the claims of some, the Open Access Rule does not guarantee that a utility may sell its power at market-based rates. The open access compliance tariff required by Order No. 888 does mitigate transmission market power. 564/ However, the Commission's Rule does not generically grant market-based rate authority to utilities that file compliance tariffs. Utilities must still demonstrate on a case-by-case basis that they not only Such tariff is a condition, but not the sole condition, for market-based rates. See, e.g., Delmarva Power & Light Company, et al., 76 FERC  61,331 (1996); accord Southern Company Services, Inc., 71 FERC  61,392 at 62,536 (1995); Heartland Energy Services, Inc., et el., 68 FERC  61,223 at 62,059-60 (1994). Docket Nos. RM95-8-001 -268- and RM94-7-002 have mitigated transmission market power but also do not have market power in generation 565/ or other barriers to entry. Notwithstanding the objections by some commenters that the stranded cost procedures of Order No. 888 fail to provide certainty in the computation of stranded cost charges, we believe that directly assigning stranded costs to departing generation customers using the revenues lost formula is the fairest and most efficient way to balance the competing interests of those involved. The alternatives that we considered (an up-front broad-based approach or an as-realized broad-based approach) have significant disadvantages and are extensively discussed in Order No. 888. 566/ Following a careful evaluation of the alternatives, we concluded that a revenues lost formula to calculate a customer's stranded cost obligation is more reasonable and provides greater certainty than would other approaches, such as those that rely on broad-based surcharge schemes that impose costs that may never be incurred or those A seller requesting market-based rates is not required to demonstrate any lack of generation market power with respect to sales from capacity for which construction commenced on or after the effective date (July 9, 1996) of the Rule. 18 CFR 35.27(a). However, if specific evidence is presented by an intervenor that a seller requesting market-based rates for sales from new generating capacity nevertheless has generation dominance, the Commission will evaluate whether the seller has generation dominance with respect to the new capacity. FERC Stats. & Regs. at 31,657; mimeo at 65-66. See FERC Stats. & Regs. at 31,797-800; mimeo at 477-85. Docket Nos. RM95-8-001 -269- and RM94-7-002 that result in widely fluctuating transmission rates. 567/ As we stated in Order No. 888, while we recognize that some commenters oppose the revenues lost approach as imprecise, any ratemaking method that relies on estimates will be subject to forecasting error. 568/ Nevertheless, we have gone to great lengths to provide specificity with respect to the calculation of the components of the formula. In response to those commenters that argue that Order No. 888's stranded cost procedures will add costs of potential deal- killing magnitude to any power supply acquisition considered by a customer, we believe that, to the contrary, use of the formula will narrow the scope of disputes over the calculation of stranded costs, lend precision to the stranded cost amount it produces, and provide certainty to departing generation customers with respect to their stranded cost obligations. APPA and ELCON object to the Commission's reference to Western Resources as a case affirming the Commission's ability to allow stranded cost recovery. Notwithstanding their efforts to Under the revenues lost approach, a customer's stranded cost obligation is calculated by subtracting the competitive market value of the power the customer would have purchased (on an average annual basis) from the average annual revenues that the customer would have paid had it remained on the utility's generation system, and multiplying the result by the period of time the utility reasonably could have expected to serve the customer beyond the contract termination but for the open access required under Order No. 888. See FERC Stats. & Regs. at 31,839-45 for a detailed explanation of the various components of the formula. FERC Stats. & Regs. at 31,841; mimeo at 600-01. Docket Nos. RM95-8-001 -270- and RM94-7-002 distinguish Western Resources (for example, as a filed rate doctrine case, not a stranded cost case, and as a case involving no allegation of anticompetitive conduct), they have failed to make a convincing argument that our description of that case as "confirm[ing] the validity of Commission-imposed stranded cost recovery mechanisms in the transition to competitive markets" 569/ is not accurate. The case depends upon the validity of the Commission's decision to allow the recovery of costs stranded in the transition of the natural gas industry to a competitive market and supports the Commission's ability to allow stranded cost recovery in general. The same court, in United Distribution Companies, has recently confirmed the Commission's ability to allow the recovery of costs stranded in the transition to competitive markets, limiting its concerns to issues about "how" stranded costs should be recovered and from whom. 570/ 3. Responsibility for Wholesale Stranded Costs (Whether to Adopt Direct Assignment to Departing Customers) In Order No. 888, the Commission concluded that direct assignment of stranded costs to the departing wholesale generation customer through either an exit fee 571/ or a FERC Stats. & Regs. at 31,793; mimeo at 464-65. 88 F.3d at 1129, 1182-83. We defined "exit fee" as the charge that will be payable by a departing generation customer upon the termination of its requirements contract with a utility (if the utility is able to demonstrate that it reasonably expected to continue serving the customer beyond the term of the contract), (continued...) Docket Nos. RM95-8-001 -271- and RM94-7-002 surcharge on transmission is the appropriate method for recovery of such costs. We concluded that the departing generation customer (and not the remaining generation or transmission customers or shareholders) should bear the legitimate and prudent obligations that the utility undertook on that customer's behalf. In reaching this decision, we carefully weighed the arguments supporting direct assignment of stranded costs against those supporting the broad-based approach of spreading stranded costs to all transmission users of a utility's system. After a detailed review of the advantages and disadvantages of each approach, we concluded that, on balance, direct assignment is the preferable approach for both legal and policy reasons. 572/ Our primary considerations were that direct assignment is consistent with the well-established principle that the one who has caused a cost to be incurred should pay that cost and that it will result in a more accurate determination of a utility's stranded costs than would an up-front, broad-based transmission surcharge. The Commission also acknowledged that the direct assignment approach adopted in Order No. 888 is different from the approach taken for the natural gas industry. We explained why we believe that difference to be justified by pointing out a number of differences between the transition of the electric industry to an (...continued) whether payable in a lump-sum payment or an amortization of a lump-sum payment. (The same charge also can be paid as a surcharge on the customer's transmission rate.) FERC Stats. & Regs. at 31,797-800; mimeo at 477-85. Docket Nos. RM95-8-001 -272- and RM94-7-002 open transmission access, competitive industry and the transition of the natural gas industry to open access transportation service by interstate natural gas pipelines. 573/ We also declined to require a utility seeking stranded cost recovery to shoulder a portion of its stranded costs on the basis that such a requirement would be a major deviation from the traditional principle that a utility should have a reasonable opportunity to recover its prudently incurred costs, and explained why we applied a different approach in the gas area. 574/ Rehearing Requests Opposing Full Recovery from Departing Customers A number of entities submit that the Commission has not adequately explained its decision not to require some utility sharing of stranded costs when the utility can satisfy the reasonable expectation criteria. They object that the Commission did not meaningfully consider the arguments made by commenters concerning utility responsibility (such as poor management decisions) for stranded costs. 575/ FERC Stats. & Regs. at 31,800-802; mimeo at 485-90. FERC Stats. & Regs. at 31,802-03; mimeo at 490-92. E.g., ELCON, IL Industrials, San Francisco, Nucor. Other entities that urge the Commission to require shareholders to shoulder a portion of the utility's stranded costs include Central Illinois Light, AR Com, American Forest & Paper, Nucor, and Occidental Chemical. American Forest & Paper and Nucor suggest that full recovery destroys incentives to mitigate. Several entities also support spreading the costs to all of the utility's customers. E.g., American Forest & Paper, Central Illinois Light, AR Com. Docket Nos. RM95-8-001 -273- and RM94-7-002 ELCON argues that departing customers are not the sole cause of stranded costs. IL Industrials submits that the statement in the Rule that utility shareholders "'had no responsibility for causing the legitimate, prudent and verifiable costs to be incurred'" is untrue. 576/ It argues that although utilities may have had a legal obligation to serve and meet projected demands, how the utility chose to meet those obligations was under the utility's control. IL Industrials asserts that shareholders should bear some of the risk associated with the decisions of their management that were less than optimal. At a minimum, IL Industrials argues that the Commission should consider on a case- by-case basis (when it determines whether a utility has incurred legitimate and verifiable stranded costs) whether some amount of stranded costs should be shared with shareholders. NASUCA challenges the Commission's statement in Order No. 888 that requiring a utility to shoulder a portion of its stranded costs "would be a major deviation from the traditional principle that a utility should have a reasonable opportunity to recover its prudently incurred costs." 577/ It contends that there is no constitutionally guaranteed right of recovery of all prudent investment. 578/ NASUCA further asserts that full IL Industrials at 4-6 (citing Order No. 888, mimeo at 491- 92). FERC Stats. & Regs. at 31,802; mimeo at 490. NASUCA cites in support of its position Covington & Lexington Turnpike Road Company v. Sandford, 164 U.S. 578 (continued...) Docket Nos. RM95-8-001 -274- and RM94-7-002 recovery of uneconomic investment is not the norm. It submits that the Commission has rejected utility demands for full recovery of cancelled electric generation facilities. 579/ San Francisco cites Market Street as support for the proposition that the risk of unmarketability should fall, in whole or in part, on utility shareholders who knew of competitive risks and who have been compensated for those risks through rates of return. A number of parties object that the Commission, in declining to require some shareholder sharing of stranded costs, is allowing the electric utility industry to claim more generous recoveries under Order No. 888 than it allowed the gas industry, and that it has provided no adequate rationale for this difference in treatment. 580/ San Francisco states that although the Rule attempts to distinguish shareholder sharing in the natural gas industry "as an extraordinary measure given the (...continued) (1896); Market Street Railway Company v. Railroad Commission, 324 U.S. 548 (1945) (Market Street); Duquesne Light Company v. Barasch, 488 U.S. 299, 315-16 (1989). NASUCA cites in support of its position New England Power Company, 8 FERC  61,054 (1979), aff'd sub nom. NEPCO Municipal Rate Committee v. FERC, 668 F.2d 1327 (D.C. Cir. 1981), cert. denied, 457 U.S. 1117 (1982). NASUCA states that in that case, prudently incurred plant investment was abandoned because changing circumstances rendered the investment uneconomic; the Commission provided for a ten- year amortization of the plant investment, with no return on the unamortized balance. NASUCA says that this precedent demonstrates that the "regulatory compact" does not require full cost recovery. E.g., Central Illinois Light, Occidental Chemical. Docket Nos. RM95-8-001 -275- and RM94-7-002 nature of the take-or-pay problem and the prevailing environment at that time," 581/ the Commission has not identified how the nature of the take-or-pay problem was any more "extraordinary" than the nature of stranded costs in electric restructuring, or explain its reference to "the prevailing environment at that time." Occidental Chemical submits that the Commission's decision not to allocate a portion of stranded costs to utilities on cost causation grounds contradicts the Commission's actions in Order No. 636, in which it required interruptible and new shippers, as beneficiaries of open access, to share in the costs of the transition. 582/ Central Illinois Light states that the Commission should allow partial recovery of stranded costs and thereby correct key differences in the Commission's responses to gas and electric transition costs. 583/ FERC Stats. & Regs. at 31,802; mimeo at 491. Occidental Chemical argues that requiring gas customers to choose their suppliers during an open season enabled the pipelines to place a dollar value on their take-or-pay obligations. Shippers thus knew at the outset what their gas supply realignment (GSR) surcharge would be and could negotiate with other suppliers accordingly. Occidental Chemical says that most pipelines have already recouped their GSR costs and have made the transition to a competitive supply market in under three years. It argues that, on the other hand, allowing electric stranded costs to be recovered over an indefinite period will blunt the pro- competitive effect of Order No. 888. Central Illinois Light supports a recovery mechanism that would allow utilities to allocate stranded costs to requirements customers on a demand basis and to all transmission customers on a commodity basis. It argues that (continued...) Docket Nos. RM95-8-001 -276- and RM94-7-002 Occidental Chemical also objects that the Commission failed to address the merits of its suggestion that the Commission grant a utility a presumption of prudence in return for absorbing a percentage of its stranded costs. ELCON, in a supplement to its rehearing request, 584/ submits that the D.C. Circuit's remand in United Distribution Companies of the aspect of Order No. 636 that allocated 100 percent of gas supply realignment costs to customers and none to pipelines has implications for the Commission's decision in Order No. 888 to allocate 100 percent of stranded costs to departing customers without any shareholder sharing of the costs. ELCON suggests that although the D.C. Circuit indicated that a finding of threat to the financial viability of the pipeline sector might justify such allocation, there is no evidence in the record in the Order No. 888 proceeding, and the Commission has made no finding, that wholesale stranded cost recovery jeopardizes the financial viability of the utility sector. It adds that, to the extent the Commission relies on strict cost causation principles in Order No. 888, it is not clear how departing wholesale customers who signed contracts in 1985 could have "caused" (...continued) this would recognize the greater cost responsibility of requirements customers, recognize the benefits obtained by all transmission customers from open access, and reduce the charges to all customers to a more reasonable level. We will accept this pleading as a motion for reconsideration, not as a request for rehearing, because it was not filed within the 30-day statutory period for rehearing requests. See 16 U.S.C.  825l(a). Docket Nos. RM95-8-001 -277- and RM94-7-002 utilities to incur uneconomic assets such as expensive nuclear facilities that were planned and ordered in the 1970s. Commission Conclusion As we explained in Order No. 888, we decided not to require a utility meeting the requirements for stranded cost recovery to shoulder a portion of its stranded costs because such a requirement would be a major deviation from the traditional principle that a utility should have a reasonable opportunity to recover its prudently incurred costs. 585/ Our decision (which allows assignment of legitimate, prudent and verifiable stranded costs to departing requirements generation customers, not to shareholders or other customers of the utility) also follows the cost causation principle that has been fundamental to our regulation since 1935. 586/ It is important, in this regard, to FERC Stats. & Regs. at 31,802; mimeo at 490-91. In response to ELCON's argument that it is not clear how departing wholesale customers who signed contracts in 1985 could have "caused" utilities to incur uneconomic assets such as expensive nuclear facilities that were planned and ordered in the 1970s, we note that customers taking requirements service generally pay an allocated share of total embedded costs, including the cost of investments made before the customer began service. This pricing principle is consistent with the method that Order No. 888 adopts for calculating a departing customer's stranded cost obligation. The revenues lost approach is not an asset-by-asset approach. Instead, it is an approach that looks at a utility's current rates, which are based on all the utility's assets, which may include both high cost and low cost generating facilities of various ages, and relies on the presumption that the fixed costs allocated to departing customers under their current rates are properly assignable to them. Thus, if a utility is able to demonstrate that it had a reasonable expectation of continuing to serve the customer after the contract term, the customer's stranded cost obligation would be (continued...) Docket Nos. RM95-8-001 -278- and RM94-7-002 distinguish between assuring recovery of all uneconomic costs (which Order No. 888 does not do) and providing an opportunity for recovery where the evidentiary requirements of the Rule are met. Allowing full recovery of stranded costs under Order No. 888 is not equivalent to allowing 100 percent recovery of the costs of all uneconomic assets. A utility may have uneconomic assets for a variety of reasons, including a decline in load, customer shifts to natural gas, customer energy conservation, loss of a large industrial customer, customer self-generation, and a customer gaining transmission access through another utility's transmission system. The Rule does not provide for the recovery of the costs of such uneconomic assets. Instead, the Rule defines a discrete set of uneconomic costs that are stranded by FPA section 211 or Order No. 888 transmission service (when a customer uses the former supplying utility's transmission system to reach a new supplier) for which utilities may seek recovery. However, even as to this set of costs the Rule does not guarantee 100 percent recovery. To be eligible to recover such costs, a utility must satisfy the (...continued) computed based on the average annual revenues that the customer would have paid had it remained a customer of the utility; the calculation of stranded costs would not be tied to any particular investments that the utility made in a particular unit. As we explain in Section IV.J.9 below, the use of present annual revenues as the basis for the stranded cost calculation is based, among other things, on the presumption that present rates include all just and reasonable costs of providing service. Docket Nos. RM95-8-001 -279- and RM94-7-002 reasonable expectation test set forth in Order No. 888. Even then, the utility will be eligible to recover only costs that are legitimate, prudent and verifiable. In response to those entities that argue that departing customers are not the sole cause of stranded costs and that poor management decisions may be partly to blame, we reiterate that a determination that a utility has a reasonable expectation of continuing to serve a customer would not, in all circumstances, mean that costs incurred by the utility were prudent. As we said in Order No. 888, we cannot make a blanket assumption that all claimed stranded costs were prudently incurred. We explained that prudence of costs, depending upon the facts in a specific case, may include different things, such as prudence in operation and maintenance of a plant, and the utility's ongoing obligation to exercise prudence in retaining existing investments and power purchase contracts and in entering into new ones. 587/ We clarified, however, that we do not intend to relitigate the prudence of costs previously recovered. Thus, to the extent that costs have not been previously recovered by a utility, and depending upon the facts presented, a customer from whom a utility is seeking to recover stranded costs may be able to challenge the prudence of those costs. If such prudence challenge is successful, then the utility would not be entitled to recovery of the imprudently incurred costs, through FERC Stats. & Regs. at 31,850; mimeo at 626. Docket Nos. RM95-8-001 -280- and RM94-7-002 stranded cost recovery or otherwise. We believe that this fully addresses the concerns of those entities that contend that departing customers should not be responsible for costs that result from poor management decisions or other actions by the utility. 588/ As we explained in Order No. 888, our decision not to require utilities to shoulder a portion of their stranded costs is based on the traditional principle that a utility should have a reasonable opportunity to recover its prudently incurred costs. 589/ NASUCA's reliance on the Commission's cancelled plant policy to support its argument that full recovery of uneconomic investment is not the norm is misplaced. The Commission's cancelled plant policy, which allows a utility to recover 50 percent of its prudently-incurred investment in a cancelled or abandoned plant, relates only to plants that are cancelled or abandoned prior to entering commercial service and thus prior to Whether poor management decisions or other actions are imprudent would be decided on a case-by-case basis. See, e.g., New England Power Company, Opinion No. 231, 31 FERC  61,047 at 61,081-84, reh'g denied, Opinion No. 231-A, 32 FERC  61,112 (1985), aff'd sub nom., Violet v. FERC, 800 F.2d 280 (1st Cir. 1986); Minnesota Power & Light Company, Opinion No. 86, 11 FERC  61,312 at 61,644-45, order on reh'g, 12 FERC  61,264 (1980). However, a utility's costs are presumed prudent and a person challenging such costs would have the burden of going forward with evidence that raises a serious doubt as to prudence. Id., 11 FERC at 61,645. See, e.g., Maryland v. Louisiana, 451 U.S. 725, 748 (1981); Office of Consumers' Counsel v. FERC, 914 F.2d 290, 292 (D.C. Cir. 1990); City of New Orleans, Louisiana v. FERC, 67 F.3d 947, 954 (1st Cir. 1995). Docket Nos. RM95-8-001 -281- and RM94-7-002 becoming used and useful. 590/ The Commission has taken a different approach in the case of electric generating plants that are prematurely shut down after having been in commercial operation for a number of years. In the latter instance (which more closely resembles the type of costs for which a utility might seek recovery under Order No. 888 than does the cancelled plant before operation scenario), the Commission has allowed 100 percent recovery of prudently-incurred unamortized investment. 591/ See New England Power Company, Opinion No. 295, 42 FERC  61,016, reh'g denied in part and granted in part, Opinion No. 295-A, 43 FERC  61,285 (1988). We note that the Supreme Court case on which NASUCA relies to support its argument that there is no constitutionally guaranteed right of recovery of all prudent investment, Duquesne, also involved electrical generating facilities that were planned but never built. See 488 U.S. 299 (1989). See Yankee Atomic Electric Company, Opinion No. 390, 67 FERC  61,318, (Yankee Atomic), reh'g denied, 68 FERC  61,364 (1994), remanded on other grounds, Town of Norwood, Massachusetts v. FERC, 80 F.3d 526 (D.C. Cir. 1996), offer of settlement accepted, letter dated January 30, 1997, Docket No. ER92-592-005. This case involved a nuclear plant that had been in operation for over 30 years. In affirming the Commission's decision to allow full recovery and not to apply Opinion No. 295's recovery rule for plants abandoned before operation, the court explained: Although ratepayers generally 'bear the expense of depreciation' and although investors generally 'are entitled to recoup from consumers the full amount of their investment in depreciable assets devoted to public service,' [citations omitted] Opinion No. 295 makes a logical exception to this full recovery rule for plants abandoned before operation; in such cases, ratepayers have not benefitted from the plant. The situation here is quite different. Because customers have benefitted from the operation of the plant for over 30 years, and because ceasing plant operations (continued...) Docket Nos. RM95-8-001 -282- and RM94-7-002 San Francisco's and NASUCA's reliance on Market Street is also distinguishable. That case involved an industry (street railway) that had been rendered economically obsolete by market forces. The electric industry today, in contrast, is clearly not obsolete. Moreover, the costs that Order No. 888 gives a utility an opportunity to recover even in the face of market forces would not become stranded but for statutory and regulatory changes. A number of parties contend that the Commission has not provided an adequate rationale for its different treatment of shareholder sharing in the natural gas industry. ELCON also relies on the D.C. Circuit's remand in United Distribution Companies of Order No. 636's holding that pipelines could recover 100 percent of their gas supply realignment (GSR) costs. After further review of this matter in light of the Court's decision in United Distribution Companies, we reaffirm that, even though the Commission permitted pipelines to recover take-or-pay costs based on "cost spreading" and "value of service" principles, stranded electric utility costs should be recovered based on traditional cost causation principles. This is because, despite the fact that both sets of costs are incurred in connection with a (...continued) will benefit customers by lowering rates, such an exception is unwarranted. Moreover, applying Opinion No. 295's recovery rule would not, as it would in the case of a plant that never began operations, promote economic efficiency." 80 F.3d at 532. In Yankee Atomic, the Commission also allowed recovery of 100 percent of construction work in progress and of post- shutdown O&M expenditures. Docket Nos. RM95-8-001 -283- and RM94-7-002 transition to unbundled, open access service, there are also substantial differences between the circumstances surrounding the two industries' incurrence of their respective transition costs. The pipelines' take-or-pay problems began before the Commission initiated open access transportation in Order No. 436. The severe gas shortages of the 1970s led to enactment of the Natural Gas Policy Act (NGPA), which initiated a phased decontrol of most new gas prices and established ceiling prices for controlled gas, including incentive prices for price-controlled new gas higher than the ceiling prices previously established by the Commission under the NGA. 592/ To avoid future shortages, pipelines then entered into long-term take-or-pay contracts at the high prices made possible by the NGPA, and those high prices stimulated producers to greatly increase exploration and drilling. 593/ When demand unexpectedly fell and supply increased, the pipelines found themselves contractually bound to take or pay for high-priced gas which they could not sell. Even before Order No. 436 issued in October 1985, pipeline take-or-pay exposure was approaching $10 billion. 594/ In 1986, as pipelines were just beginning to implement open access transportation under Order No. 436 and before the August 1987 issuance of Order No. Order No. 500-H, Regulations Preambles 1986-1990, FERC Stats. & Regs.  30,867 at 31,509 (1989). Id. at 31,509-10. Id. at 31,513. Docket Nos. RM95-8-001 -284- and RM94-7-002 500, the pipelines' outstanding unresolved take-or-pay liabilities peaked at $10.7 billion. 595/ The Commission and the industry had never previously faced a take-or-pay problem of this nature or magnitude. In earlier times, pipelines had made take-or-pay payments to particular producers, and the Commission had a policy of permitting such payments to be included in rate base and then recovered as a gas cost when the pipeline later took the gas under make-up provisions in the contract. 596/ By 1983, however, the pipelines could not manage their take-or-pay problems, and stopped honoring the bulk of their take-or-pay liabilities. 597/ They then sought settlements with the producers to reform or terminate the uneconomic take-or-pay contracts and to resolve outstanding take- or-pay liabilities. Because pipelines had never previously incurred significant take-or-pay settlement costs, the Commission had no policy concerning whether and how pipelines were to recover those costs. The Commission commenced establishing such Id. Regulatory Treatment of Payments Made in Lieu of Take-or-Pay Obligations, Regulations Preambles 1982-85, FERC Stats. & Regs.  30,637 at 31,301 (1985). In Order No. 500-H, the Commission found that, although pipelines incurred total take-or-pay exposure over the period January 1, 1983 through June 30, 1987 of over $24 billion, they made take-or-pay payments totalling only $.7 billion. Order No. 500-H, Regulations Preambles 1986-1990  30,867 at 31,514. Docket Nos. RM95-8-001 -285- and RM94-7-002 a policy in an April 1985 policy statement, 598/ just six months before Order No. 436. When Order No. 500 issued, few take-or-pay settlement costs had yet been included in pipelines' rates. However, since the pipelines' outstanding take-or-pay liabilities were in the neighborhood of $10 billion, it was clear that pipelines would incur massive costs in their settlements with producers. In short, when the Commission first addressed the issue of how to allocate take-or-pay settlement costs in Order No. 500, it did so under the shadow of the pipelines' vast outstanding take- or-pay exposure. The essential problem, therefore, was to decide which customers' rates should be raised to reflect the billions of dollars of take-or-pay settlement costs that the pipelines were incurring, but that the pipelines had still not filed to recover. To have allocated those costs solely to any one segment of the industry would have imposed a crushing new burden on that segment. For example, if the Commission had allocated the take- or-pay settlement costs entirely to bundled sales customers who chose to convert to transportation-only service, those customers would have ended up far worse off than if they remained as bundled sales customers. As a result of all these facts, the fundamental premise of Order No. 500 was, as the Court expressed it in KN Energy, that Regulatory Treatment of Payments Made in Lieu of Take-or-Pay Obligations, Regulations Preambles 1982-85, FERC Stats. & Regs.  30,637 (1985). Docket Nos. RM95-8-001 -286- and RM94-7-002 "the extraordinary nature of this problem requires the aid of the entire industry to solve it." 599/ In order to accomplish this result, Order No. 500 established an equitable sharing mechanism for pipelines to use in recovering their take-or-pay settlement costs as an alternative to recovery through their commodity sales rates. Relying on "cost spreading" and "value of service" principles, the Commission permitted pipelines to allocate their take-or-pay settlement costs among all the pipelines' customers. The Commission also required the pipelines using the equitable sharing mechanism to absorb a portion of the costs in return for the ability to recover an equal portion through a fixed charge. Importantly, pipelines using the equitable sharing mechanism and agreeing to absorb a portion of the costs were given a presumption that their take-or-pay settlement costs were prudent. Those who did not choose to avail themselves of the sharing/absorption mechanism could still file for recovery of take-or-pay costs pursuant to the traditional ratemaking methodology. Because the pipelines' cash flow problems were so severe and they could not reasonably expect to recover their costs through their sales rates, they readily availed themselves of the special mechanism, with its presumption of prudence, rather than the more protracted traditional ratemaking option. 600/ 968 F.2d 1295, 1301 (D.C. Cir. 1992). By contrast, Order No. 888 does not provide a presumption of (continued...) Docket Nos. RM95-8-001 -287- and RM94-7-002 The Court in KN Energy upheld the Commission's use of cost spreading in connection with the allocation of take-or-pay costs among a pipeline's open access customers. 601/ The Court held that "the ratemaking rationales of Order No. 500 can be reconciled with the NGA, given the unusual circumstances surrounding the take-or-pay problem, and the limited nature -- both in time and scope -- of the Commission's departure from the cost-causation principle." 602/ The Court emphasized that "[w]e hold only -- and quite narrowly -- that in the context of Order No. 500 the Commission has not betrayed its obligations to the NGA or precedent by employing these ratemaking principles in its attempt to bring closure to the take-or-pay drama." 603/ The unusual circumstances that justified the departure from cost causation principles in Order Nos. 500/528 are not present in the electric industry. In Order No. 888's discussion of the Commission's decision not to order any generic abrogation of (...continued) prudence for utilities' stranded cost recovery proposals. Once again, the more traditional concept that the utility must prove costs were prudently incurred will apply. The Court did not review the Order No. 500/528 requirement that pipelines absorb a share of the take-or-pay costs. See AGA v. FERC, 888 F.2d 136, 152 (D.C. Cir. 1989), and AGA v. FERC, 912 F.2d 1496, 1519 (D.C. Cir. 1990), cert. denied, 498 U.S. 1084 (1991), both holding the absorption requirement not ripe for review. KN Energy, 968 F.2d at 1301. Id. at 1302. Docket Nos. RM95-8-001 -288- and RM94-7-002 existing requirements and transmission contracts between electric utilities and their customers, we have already pointed out: 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 prices under the Natural Gas Policy Act, and increased production of gas. In other words, there was a market failure in the industry. . . . In contrast, there is no such market failure in the electric industry. [604/] The electric utility costs potentially stranded by Order No. 888 are fixed costs arising from the utility's electric generation business, including, for example, depreciation expense associated with the utilities' own generation facilities and a return on the original cost of its investment in those facilities. They also include costs associated with mandatory QF purchase contracts. Unlike take-or-pay settlement costs, these costs are not an extraordinary expense that the Commission has never previously encountered. Rather, the stranded electric costs that are subject to the direct assignment provisions of Order No. 888 are ordinary costs that have always been, and are currently, included in the utility's rates for electric generation approved by the Commission. And there is no pre- existing industry-wide market failure. Thus, we are not confronted at the start of the electric open access program with a vast outstanding cost not currently reflected in the electric FERC Stats. & Regs. at 31,664; mimeo at 84. Docket Nos. RM95-8-001 -289- and RM94-7-002 utilities' rates, as we were at the start of the natural gas open access program. Therefore, unlike the situation with the natural gas industry, stranded electric utility costs can be allocated among customers based upon traditional cost causation principles without imposing inequitable and unreasonable burdens on particular customer classes. Direct assignment to departing requirements generation customers through the stranded cost recovery mechanism contained in the Rule is consistent with the traditional cost causation principle because it recognizes the link between the incurrence of stranded costs and the decision of a particular generation customer to use open access transmission on the utility's system to leave the utility's generation system and shop for power, and bases the utility's ability to recover stranded costs on its ability to demonstrate that it incurred costs with the reasonable expectation that the customer would remain on its generation system beyond the term of the contract. The stranded costs are measured as the difference between revenues the utility would have recovered from the customer and the market value of the utility's power. In essence, therefore, all that the direct assignment provisions of Order No. 888 require is that certain customers (those whom a utility is able to demonstrate it reasonably expected to continue serving beyond the contract term) who convert to transmission-only service continue, for a period, to bear certain generation costs that they were previously bearing. Docket Nos. RM95-8-001 -290- and RM94-7-002 This helps to minimize immediate cost shifts to the remaining generation customers, and is thus consistent with the Court's concerns in AGD about cost shifts due to open access transportation. 605/ At the same time, it does not impose any crushing new burden on the converting generation customers, as would have happened if in the natural gas industry the Commission had allocated the take-or-pay settlement costs entirely to pipeline sales customers who converted to transportation-only service. On the issue of utility absorption of stranded costs, as ELCON points out, the D.C. Circuit in United Distribution Companies remanded Order No. 636 to the Commission for further explanation as to why the Commission had exempted pipelines from sharing in Order No. 636 GSR costs in light of: (1) its reliance on "cost spreading" and "value of service" principles in allocating GSR costs among the pipelines' customers, and (2) the absorption requirement in Order Nos. 500/528. As the Court explained: If the Commission intends to assign GSR costs according to these 'cost spreading' and 'value of service' principles, it must do so consistently or explain the rationale for proceeding in another manner. We approved the invocation of those principles in KN Energy because FERC had concluded that the take-or-pay crisis could be resolved only by spreading costs throughout the 'entire industry' 968 F.2d at 1301 (emphasis added), and because we recognized that 'all segments See, e.g., AGD, 824 F.2d at 1026. Docket Nos. RM95-8-001 -291- and RM94-7-002 of the industry' . . . will benefit, id. (emphasis added), from restructuring. [606/] For the reasons discussed above and in Order No. 888, we have chosen to use traditional cost causation principles both in allocating stranded electric costs to certain electric utility customers and in finding that the utilities should be given an opportunity for full recovery of certain legitimate, prudent, and verifiable stranded costs. Thus, Order No. 888 does not present the issue of whether the Commission inconsistently applied ratemaking principles to the recovery of stranded costs that was of concern to the court in United Distribution Companies when it remanded the analogous portion of Order No. 636. Moreover, based on the facts summarized above, the Commission concludes that the rationale we used to support the Order Nos. 500/528 absorption requirement is not valid for electric utility costs stranded by Order No. 888. Order No. 528- A, where the Commission gave its fullest justification for that absorption requirement, did not rely on either the "cost spreading" or "value of service" rationales to support the absorption requirement. 607/ Order Nos. 500/528 consistently recognized that the Commission must "provide a pipeline a reasonable opportunity to recover its prudently incurred costs." United Distribution Companies, 88 F.3d at 1189. Order No. 528-A, 54 FERC  61,095 at 61,303-05 (1991). Docket Nos. RM95-8-001 -292- and RM94-7-002 608/ However, Order No. 528-A reasoned that, because the take- or-pay problem was caused more by general market conditions than by any regulatory action of the Commission, it was appropriate to require the pipelines to share in the losses arising from those market conditions as a condition to using the alternative recovery mechanism. 609/ In these circumstances, the Commission concludes that it would not be reasonable to require electric utilities to bear costs that, unlike the Order Nos. 500/528 take-or-pay costs, arise as the direct result of Congress' and the Commission's change in the regulatory regime through FPA section 211 and Order No. 888. This is particularly the case since the electric utilities' potential stranded costs relate to large capital expenditures or long-term contractual commitments (some mandated by federal law) to buy power made many years ago in reliance on the preexisting regulatory regime. Moreover, in a separate order, the Commission is responding to the United Distribution Companies remand by reaffirming the policy established in Order No. 636 that pipelines should be permitted full recovery of their prudently incurred GSR costs. Order No. 500-H, Regulations Preambles 1986-1990, FERC Stats. & Regs. at 31,575. Those orders permitted all pipelines to seek full recovery of their take-or-pay settlement costs through their sales commodity rates. The Commission required pipelines to absorb a share of their Order No. 500/528 take-or-pay costs only if they chose to use the alternative, equitable sharing recovery mechanism. Order No. 528-A, 54 FERC at 61,303-05. Docket Nos. RM95-8-001 -293- and RM94-7-002 In that order, the Commission finds that the rationale Order No. 528-A used to support the Order Nos. 500/528 absorption requirement is inapplicable to GSR costs. The remand order explains that, in the face of extraordinary market conditions, Order Nos. 500/528 adopted extraordinary measures. However, as we are finding here with respect to stranded electric utility costs, the remand order holds that the extraordinary market circumstances that gave rise to the requirement for pipeline absorption of gas supply costs in Order Nos. 500/528 were not present at the time of Order No. 636. Even before the Commission initiated open access transportation in Order No. 436, the market was preventing pipelines from recovering costs incurred under their take-or-pay contracts. The Order Nos. 500/528 absorption requirement reflected the preexisting effect of the market, which would have required absorption even without open access transportation under Order No. 436. The remand order finds that, contrary to the situation when Order No. 436 issued, at the time of Order No. 636, pipelines were generally able to take gas under their few remaining high-priced take-or-pay contracts from the late 1970s and early 1980s and were no longer accumulating significant additional take-or-pay obligations. This was because the pipelines were still performing a significant sales service and had reformed most of their uneconomic take-or-pay contracts. 610/ A number of entities (e.g., VT DPS, Valero, Occidental (continued...) Docket Nos. RM95-8-001 -294- and RM94-7-002 The remand order accordingly holds that the Commission's regulatory actions in Order No. 636 have caused the pipelines to incur the GSR costs. This is particularly the case because Order No. 636 required the pipelines to unbundle their natural gas and transportation sales and forbade the pipelines from making sales unless they were made by a separate sales or marketing entity. Order No. 888 also requires generation or commodity sales to be unbundled from sales of transmission. In these circumstances, traditional ratemaking principles require the Commission to allow the pipelines an opportunity to recover the full amount of the expenses caused by its actions. Thus, the Commission's approach to Order No. 636 GSR costs is similar to its approach in Order No. 888 to stranded electric generation costs. (...continued) Chemical) challenge the Commission's suggestion that, after Order No. 436, many of the former bundled sales customers of the pipeline had departed. To the extent that Order No. 888 suggested that many pipelines' sales customers had terminated their sales service before Order No. 636 issued, we note that, as the Commission indicated in Order No. 636, pipeline sales constituted less than 20 percent of total annual throughput on major pipelines. FERC Stats. & Regs.  30,939 at 30,400. However, the Commission also found that in 1991 over 60 percent of peak day capacity on major pipelines that made bundled sales was reserved for pipeline firm sales service. Id. at 30,399. Thus, we clarify that although on an annual basis customers were buying most of their gas from other suppliers, pipelines were making significant sales of gas, particularly on peak days. Docket Nos. RM95-8-001 -295- and RM94-7-002 Rehearing Requests Citing Other Inconsistencies Between Commission Treatments of the Gas and Electric Industries VT DPS and Valero submit that Order No. 888 does not satisfactorily distinguish the Commission's rejection of gas pipelines' attempts to impose exit fees on departing customers. They argue that the Commission opposed the imposition of such exit fees in the gas context as anticompetitive because it would force customers desiring to switch suppliers when their contracts expired to pay the supply costs of both the new and former suppliers. VT DPS and Valero take issue with the Commission's attempt to distinguish a recent El Paso case 611/ as a "post- restructuring" case under Order No. 636. They contend that the Commission consistently applied the same policy (rejection of gas pipeline attempts to impose exit fees) before restructuring under Order No. 636. They further claim that the Commission cannot articulate a plausible basis for permitting utilities with notice provisions to file for exit fees, having denied El Paso's proposal outright without giving it an opportunity to rebut the presumption. VT DPS and Valero also state that the "stranded" costs for which the Commission allowed recovery under Order No. 636 were costs that would be rendered unrecoverable because the costs would not be incurred to provide transportation service and El Paso Natural Gas Company, 72 FERC  61,083 (1995) (El Paso). Docket Nos. RM95-8-001 -296- and RM94-7-002 because there would be no wholesale load from which to recover the costs. They indicate that the Commission has held that such gas costs are stranded only if rendered unrecoverable as a direct result of the restructuring required under Order No. 636. They submit that when a utility loses wholesale load or a municipality establishes a new distribution system and the utility cannot resell the capacity left unused, the utility's costs are not necessarily "stranded" -- i.e., rendered unrecoverable -- any more than if the utility's load declines because of conservation, an economic downturn or an increase in self-generation. They argue that the Commission should limit utility stranded cost claims solely to those cases where the utility can demonstrate that its costs have been rendered unrecoverable as a direct result of the Rule. Commission Conclusion We explained in Order No. 888 why we disagree with the argument that the Commission cannot impose an exit fee to recover stranded costs because the Commission did not allow gas pipelines to do so. We noted that the Rule establishes procedures for providing a potential departing generation customer advance notice (before it leaves its existing supplier) of the stranded cost charge (whether it is to be paid as an exit fee or a transmission surcharge) that will be applied if the customer decides to buy power elsewhere and the Commission decides the utility has satisfied the stranded cost recovery criteria of the Rule, e.g., the reasonable expectation criterion. We indicated Docket Nos. RM95-8-001 -297- and RM94-7-002 that in the natural gas context, in contrast, the Commission has prohibited pipelines from developing and charging an "exit fee" after a customer had implemented its gas purchase decision, noting that otherwise, the customer would not know in advance the full cost consequences of its nomination decision. 612/ We continue to believe that the Commission's decisions concerning natural gas pipeline exit fees, relied on by VT DPS and Valero, are not inconsistent with Order No. 888's limited approval of exit fees for the recovery of certain stranded electric utility costs. VT DPS and Valero point first to two cases decided by the Commission in 1988 and 1989 involving Gas Inventory Charges (GICs) proposed by Transwestern Pipeline Company (Transwestern) 613/ and El Paso Natural Gas Company (El Paso) 614/ pursuant to our Order No. 500 policy statement. However, those cases are not relevant here, essentially because the exit fees at issue in those cases were not designed to recover costs arising from the transition to open access transportation, unlike the stranded electric utility costs at issue here. In the Transwestern case cited by VT DPS and Valero, Transwestern included in its proposal to implement a GIC a FERC Stats. & Regs. at 31,802; mimeo at 489. Transwestern Pipeline Company, 44 FERC  61,164 at 61,536 (1988) (Transwestern). El Paso Natural Gas Company, 47 FERC  61,108 at 61,314, reh'g denied, 48 FERC  61,202 (1989). Docket Nos. RM95-8-001 -298- and RM94-7-002 request for permission to assess an exit fee. The exit fee would have been charged to its largest local distribution company customer if that customer initially chose to nominate purchases under the GIC but then subsequently reduced its nominations. The Commission found the proposed exit fee inconsistent with both (1) its policy that GIC customers know in advance the full cost consequences of their nomination decisions and (2) its objective that prices under the GIC be constrained by market forces. However, this holding was not applicable to Transwestern's recovery of costs incurred as part of its transition to open access transportation, since the Commission did not intend the GIC as a vehicle for recovery of such transition costs. The GIC was intended solely as a forward-looking charge that would recover costs the pipeline would incur in the future under its reformed, market responsive gas supply contracts. 615/ The Commission's intent was that, before implementing GICs, pipelines would negotiate settlements of their existing uneconomic take-or- pay contracts and file to recover the resulting settlement costs under the Order No. 500 equitable sharing mechanism. 616/ Indeed, in the Transwestern order cited by VT DPS and Valero, the Commission suggested that Transwestern postpone implementation of its GIC until it had renegotiated its supply contracts and filed Order No. 500, Regulations Preambles (1986-1990), FERC Stats. & Regs.  30,761 at 30,793-94 (1987). CPUC v. FERC, 988 F.2d 154, 168 (D.C. Cir. 1993), quoting, Transwestern Pipeline Company, 55 FERC  61,157 at 61,509 (1991). Docket Nos. RM95-8-001 -299- and RM94-7-002 to recover the resulting costs under the Order No. 500 equitable sharing mechanism. 617/ That mechanism included a fixed take-or-pay charge analogous to the direct assignment provisions of Order No. 888. The Commission permitted pipelines to allocate to sales customers who converted from sales to transportation the same fixed take-or-pay charge that those customers would have been allocated had they not converted. 618/ Moreover, in a later order involving Transwestern's recovery of take-or-pay settlement costs under its Order No. 500 equitable sharing mechanism, the Commission expressly held: In appropriate circumstances, the Commission may approve exit fees for departing customers, either through a condition on the abandonment of the purchase obligation of customers subject to the Commission's jurisdiction or through tariff language Transwestern, 44 FERC at 61,536. The 1989 El Paso order cited by VT DPS and Valero (47 FERC  61,108) reiterated the policy established in Transwestern concerning exit fees in the context of GICs. The El Paso order is distinguishable from our approach to exit fees in Order No. 888 for the same reasons as Transwestern. Natural Gas Pipe Line Company, 46 FERC  61,335 at 62,013 ("Consistent with the court's holding in AGD, that Part 284 transportation and CD conversion must be accompanied by take-or-pay relief, the Commission finds that a pipeline's sales customers who convert to transportation must continue to be liable for the take-or-pay costs allocated to them without regard to the fact that they are no longer sales customers but only transportation customers."), reh'g denied, 47 FERC  61,247 (1989); Transwestern Pipeline Company, 65 FERC  61,060 at 61,473 (1993), reh'g denied, 66 FERC  61,287 at 61,827-828 (1994), aff'd sub nom. Western Resources, Inc. v. FERC, 72 F.3d 147 (D.C. Cir. 1996). Docket Nos. RM95-8-001 -300- and RM94-7-002 giving appropriate notice of such a fee before the departure. [619/] As discussed in the preceding section of this order, the direct assignment provisions of Order No. 888, in essence, require that certain electric generation customers who convert to transmission-only service continue, for a period, to bear certain generation costs that they were previously bearing. That requirement is similar to the Commission's requirement, in connection with its Order No. 500 program, that pipeline sales customers who convert to transportation-only service continue to pay the same Order No. 500 fixed take-or-pay charge as they would have paid had they not converted. VT DPS and Valero also claim that permitting electric utilities to recover stranded generation costs through exit fees to customers converting to transmission-only service is inconsistent with our 1995 order in El Paso, 620/ rejecting that pipeline's exit fee proposal. We see no inconsistency. El Paso proposed, several years after its restructuring pursuant to Order No. 636, to impose an exit fee on its firm transportation customers who terminated or reduced their firm transportation Transwestern Pipeline Company, 64 FERC  61,145 at 62,166 (1993), reh'g denied, 66 FERC  61,287 (1994). However, as illustrated by the situation described in the cited Transwestern order, some sales customers had departed altogether from the systems of their historical pipeline suppliers before the Commission recognized the need for continued allocation of Order No. 500 take-or-pay costs to those customers. In these circumstances, the filed rate doctrine prevented such continued allocation. 72 FERC  61,083 (1995).