UNITED STATES OF AMERICA 61 FERC 61,272 FEDERAL ENERGY REGULATORY COMMISSION 18 CFR Part 284 Pipeline Service Obligations ) Docket No. RM91-11-004 and Revisions to Regulations ) Governing Self-Implementing ) Transportation Under Part 284 of ) the Commission's Regulations ) Regulation of Natural Gas Pipelines) Docket No. RM87-34-069 After Partial Wellhead Decontrol ) ORDER NO. 636-B ORDER DENYING REHEARING AND CLARIFYING ORDER NOS. 636 AND 636-A Issued: November 27, 1992 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Before Commissioners: Martin L. Allday, Chairman; Charles A. Trabandt, Elizabeth Anne Moler, Jerry J. Langdon and Branko Terzic. Pipeline Service Obligations ) Docket No. RM91-11-004 and Revisions to Regulations ) Governing Self-Implementing ) Transportation Under Part 284 of ) the Commission's Regulations ) Regulation of Natural Gas Pipelines ) Docket No. RM87-34-069 After Partial Wellhead Decontrol ) ORDER NO. 636-B ORDER DENYING REHEARING AND CLARIFYING ORDER NOS. 636 and 636-A (Issued November 27, 1992) I. INTRODUCTION On August 3, 1992, the Federal Energy Regulatory Commission issued Order No. 636-A in which it denied rehearing in part, granted rehearing in part, and clarified Order No. 636. 1/ Order No. 636, as modified by Order No. 636-A, restructured the regulation of interstate natural gas pipeline services in order to create a natural gas industry which will provide all gas 1/ Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations; and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 57 FR 13267 (April 16, 1992), III FERC Stats. & Regs. Preambles  30,939 (April 8, 1992) (Order No. 636); order on reh'g, Order No. 636-A, 57 FR 36128 (August 12, 1992), III FERC Stats. & Regs. Preambles  30,950 (August 3, 1992). Docket No. RM91-11-004, et al. - 2 - consumers and the Nation in the long-term with an adequate and reliable supply of clean and abundant natural gas at reasonable prices. In Order No. 636-A, the Commission largely upheld the regulations adopted in and requirements of Order No. 636. The Commission did, however, make a number of changes to Order No. 636 in response to the rehearing and clarification requests. The Commission has received over eighty petitions for rehearing or clarification or both of Order No. 636-A. 2/ The petitioners reargue issues on which rehearing was denied in Order No. 636, challenge changes made to Order No. 636 by Order No. 636-A, and raise some new issues with respect to details of various aspects of Order Nos. 636 and 636-A. The main issues raised by petitioners are as follows. First, they argue that the Commission erred in denying shippers receiving transportation service under individual or transaction specific Natural Gas Act (NGA) section 7(c) certificates the right to release capacity under section 284.243 of the Commission's regulations and to have the same rights to flexible receipt and delivery points as Part 284 shippers. Second, petitioners oppose the Commission's requirement that pipelines maintain their one-part volumetric rates computed at an imputed load factor to determine the transportation rates for small 2/ See the Appendix for a list of the parties seeking rehearing or clarification or both. Petitioners will be referred to by the abbreviations indicated in the Appendix. Docket No. RM91-11-004, et al. - 3 - customers. Third, petitioners maintain that the Commission erred in requiring pipelines to adopt measures to avoid significant cost shifts that may result from the adoption of the straight fixed variable (SFV) method of cost classification, allocation, and rate design. Fourth, petitioners argue that the Commission should have used a period less than 20 years as the contract term cap that must be matched by a customer exercising its right of first refusal upon expiration of its contract. Fifth, petitioners contend that the Commission erred in requiring pipelines to recover 10 percent of their gas supply realignment costs from their Part 284 interruptible transportation service. As discussed below, this order denies rehearing and clarifies Order Nos. 636 and 636-A. Hence, no further petitions for rehearing will be entertained and the instant rule is fully ripe for judicial review. II. LEGAL BASIS AND RATIONALE FOR UNBUNDLING This part addresses the rehearing requests with respect to the Commission's legal basis and rationale in adopting Order Nos. 636 and 636-A. A. The Legal Basis 1. Natural Gas Act Authority In Order Nos. 636 and 636-A, the Commission concluded that it had authority under NGA section 5 to alter a pipeline's contractual terms and conditions of service and that it had not unlawfully revoked or modified any certificates of public convenience and necessity under NGA section 7. The Commission Docket No. RM91-11-004, et al. - 4 - found that "section 7 cannot be read so narrowly as to permanently prevent the Commission from changing the terms and conditions under which a pipeline provides service, especially when the pipeline's obligation to serve and the LDC's entitlement under the certificate remain intact." 3/ Cincinnati Gas argues that an analysis of the individual elements of Order No. 636-A reveals that the rule does not preserve the pipelines' existing service obligation. It contends that this is so because the new combination of unbundled sales service and no-notice transportation service is not equal to the bundled, city-gate, firm sales service. Cincinnati Gas complains that, under the new combination of services, LDCs, rather than the pipelines, will be responsible for and bear the risk of supplying their gas for the no-notice transportation service. As an example, Cincinnati Gas states its concern that the pipeline and other gas suppliers will subject it to "output" agreements, under which a failure of supply service will merely reduce the contracts' take obligation. Hence, it maintains that it will not be insulated, as it is now, from the risk of obtaining gas supplies to minimize the risks associated with the loss or reduction of production from particular wells. It further contends that the concept of borrowing gas has not been shown to be a viable option for securing gas supplies for firm service. In a similar vein, Cincinnati Gas contends that the conditions attached to no-notice transportation, e.g., imbalance 3/ Order No. 636-A at p. 30,530. Docket No. RM91-11-004, et al. - 5 - penalties and operational flow orders, show that is inferior to bundled, city-gate, firm sales service. In addition, Cincinnati Gas maintains that a pipeline can free itself from its certificated sales service obligation by merely making an uncompetitive offer to the LDC. The Commission adheres to its discussion and conclusion in Order Nos. 636 and 636-A that it has acted within its authority under NGA sections 4(b) and 5 to prevent undue discrimination by altering the pipelines' contractual terms and conditions of service to remedy the unduly discriminatory and anticompetitive structure of the pipeline industry. The Commission rejects Cincinnati Gas's argument that the Commission's action does not comport with NGA section 7. 4/ In short, the Commission concludes that the instant rule, in unbundling pipeline sales and transportation services, effects no abandonment of service to Cincinnati Gas or to any other pipeline customer. The Commission amplifies its discussion in Order Nos. 636 and 636-A as follows. The Commission finds that Cincinnati Gas has presented no reasons to persuade the Commission that it will suffer any diminution in service. At the outset, the pipeline continues to 4/ The Commission has the authority under NGA section 4(b) to prevent undue discrimination among pipeline customers. The Commission may invoke that section, as it did here (Order No. 636 at p. 30,405), to deal with discrimination between pipeline services whether or not it could invoke section 7 for that purpose. FPC v. Louisiana Power & Light Co., 406 U.S. 621, 646 (1972) ("Since  4(b) deals with `service,' the FPC may invoke it to deal with curtailment programs, whether or not it could also invoke  7 for that purpose."). Docket No. RM91-11-004, et al. - 6 - be obligated to deliver gas on a no-notice basis to customers receiving no-notice delivery under bundled, city-gate, firm sales service on May 18, 1992. It is true that the Commission has changed the terms and conditions of service and thereby subjected pipeline customers to more responsibilities, duties, and risks. However, the Commission specifically found that those terms and conditions are necessary and reasonable operational mechanisms for implementing the Commission's remedies to eliminate the anticompetitive effect of the current regulatory environment and pipeline services on all segments of the natural gas industry. It is axiomatic that the consumer of any commodity should be responsible for its purchase and use. That is equally applicable here, where gas buyers will have meaningful access to a national and competitive wellhead gas market. Indeed, because the unbundling remedy requires that sales and transportation be provided separately shippers must take the initiative in obtaining gas and therefore bear the responsibilities and risks of obtaining supply. In addition, this shifting of risk is not unreasonable when, as fully discussed in Order No. 636, the pipelines (and ultimately consumers) were disadvantaged by maintaining gas supplies for sale at their WACOG to LDCs when the supplies were needed by the LDCs only as a peaking source supplement to other cheaper gas supply sources. Other terms and conditions of service are necessary to maintain the operational integrity of the pipeline system because the pipeline cannot sell gas at the city gate. This means that the pipeline must rely in Docket No. RM91-11-004, et al. - 7 - the main on the shippers to supply the gas needed to keep the pipeline in balance and capable of making the necessary deliveries. Hence, imbalance penalties and operational flow orders are intimately connected with the pipeline's performance of its transportation service for shippers. 5/ To conclude, the Commission believes that through such measures, the no-notice transportation service will prove as reliable as the no-notice aspect of bundled, city-gate, firm sales service. The Commission merely suggested the concept of gas borrowing as a possible tool to aid in the cooperative effort to secure no-notice service. The Commission does not view the borrowing of gas as the only tool for ensuring no-notice service. LDCs, such as Cincinnati Gas, should be able to negotiate gas purchase contracts with reasonable terms (such as output clauses or gas supply warranties) and prices in the competitive gas market. The mere possibility, unsupported by the rulemaking record, that pipelines will make uncompetitive offers does not invalidate the Commission's ability to act within its NGA section 5 authority. The Commission has no reason to believe that any pipeline will do that or, more importantly, even if a pipeline made such an uncompetitive offer, that any customer will be 5/ Cincinnati Gas believes that pipelines will use operational flow orders to interrupt its supply of gas needed for no-notice transportation service. The Commission views operational flow orders as a vehicle for providing, not interrupting, no-notice service and will consider opposition to particular pipeline operational flow order mechanisms in the compliance filing orders. Docket No. RM91-11-004, et al. - 8 - unable to find adequate, competitively priced supplies from other sources. With the expected enhanced quality of transportation brought about by Order No. 636, there is no reason to expect a diminution in service to any customer. Indeed, as noted, the Commission expects it would be as reliable. Cincinnati Gas has not contended that it, in fact, faces the prospect of a diminution in aggregate service. In fact, Cincinnati Gas now has more options from which to choose from than ever before. Cincinnati Gas complains that it, like other LDCs, is no longer insulated from the risks associated with buying gas in a competitive market. The Commission sees no harm to Cincinnati Gas from acquiring gas in a competitive market. The Commission concludes that the instant rule effects no abandonment of service to Cincinnati Gas or any other pipeline customer by unbundling pipeline sales and transportation services. There is a possible abandonment of service in connection with the pipeline's obligation to serve under the blanket sales certificate granted by Subpart J of Part 284. Effective on the effective date of that certificate, section 284.14(d) of the regulations provides for abandonment of pipeline sales if a gas purchaser exercises its right to reduce or terminate its right to purchase gas from a pipeline or if the purchaser refuses to pay the rate the pipeline offers for unbundled gas sales. However, this will result from the operation of the purchasers' decisions under the regulation -- not from a generic section 7 finding. The Commission found these abandonment authorizations to be in Docket No. RM91-11-004, et al. - 9 - the present or future public convenience or necessity as part of the transition to pipeline sales under the blanket sales certificates, because they will enable the pipelines and gas purchasers to structure their relationship in light of the market for natural gas. 6/ As stated by Congress in section 202 of the Energy Policy Act of 1992: "It is the sense of the Congress that natural gas consumers and producers, and the national economy, are best served by a competitive natural gas wellhead market." 7/ 2. Past Precedent Cincinnati Gas argues that past Commission precedent indicates that the Commission must act under NGA section 7 to accomplish the proposed restructuring. It states that the Commission has required pipelines to apply for certificates under NGA section 7 in order to restructure their services and institute gas inventory charge (GIC) mechanisms 8/ and to transport gas to an existing shipper at new delivery points. 9/ The Commission has acted consistently with the cited cases. The essential aspects of those cases were (1) the fact that the 6/ See Order No. 636 at p. 30,452-55. 7/ Pub. L. No. 102-486, 106 Stat. 2776 (1992). 8/ E.g., Natural Gas Pipeline Co., 41 FERC  61,358 at pp. 61,972-73 (1972), Transwestern Pipeline Co., 42 FERC  61,370 at p. 62,083 (1988), and Transcontinental Gas Pipe Line Corp., 46 FERC  61,364 (1989). 9/ Transcontinental Gas Pipe Line Corp., 42 FERC  61,256 at p. 61,823, reconsideration denied, 43 FERC  61,207 (1988). Docket No. RM91-11-004, et al. - 10 - pipeline's customers had to consent to the abandonment of service linked to releasing the pipeline from its obligation to supply gas above a customer's nominated levels 10/ and (2) the need to act prospectively with respect to an interrelated package of proposals. 11/ Here, the Commission, by operation of the rule, is: (1) providing for abandonment of reduced or terminated customer purchase obligations (section 284.14(d)), (2) issuing each Part 284 pipeline a blanket sales certificate (under Subpart J of Part 284), and (3) acting prospectively under NGA section 5 to avoid a segmented approach. There is therefore no inconsistency with those cases. The Commission also concludes that Cincinnati Gas's argument that the case requires a certificate to change delivery points is irrelevant. This is because the Commission did not, as a policy matter, permit flexible delivery points as a term and condition of transportation service until Order No. 636 modified that policy for Part 284 pipelines. 12/ B. The Rationale Cincinnati Gas attacks in part the Commission's conclusion in Order No. 636-A that 100 percent standby transportation 10/ E.g., Natural Gas Pipeline Co., 41 FERC  61,358 at pp. 81, 972-73 (1987); Transwestern Pipeline Co., 41 FERC  61,371 at p. 62,006 (1987); Transwestern Pipeline Co., 42 FERC  61,370 at p. 62,083 (1988); El Paso Natural Gas Co., 43 FERC  61,327 at p. 61,913 (1988). 11/ See Transwestern Pipeline Co., 42 FERC  61,370 at p. 61,083 (1988), and Transcontinental Gas Pipeline Corp., 46 FERC  61,364 at p. 62,135 (1989). 12/ Order No. 636 at p. 30,428-29. Docket No. RM91-11-004, et al. - 11 - service within firm sales entitlements is not in the public interest. 13/ The Commission reached this conclusion for several reasons. First, the pipeline would still be offering a bundled sales service and therefore would be offering a service at the city gate while other gas sellers would be offering a different service because their sales would occur at or near the production area. Second, the pipeline would have a natural incentive to favor its own sales in managing the pipeline system. This would run afoul of the Commission's intent to put all sellers on an equal footing. Third, the pipeline would have to retain the gas under contract to make the bundled sales, without appropriate compensation, even though the customer would be taking the gas only or mainly at peak. Cincinnati Gas takes issue with the third rationale at least for certain pipelines, such as Columbia Gas Transmission Corporation, which has implemented a GIC that compensates it for the costs associated with maintaining its gas supply portfolio. Cincinnati Gas maintains that Columbia is thus compensated even if its customers take gas only at peak. The Commission believes that the first two reasons are adequate to support its conclusion that 100 percent standby transportation service is not in the public interest and 13/ Under 100 percent standby service, a firm sales customer may elect to receive 100 percent of its daily contract demand volumes as firm transportation service for the shipment of gas purchased from any gas suppliers, with the pipeline obligated to stand ready to provide sales gas at call at full contract demand levels. Docket No. RM91-11-004, et al. - 12 - therefore is not a reasonable alternative to unbundling sales from transportation. Moreover, that Columbia has a GIC, and is, therefore, compensated for maintaining gas supplies, does not alter the Commission's conclusion that the transportation embedded within the bundled firm sales service is superior to firm transportation, to the disadvantage of competing sellers. Last, as stated in Order No. 636-A, "[b]ecause the Commission is determining rules of general, prospective applicability to solve `systemic problems of the natural gas [industry],' 14/ it does not need to examine the circumstances of individual pipelines." 15/ Cincinnati Gas also argues that mandating unbundling runs counter to the Commission's goal of allowing parties to rely more on private contracts. 16/ It maintains that it has renegotiated its pipeline contracts since Commission Order No. 436 was implemented, and that mandating unbundling merely destroys the balance between open access and pipeline sales that it has already achieved. 14/ Order No. 636-A at p. 30,541, quoting Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1166 (D.C. Cir. 1985). 15/ Order No. 636-A at p. 30,541, citing Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1165-68 and Associated Gas Distributors v. FERC, 824 F.2d 981, 1008 (D. C. Cir. 1987). Cincinnati Gas also fails to appreciate that it can contract with any gas supplier -- including the pipeline -- for gas that can be produced on a stand ready basis. In conjunction with the LDC's transportation entitlement, the LDC can if, it chooses replicate a standby service. 16/ Citing Order No. 636-A at p. 30,534. Docket No. RM91-11-004, et al. - 13 - The Commission sees no inconsistency between exercising its authority to find a particular type of contract (bundled sales contract) unduly discriminatory and anticompetitive, and encouraging parties to rely more on contracts in a commercial environment where no one segment of the natural gas industry has an unfair advantage over other market participants owing to its control of a monopoly service. The Commission sees no reason why Cincinnati Gas cannot continue to rely on both pipeline and non- pipeline gas merchants in the new commercial and regulatory environment created by the instant rule. III. UNBUNDLING -- PIPELINE ACCESS TO CAPACITY In Order No. 636, the Commission concluded that pipelines must unbundle the sales and transportation components of their bundled, city-gate, sales services. In Order No. 636-A, the Commission concluded that a pipeline cannot retain or obtain capacity downstream of the point of unbundling on its system except for storage as needed for system management and balancing and no-notice transportation purposes. Several pipelines 17/ argue that this restriction on holding on-system capacity puts them at a competitive disadvantage with their competitors because the latter can effectively rebundle by holding capacity. They add that the Commission's policy may increase the level of transition costs and is not necessary to prevent the pipelines from favoring 17/ Natural, Enron (Northern Natural, Transwestern, and Florida Gas), PEC Pipeline Group, and Tenneco. Docket No. RM91-11-004, et al. - 14 - themselves in light of the Order No. 497-type safeguards of Order Nos. 636 and 636-A. Natural and Enron argue that pipelines as merchants should be able to hold capacity on their own systems. Enron, PEC Pipeline Group, and Tenneco maintain that pipelines should be able to obtain unsubscribed firm and unutilized interruptible transportation and storage capacity once sales and transportation are unbundled. The Commission denies rehearing and adheres to its discussion of this issue in Order No. 636-A. In brief, as stated there, the Commission believes that pipelines will be able to compete with other gas sellers for unbundled gas sales and that, "on balance any advantage on a generic basis for [pipeline] competitors [from reserving capacity for their own sales service] will be minimal and does not warrant permitting pipelines to be capacity holders and gain the opportunity to favor themselves as gas sellers in the management of pipeline transportation facilities, including storage." 18/ This is especially so in the current circumstances where the pipeline must adjust from the bundled to the unbundled environment in operating the pipeline system. The Order No. 497-type safeguards imposed by Order No. 636 (standards of conduct and reporting requirements) apply only to an unbundled and not to a bundled environment. Hence, those 18/ Order No. 636-A at p. 30,543, citing, Tenneco Gas v. FERC, 969 F.2d 1187 (D.C. Cir. 1992), with respect to the pipeline's "obvious incentive to favor its own marketing affiliate." (at 1202). Docket No. RM91-11-004, et al. - 15 - safeguards would provide no protection against a pipeline favoring itself with its bundled sales service. In addition, one reason for adopting the instant rule was a need to ensure equality of transportation, which the Commission continues to believe is best obtainable when the pipeline makes only unbundled sales. The pipeline differs from its competitors because of its control over a monopoly service -- transportation -- which its competitors must use, which gives the pipeline an inherent ability and incentive to favor its own sales service. 19/ The Commission believes that it is therefore necessary to deny pipelines the right to capacity on their own systems, whether retained as part of the restructuring process or obtained thereafter from unsubscribed or released capacity. 20/ The Commission notes, however, that a pipeline's merchant division can act as the gas purchaser's agent to make all arrangements necessary for transportation of the gas. However, the transportation would be accomplished through the use of the customer's transportation capacity in entitlement. In addition, a pipeline's marketing affiliate can obtain capacity on any pipeline and package sales and transportation but, in order to prevent circumvention of the unbundling requirement, the pipeline itself cannot do this. 19/ Cf. Tenneco Gas v. FERC, 969 F.2d 1187 (D.C. Cir. 1992), with respect to the pipeline's "obvious incentive to favor its own marketing affiliate." (at 1202). 20/ For a discussion of transition costs, see infra. Docket No. RM91-11-004, et al. - 16 - IV. OPEN ACCESS TRANSPORTATION RULES A. Application to Part 157 Shippers In Order No. 636-A, the Commission determined that holders of individually certificated transportation under section 7(c) of the Natural Gas Act and Part 157 of the Commission's regulations (Part 157 shippers), i.e. not part 284 shippers, are not eligible to release capacity under section 284.243 since they are not governed by Part 284 or affected by the provisions of Order No. 636 that amended the Part 284 regulations. 21/ For the same reason, the Commission found that Part 157 shippers would not have the same rights to flexible receipt and delivery points as Part 284 shippers. 22/ The Commission stated that Part 157 shippers could convert to Part 284 if they wanted to release capacity or use flexible receipt and delivery points. A number of petitioners seek rehearing of the Commission's restrictions on Part 157 shippers. 23/ They contend the Commission did not adequately justify denying Part 157 shippers access to these essential services and treating them differently than other classes of firm transportation. They assert that Order No. 636 affected all industry segments, including Part 157 21/ Order No. 636-A at p. 30,569. 22/ Order No. 636-A at p. 30,585. 23/ AGA, Brooklyn Union, ConEd, JMC Power Projects, LILCO, Midland Cogeneration, National Fuel, New England Power, Northeast Energy, NYSE&G, Power Authority, PSE&G, SoCal Edison, Tenneco, TransCanada, Transco, UGI, Virginia Power (capacity release). JMC Power Projects, New England Power, Northeast Energy, Northern States, NYSE&G, PSE&G, Virginia Power (flexible receipt and delivery points). Docket No. RM91-11-004, et al. - 17 - shippers. In particular, they cite to the requirement that Part 157 shippers must pay SFV rates and argue that they, like Part 284 shippers, need to release capacity to mitigate the effect of the change to SFV. They further contend that excluding Part 157 shippers from the capacity release mechanism and restricting their use of flexible receipt and delivery points eliminates available capacity from the secondary market and is incompatible with the Commission's goals of establishing a robust secondary market in released capacity and providing for maximum use of the pipeline system with little idle capacity. The Commission denies the requests for rehearing. While the petitioners are correct that the rate design portion of Order No. 636 will apply to Part 157 shippers, the Commission's traditional policy is to apply the same rate design to all services. For example, the Commission applied the principles of its Rate Design Policy Statement to the design of Part 157 rates even though the Policy Statement was applicable only to Part 284 transportation and the non-discriminatory access conditions of Part 284 did not apply to the Part 157 shippers. 24/ Similarly, the competitive rationale for adopting SFV rate design as a means to promote the development of a national gas market 25/ applies equally to Part 157 rates. 24/ Interstate Natural Gas Pipeline Rate Design, 48 FERC  61,122, at p. 61,444 (1989) (order on rehearing). 25/ Order No. 636 at pp. 30,431-35. Docket No. RM91-11-004, et al. - 18 - The rationale for applying SFV rate design to Part 157 rates does not justify extending the capacity release provisions, or other substantive aspects of Part 284, to Part 157 shippers. The regulations promulgated by Order No. 636 changed only the regulations under the Commission's open access transportation program implemented in Part 284 of the regulations. 26/ The Commission's open access program always has been a special program with interrelated provisions designed to implement a comprehensive regulatory scheme. While Part 284 provisions may provide shippers with benefits not enjoyed by Part 157 shippers, it also imposes obligations not incurred by Part 157 shippers. Part 284 requires non-discriminatory access for all shippers, while Part 157 arrangements may include unique terms and conditions. 27/ Important substantive provisions of Order No. 636 therefore do not apply to Part 157 shippers; for example, Part 157 shippers are not responsible for paying transition costs resulting from Order No. 636 and are not subject to pre-granted abandonment. 28/ Of particular relevance to the issue of capacity release, the Commission has a long standing policy of not permitting 26/ Order No. 636 applies only to pipelines operating under Part 284, except that it does not apply to intrastate pipelines and, as discussed later, section 284.242 applies to Part 157 capacity held by pipelines. 27/ Penalties, for instance, must be imposed on all Part 284 shippers, but are not required to be imposed on all Part 157 shippers. 28/ See Order No. 636 at p. 30,459; section 284.221 (d). Docket No. RM91-11-004, et al. - 19 - discounting under Part 157 in order to prevent undue discrimination. Selective discounting can take place only under the comprehensive regulatory scheme established in Part 284. 29/ The capacity releasing mechanism established under Part 284 provided that the rates for released capacity could be discounted. 30/ Indeed, the flexibility to discount rates for released capacity is an integral part of the capacity release mechanism because it promotes the Commission's goal of achieving efficient use of pipeline firm capacity throughout the year. 31/ By discounting, firm shippers will be able to release capacity during the off peak season, when rates for capacity are most likely to be less than the maximum. Since the Part 284 capacity releasing mechanism is predicated on the ability to discount and Part 157 capacity cannot be discounted, Part 157 shippers cannot simply be included in the capacity releasing mechanism established under Part 284. 29/ See Consolidated Gas Transmission Corp., 36 FERC  61,723 (1986), aff'd, 39 FERC  61,112 (1987), aff'd sub nom., Columbia Gas Transmission Corp. v. FERC, 848 F.2d 250 (D.C. Cir. 1988); Interpretation of, and Regulations Under, Section 5 of the Outer Continental Shelf Lands Act Governing Transportation of Natural Gas by Interstate Natural Gas Pipelines on or Across the Outer Continental Shelf, Order No. 509-A, 54 Fed. Reg. 8301, III FERC Stats. & Regs. Preambles  30,848, at p. 31,338 (1989). 30/ Section 284.243 (e) provides that the pipeline must allocate released capacity to the person offering the highest rate (not over the maximum rate). 31/ Order No. 636 at p. 30,418. Docket No. RM91-11-004, et al. - 20 - Some petitioners 32/ argue that the Commission's determination that Part 157 shippers cannot release capacity under section 284.243 is inconsistent with the Commission's requirement that pipelines reassign their upstream Part 157 capacity under section 284.242. 33/ The Commission finds no inconsistency between these determinations because the goals sought to be achieved by the two sections are unrelated. The capacity release mechanism was designed to enable firm shippers to reallocate unused capacity to replacement shippers wishing to obtain that capacity. On the other hand, the required assignment of upstream Part 157 capacity held by pipelines was necessary to implement the unbundling of sales and transportation service. After unbundling, firm shippers on the downstream pipeline would need upstream transportation to obtain access to supplies in the production area. Without upstream capacity, firm shippers on the downstream pipeline would have no means to transport gas from the production area to the downstream pipeline. 34/ The reassignment of upstream pipeline Part 157 capacity, therefore, would have been necessary to implement unbundling fully, regardless of whether a capacity release mechanism was in place. 35/ 32/ New England Power; SoCal Edison. 33/ Order No. 636-A at p. 30,569. 34/ Order No. 636 at p. 30,417. 35/ Additionally, the reassignment of upstream pipeline capacity occurs only once and is permanent, while the capacity releasing mechanism is an on-going program. Docket No. RM91-11-004, et al. - 21 - Brooklyn Union contends that since no party sought rehearing of Order No. 636, which stated that Part 157 capacity could be released, the initial decision to permit such a release became final and could not be repealed without a full notice and comment rulemaking. The Commission finds this argument unpersuasive. In Order No. 636, the regulations and preamble were inconsistent on whether Part 157 shippers could release capacity, and several parties requested clarification on this point. 36/ Based on such requests, the Commission can make modifications in a major rulemaking, such as this one, without embarking on a new round of notice and comment, in particular when parties have the opportunity to comment on the proposed change. 37/ Brooklyn Union was given notice and the opportunity in this round of rehearing to contest the Commission's decision regarding capacity release by Part 157 shippers. Customers on the Great Lakes system 38/ contend that denying Part 157 shippers the ability to release capacity is inconsistent with Commission Order No. 368 requiring capacity release for Part 157 capacity on the Great Lakes system in order to ration capacity effectively. 39/ As the Commission found 36/ See Order No. 636-A at p. 30,565. 37/ See Natural Resources Defense Council, Inc. v. Thomas, 838 F.2d 1224 (D.C. Cir.), cert. denied, 488 U.S. 888, 901 (1988); Connecticut Light & Power Co. v. Nuclear Regulatory Comm'n., 673 F.2d 525 (D.C. Cir), cert. denied, 459 U.S. 835 (1982). 38/ Midland Cogeneration; TransCanada. 39/ 57 FERC  61,141 (1991). Docket No. RM91-11-004, et al. - 22 - in Order No. 636-A, it will not decide case-specific issues in a generic rulemaking. 40/ Case-specific concerns should be addressed in the particular proceeding at issue or in the pipeline's individual restructuring proceeding. Rehearing of Order No. 368 in Great Lakes still is pending before the Commission. Although the Commission is denying the requests for rehearing, the Commission reemphasizes that it finds conversions from individually certificated transportation to open access transportation to be in the public interest. The Commission anticipates that pipelines and their customers will be able to reach agreement on proposals for implementing such conversions and encourages them to do so. 41/ Several petitioners seek clarification of the mechanism by which Part 157 shippers can convert to Part 284 transportation. 42/ Some contend Part 157 shippers should be given a unilateral right to convert at any time. Others argue that the pipeline must agree. Petitioners also raise questions concerning the rate implications of conversions since some Part 157 shippers now pay rates above those charged firm customers under Part 284. They request clarification whether the rates 40/ Order No. 636-A at p. 30,561. 41/ See Transcontinental Gas Pipe Line Corp., 60 FERC  61,388 (1992). 42/ PSE&G; National Fuel; Transco; LILCO; New England Power; Midland Cogeneration. Docket No. RM91-11-004, et al. - 23 - will be converted at the higher incremental level or will be rolled-in. As a general proposition, the details of Part 157 conversions should be worked out in the restructuring proceedings so that the conversions can be coordinated with the other aspects of compliance with Order No. 636. Part 157 shippers should notify the pipeline during the restructuring of their desire to convert. The Commission will expect pipelines to implement such conversions to the maximum extent feasible. However, since rate and other implications of Part 157 conversions are specific to individual pipelines, the Commission cannot specify a universal mechanism for handling these concerns; these issues are more appropriately addressed in individual cases. B. Capacity Release In Order No. 636, the Commission added section 284.243 requiring open access pipelines to establish a mechanism that permits firm transportation customers under Part 284 to release all or part of their capacity to a replacement shipper. In Order No. 636-A, the Commission added section 284.243(h) providing an exception from the bidding requirements of section 284.243 for short-term capacity releases, modified section 284.243(d) to require pipelines to post offers to purchase capacity, and addressed numerous requests for rehearing and clarification. Except when necessary to respond to petitioners' arguments on rehearing and clarification of Order No. 636-A, the Commission Docket No. RM91-11-004, et al. - 24 - will not repeat here the discussion of the capacity release mechanism in Order Nos. 636 and 636-A. 1. Maximum Rate Bids CNG requests clarification that if a designated replacement shipper under a prearranged deal bids the maximum rate, the pipeline need not post the transaction on the EBB or, in the alternative, could post the transaction within 48 hours of the completed transaction. The Commission will clarify the appropriate handling of prearranged deals at the maximum rate (meeting all terms and conditions of the release). One of the primary goals of the capacity release provisions was to provide timely notice of all capacity reallocations and CNG has provided no basis for concluding that such posting would be any more burdensome than posting other listings of capacity available for release. Thus, CNG's request for an exception from the posting requirements for capacity released at the maximum rate is denied; under section 284.243(d), pipelines must post immediately all capacity available for release, including those involving designated replacement shippers paying the maximum rate. 43/ However, when a prearranged deal is at the maximum rate, and meets all other terms and conditions of the release, no other shipper can make a better bid for that capacity, and, therefore, subjecting such a release to the bidding periods in the pipeline's tariff could unnecessarily delay implementation of the 43/ Releases falling under the short-term exception in section 284.243(h) must be posted as soon as possible, but not later than 48 hours after the transaction commences. Docket No. RM91-11-004, et al. - 25 - release. Accordingly, the Commission expects pipelines to adopt procedures to provide for prompt implementation of prearranged deals at the maximum rate. 2. Exception for Short-Term Releases In Order No. 636-A, the Commission promulgated new section 284.243(h) providing that parties could arrange for releases of capacity of less than one calendar month without compliance with the bidding requirements of section 284.243. Notice of the release would have to made as soon as possible, but no later than 48 hours after the release transaction begins. While petitioners generally were supportive of the short-term exception, they have requested rehearing on two aspects of the provision. a. Length of release Several petitioners request that the exception be extended to one full month so that it will conform better to the industry's current practice in which contracts for spot market gas cover a full month. 44/ The Commission denies the request for rehearing on this point. The short-term exception was designed to ensure that firm shippers have the ability to release capacity in unforseen situations when they cannot anticipate having capacity available. It was not designed as a substitute for the section 284.243 bidding procedures for normal industry transactions. The Commission remains convinced that pipelines can design capacity release mechanisms to accommodate the industry's standard monthly contracting process. Indeed, in most 44/ AGA; Natural; NYSE&G; Peoples Gas. Docket No. RM91-11-004, et al. - 26 - cases, the Commission expects that pipelines can implement capacity releases mechanisms under the regulations that will accommodate releases for one day or less anytime during a month and provide for consummation of such transactions within twenty- four hours of posting. 45/ b. Prohibition on roll-overs In section 284.243(h)(2), the Commission prohibited roll- overs or extensions under the exception as well as re-releases of capacity to the same replacement shipper within 30 days of the first release. Parties wishing to extend such releases would have to comply with the posting and bidding requirements of the rule. The Commission included these prohibitions on roll-overs to protect the integrity and allocative efficiency of the capacity release mechanism by preventing parties from avoiding the bidding requirement by extending short-term releases. 46/ Several petitioners request the Commission to remove these prohibitions on roll-overs. 47/ They contend that an exigency may reoccur within a month, requiring a re-release of capacity to the same replacement shipper. AGD gives, as an example, a power 45/ See Order No. 636-A at p. 30,554. 46/ The Commission found that prearranged deals ordinarily must be subject to the bidding requirements of section 284.243 to preserve allocative efficiency by ensuring that capacity is allocated to the shipper placing the highest value on that capacity. Order No. 636-A at pp. 30,554-55. 47/ AGA, AGD, CNG, Northern States; PSE&G; UGI; UDC; Washington Gas. Docket No. RM91-11-004, et al. - 27 - outage resulting in excess capacity to an LDC which could recur later in the month. The Commission denies the requests for rehearing. In the Commission's judgment, the need to prevent circumvention of the bidding process should not be sacrificed to accommodate the remote possibility that an unforseen situation will reoccur more than once a month. Moreover, the Commission has provided flexibility to accommodate even such remote exigencies. The releasing shipper could release capacity to another replacement shipper under the short-term exception. As discussed previously, the releasing shipper also could enter into a pre-arranged deal with the same replacement shipper at the maximum rate. Such a deal would not be subject to any bidding periods and the Commission expects that pipelines will be able to provide for prompt implementation of such deals. Petitioners also contend that some replacement shippers require quick access to short-term capacity on a recurring basis and that the prohibition on roll-overs would preclude such transactions from taking place. As noted above, the short-term exception was not intended to permit parties to structure on- going transactions involving recurring access to capacity over short periods. Such ongoing, recurring transactions must be subject to bidding (unless at the maximum rate) and the other non-discriminatory requirements of the capacity releasing mechanism to ensure that capacity is allocated to the replacement shipper placing the highest value on the capacity. Docket No. RM91-11-004, et al. - 28 - Consolidated Minerals, on the other hand, contends that the Commission's prohibition on roll-overs is not strong enough to prevent circumvention of the non-discriminatory bidding requirements of the capacity release mechanism. It requests stronger provisions, such as volumetric limitations or further limits on the frequency with which parties can use this process. The Commission will not impose volumetric limits or further restrictions to prevent roll-overs, because such restrictions would place burdens on short-term releases that do not appear necessary to prevent circumvention of the bidding process. 3. Requests for Additional Exceptions In Order No. 636-A, the Commission rejected requests for exceptions from its rule that a replacement shipper under a prearranged deal has priority to released capacity so long as the prearranged replacement shipper meets the maximum price bid. 48/ American Natural Gas and Consolidated Minerals reiterate the request for alternative priority mechanisms, arguing, in particular, that providing prearranged deals with priority to released capacity on capacity constrained pipelines will result in an unfair allocation of capacity. The Commission reaffirms its position in Order Nos. 636 and 636-A and will not provide for alternative priority provisions on capacity constrained pipelines. Such an exception could involve numerous pipelines or portions of pipelines and would defeat the efficiency goals of the capacity release mechanism. As stated in 48/ Order No. 636-A at pp. 30,554-56. Docket No. RM91-11-004, et al. - 29 - Order No. 636-A, prearranged deals promote efficiency by providing firm shippers with the incentive to market actively their unneeded firm capacity rather than simply posting it on the bulletin board. However, the Commission sought to preserve the allocative efficiency of the process by requiring that prearranged deals be subject to the bidding requirements of section 284.243 so that the available capacity is allocated to its highest valued use. 49/ Washington Gas suggests that, in Order No. 636-A, the Commission limited the use of prearranged deals to agreements between LDCs and end-users and suggests that this limitation fails to recognize that LDCs may need to enter into pooling or exchange arrangements among themselves to provide peaking service or emergency replacement of supplies in the event of a force majeure outage. 50/ It further requests that the Commission permit LDCs to enter into such exchange or pooling arrangements without EBB posting. Washington Gas is not correct that prearranged deals are limited to arrangements between LDCs and end-users; the section cited by Washington Gas merely referred to deals between LDCs and end-users as an example of one type of prearranged deal. LDCs can enter into prearranged deals with other LDCs or any other 49/ In Order No. 636-A, the Commission denied a similar request for according shippers on a pipeline's firm queue with priority access to released capacity. Order No. 636-A at p. 30,555. 50/ Washington Gas cites the discussion in Order No. 636-A at p. 30,555. Docket No. RM91-11-004, et al. - 30 - potential shippers. However, Washington Gas has not demonstrated that so-called pooling and exchange arrangements, or similar arrangements, are so different from other prearranged deals that they warrant an exception from the posting requirements. All prearranged deals for release of capacity must either fall within the short-term exception in section 284.243(h) or comply with the posting and bidding requirements of section 284.243. 4. Terms and Conditions Order No. 636 provided that releasing shippers could establish terms and conditions specific to their releases, such as the right to recall the use of capacity under certain conditions, for instance, if the temperature dropped below a specified degree. 51/ In Order No. 636-A, the Commission clarified a number of issues relating to terms and conditions. The Commission stated that releasing shippers could include reasonable and non-discriminatory terms and conditions and could include provisions for determining the highest valued or best bid. The Commission required that all such terms and conditions must be posted on the pipeline's EBB, be objectively stated, be applicable to all potential bidders, and relate solely to the details of acquiring capacity on interstate pipelines. 52/ With respect to the determination of best bids, the Commission also required the pipelines to include in their tariffs an objective and non-discriminatory economic standard for 51/ Order No. 636 at p. 30,418. 52/ Order No. 636-A at p. 30,557. Docket No. RM91-11-004, et al. - 31 - determining best bids. Releasing shippers could avail themselves of this standard, but were not required to do so. CIG contends the Commission erred in permitting the releasing shipper to establish terms and conditions for determining best bids and should, instead, require the pipelines and their customers to craft a generic set of evaluation criteria for determining best bids. It asserts that allowing the releasing shipper to dictate bid evaluation criteria will burden the administration of the capacity release program and could lead to discriminatory conduct, for example, if releasing shippers favor their own end-users. The Producer Associations argue that the capacity release mechanism should protect small shippers and contend that bid evaluation should be done solely on the basis of price without consideration of the volumes bid by any shipper. Under its proposal, a shipper bidding a high price for a small volume would receive that capacity even though another shipper bid a somewhat lower price for the entire package. The Commission denies the requests for rehearing. In Order No. 636-A, the Commission recognized that a variety of releasing conditions might exist and that one methodology for evaluating bids might not apply equally to all releases. 53/ In balancing the need to permit releasing shippers to develop terms 53/ Order No. 636-A at p. 30,556. For example, the Commission recognized that in some circumstances, releasing shippers may be releasing capacity on both downstream and upstream pipelines. Order No. 636-A at p. 30,558 n.144. Docket No. RM91-11-004, et al. - 32 - and conditions that would maximize the efficiency of their capacity releases against the need to prevent discrimination, the Commission concluded that it would not prohibit releasing shippers from developing objective, non-discriminatory terms and conditions to determine the best bid. 54/ The Commission, however, specifically provided that such terms and conditions could not favor one set of buyers or grant price preferences or credits to certain buyers. The Commission believes such regulations are sufficient to prevent undue discrimination. Applying objectively stated criteria also should pose little administrative difficulty. Because releasing situations are so varied, the Commission will not circumscribe the options of the parties by proscribing particular evaluation methodologies, such as those suggested by the Producer Associations. Other petitioners raise additional issues with respect to terms and conditions. UGI and UDC reiterate the argument advanced on rehearing of Order No. 636 that releasing shippers should be allowed to establish bid evaluation criteria that reflect all factors affecting the releasing shipper; UGI contends, for example, that LDCs should be able to establish criteria to permit them to recover the cost of their own facilities that would become effectively stranded if an off- system replacement shipper acquired the LDC's pipeline capacity. PG&E contends that parties should be able to agree on prearranged 54/ The pipeline's tariff standard for evaluating bids would apply when the releasing shipper did not specify its own standard. Docket No. RM91-11-004, et al. - 33 - deals involving terms and conditions that are not posted as conditions of the capacity release. ANR requests guidance on issues relating to recall rights, such as who will be responsible for invoking recall rights and whether the pipeline will be insulated from liability associated with proper recalls. It requests clarification that pipelines are free to devise tariff provisions to determine liability for imbalances associated with recalls. The Commission denies these requests. The Commission continues to hold the same position it stated in Order No. 636-A. All terms and conditions for releases, including those providing for recalls, must be posted on the EBB, must be objectively stated, must apply only to release of pipeline capacity, must not prefer any shipper, such as an end-user, over other shippers, and cannot take into account the use of an LDC's own facilities. As the Commission pointed out in Order No. 636-A, an LDC can negotiate a prearranged deal with an end-user and the end-user will receive the capacity as long as it matches the best offer. 55/ Issues of defining rights and responsibilities relating to recalls should be considered in the restructuring proceedings and included in the tariff provisions in the pipelines' compliance filings. 5. Volumetric Bids Western Resources and the Producer Associations request reconsideration of a statement in Order No. 636-A which they 55/ Order No. 636-A at p. 30,555. Docket No. RM91-11-004, et al. - 34 - interpret as forbidding a releasing shipper from accepting bids for released capacity on a one-part volumetric basis. In Order No. 636-A, the Commission addressed a request to establish the maximum rate for released capacity as equal to the maximum rate for interruptible transportation. In response, the Commission stated that the maximum rate for released capacity normally would be the maximum firm rate since the releasing shipper is releasing firm capacity and the replacement shipper is paying a monthly reservation charge. 56/ The Commission, however, was addressing the maximum rate issue only with respect to this common releasing scenario. As a general policy, the Commission seeks to promote competition between pipeline capacity and released capacity. To facilitate such competition, the Commission will not foreclose released capacity from being bid on a volumetric basis. The Commission will clarify that parties to the restructuring proceedings can propose mechanisms that would permit shippers to release capacity on a volumetric basis if they choose to do so. 6. Use of Released Capacity for Backhauls WGM requests clarification that a releasing shipper can release capacity it currently uses as a forward haul for use as a backhaul, if such use is operationally feasible. WGM contends that a backhaul resulting in a change in the flow direction should be permitted if such a change is operationally feasible or if the shipper is willing to pay the cost of making it feasible. 56/ Order No. 636-A at p. 30,560. Docket No. RM91-11-004, et al. - 35 - In Order Nos. 636 and 636-A, the Commission established the general principle that firm shippers should be able to make full use of their pipeline capacity through release transactions. The Commission used as an example a releasing shipper with capacity between the Gulf of Mexico and New York releasing capacity from the Gulf to Atlanta; this transaction would then free up an equal amount of capacity from Atlanta to New York which the shipper could release or use itself. 57/ The releasing shipper could release its capacity in this manner even though the total amount of gas delivered from the two transactions could exceed its total reservation quantity from the Gulf to New York. This principle should be applied to capacity release arrangements between releasing and replacement shippers that involve backhauls or exchanges. The Commission, however, cannot make a generic determination on WGM's questions with respect to physical changes in flow direction, since operational questions must be determined on the basis of the characteristics of each pipeline. 7. Credits Exceeding Reservation Fee Section 284.243(f) provides that releasing shippers receive the full proceeds from any release. In Order No. 636-A, the Commission denied requests for modifying this principle as applied to shippers paying discounted rates. 58/ Three petitioners seek rehearing of the Commission's determination that shippers holding discounted contracts should receive the full 57/ Order No. 636-A at p. 30,559 n.151. 58/ Order No. 636-A at pp. 30,561-62. Docket No. RM91-11-004, et al. - 36 - proceeds from a release, making essentially the same arguments addressed in Order No. 636-A. 59/ They contend that the pipeline entered into discounted contracts based on specific circumstances in order to retain firm transportation that was in danger of being lost, the pipeline will be harmed if these customers could release their capacity to other shippers, and the holders of discounted contracts would enjoy an advantage over shippers paying maximum rates. For the reasons stated in Order No. 636-A, the Commission again denies the requests for rehearing. Holders of discounted capacity have no competitive advantage in the release market over shippers paying maximum rates, since all firm shippers will be releasing capacity under the same conditions. 60/ Further, as the Commission pointed out, pipelines are no worse off if holders of discounted contracts can release capacity; the pipeline still receives the same total reservation charges and revenue as it did prior to the release. 8. Capacity Releasing by Small Customers Paying a One-Part Rate In Order No. 636-A, the Commission clarified that pipelines offering a small customer sales or firm transportation service at an imputed load factor rate must continue to offer firm and no- 59/ Arkla; CIG; Enron. 60/ Replacement shippers will be able to bid for all available capacity up to the same maximum rate and therefore will have no incentive to favor a release from a shipper holding discounted capacity over a release from a customer paying the maximum rate. Docket No. RM91-11-004, et al. - 37 - notice transportation on the same basis. 61/ Several petitioners request rehearing or clarification, contending that the small customers electing service under a one-part volumetric rate should be prohibited from releasing capacity under the capacity release mechanism of section 284.243. 62/ They contend that permitting such releases would provide these customers with a double benefit or would provide them with competitive advantages in the releasing market. If the Commission permits small customers to release capacity, the Northern Distributor Group contends that the release should be at a rate equal to the pipeline's two-part rate, while Southern argues that the small customers should be required to pre-pay their one-part rate prior to releasing. Prior Energy, on the other hand, argues that small customers should be able to release capacity and requests clarification of the maximum rate for such releases. Because small customers paying a one-part volumetric rate are not paying a reservation charge to reserve the capacity, the Commission clarifies that they cannot release that capacity under the capacity release mechanism. 63/ However, small customers paying a two-part rate including a reservation fee will be permitted to release that capacity. The parties in the 61/ Order No. 636-A at p. 30,600. 62/ Atlanta Gas; Northern Distributor Group; Southern. 63/ The capacity release mechanism was designed so that payments from a replacement shipper will be credited to a releasing shipper's reservation charge. See section 284.243(f). Docket No. RM91-11-004, et al. - 38 - restructuring proceedings should work out details relating to releases of capacity under small customer two-part rate schedules, including the development of procedures to enable customers served under a one-part rate schedule to convert to a two-part rate schedule if they choose to convert in order to release capacity. 9. Responsibility for Penalties Section 284.243(f) provides that, unless the pipeline agrees otherwise, a releasing shipper remains liable under its contract with the pipeline. In Order No. 636-A, the Commission clarified that if a replacement shipper defaults, the releasing shipper is responsible to the pipeline for the continued payment of reservation charges, but not for penalties or other charges incurred by the replacement shipper as a result of its own conduct. 64/ Arkla requests clarification that releasing shippers still will be ultimately liable for monthly surcharges, such as GSR charges, and other charges not the result of the replacement shipper's conduct. CNG requests clarification that the Commission was not predetermining the issue of a releasing shipper's liability and that a releasing shipper can be held liable for penalties if it is partly responsible for the conduct. In Order No. 636-A, the Commission set out the general parameters for determining whether releasing shippers should be liable for penalties and other charges in the event of defaults by the replacement shippers. As a general matter, releasing 64/ Order No. 636-A at p. 30,565. Docket No. RM91-11-004, et al. - 39 - shippers are ultimately responsible for items included in reservation charges (amounts for which they would be responsible if no release took place), but are not responsible for assessments included in the usage charge or penalties caused by the conduct of replacement shippers. For example, releasing shippers ultimately would be responsible for payment of a full reservation fee and any GSR demand surcharge applicable to that fee. The parties in the restructuring proceedings should craft appropriate tariff language along those lines. 10. Contractual Privity UGI and UDC repeat the request, denied in Order No. 636-A, that the Commission establish contractual privity between releasing and replacement shippers. UDC suggests that releasing shippers be able to include, as a term and condition of release, an indemnification agreement between the releasing and replacement shipper. As determined in Order No. 636-A, the Commission will not compel pipelines to require contractual privity between releasing and replacement shippers, since privity and subrogation are matters of state law and should be governed by that law and the contracts of the releasing shipper and the pipeline. 65/ Releasing shippers can include any non- discriminatory term and condition in their offers to release and therefore could include the requirement for replacement shippers 65/ "[P]robably there are few doctrines better established than that a surety who pays the debt of another is entitled to all the rights of the person he paid to enforce his right to be reimbursed." Pearlman v. Reliance Insurance Co., 371 U.S. 132, 136-37 (1962). Docket No. RM91-11-004, et al. - 40 - to enter into an indemnification agreement, but the interpretation of any such agreement would be a matter for state law. 11. Releasing Shipper's Liability Barclays and Mojave request clarification that the capacity releasing mechanism will not impair the ability of pipelines to recover their full cost-of-service. Barclays seeks assurance that a project financed pipeline will be protected from a shortfall in price and in contract duration when capacity is reassigned. Mojave seeks clarification that it will be able to tailor its capacity release program to deal with case specific issues stemming from the rate design and contracts on its system so as to ensure its ability to recover its cost-of-service. As discussed in Order No. 636-A, the capacity release mechanism promulgated in section 284.243 does not change the relationship between the firm capacity holder (releasing shipper) and the pipeline and therefore will not result in any diminution of revenue received by the pipeline. Section 284.243(f) provides that the contract of the releasing shipper and the pipeline still remains in full force and effect. 66/ As the Commission explained in Order No. 636-A, the releasing shipper is therefore 66/ Similarly, the Commission clarified in Order No. 636-A that for capacity reallocations on project financed pipelines under sections 284.14(e) and 284.242, an assignor of capacity must serve as a guarantor of payments under the existing contract unless creditor approval of the assignment is obtained, where necessary, and the project financed pipeline agrees to release the assignor from liability. Order No. 636-A at p. 30,674. Docket No. RM91-11-004, et al. - 41 - ultimately responsible for paying the pipeline the full amount of its reservation fee. 67/ The Commission will consider Mojave's or any other case specific concerns in the restructuring proceedings for each pipeline. 12. Interruptible Rate Design In Order No. 636-A, the Commission addressed issues regarding the development of a rate design for interruptible transportation after the implementation of a capacity release mechanism. 68/ The Commission traditionally has required that a pipeline recover a certain amount of fixed costs (its revenue responsibility) from interruptible transportation based on a projected level of interruptible throughput. On rehearing of Order No. 636, several parties were concerned about the difficulty in accurately projecting interruptible throughput and revenue responsibility when the pipelines and their customers have had no experience with the effect of capacity releasing on the throughput levels for interruptible transportation. The release of firm capacity also may affect the rates charged for interruptible transportation since the competition from released capacity might require the pipelines to offer greater discounts 67/ Order No. 636-A at p. 30,560. The pipeline will bill the replacement shipper for the amount it bid for the reservation fee (to be credited to the releasing shipper) and for the applicable usage fee. For accounting purposes, the pipeline bill to the releasing shipper should reflect a simultaneous credit to the releasing shipper for the reservation fee billed the replacement shipper. If the replacement shipper defaults, the pipeline will bill the releasing shipper for the unpaid amount on the next bill. 68/ Order No. 636-A at pp. 30,562-63. Docket No. RM91-11-004, et al. - 42 - for interruptible transportation than they had in the past. 69/ In Order No. 636-A, the Commission found that promoting competition between released and interruptible transportation was an important policy objective. The Commission recognized that competition between released firm and interruptible transportation, together with the potential use of seasonal contract demands, could affect the level of interruptible transportation and provided that the throughput mix between interruptible and firm transportation should be considered in the restructuring proceedings. 70/ In handling this issue, the Commission stated that the parties to the restructuring proceedings could consider a variety of approaches, such as agreeing on an appropriate level of throughput for interruptible transportation or some type of revenue crediting mechanism. Although not mandating the adoption of any technique, the Commission provided an outline of a potential revenue crediting approach under which the pipeline would allocate no costs or revenue responsibility to interruptible service, but would credit firm shippers with interruptible revenue generated. The firm shippers would receive the credit because under this allocation 69/ For example, if the projected revenue responsibility for interruptible transportation were higher than actual experience, the pipeline might not recover the fixed costs assigned to interruptible transportation. On the other hand, if the projection were too low, the pipeline could recover much more than the costs allocated to the interruptible service. 70/ Order No. 636-A at p. 30,563. Docket No. RM91-11-004, et al. - 43 - of costs, the firm rate would recover all the fixed costs of the pipeline. Several petitioners contend that the Commission erred in even suggesting that a revenue crediting mechanism might be appropriate for dealing with the difficulty of projecting interruptible revenues. 71/ They contend that revenue crediting is inconsistent with section 284.7(d)(2) of the Commission's regulations, which provides that rates must be designed to recover costs on the basis of projected units of service. They assert that revenue crediting conflicts with the purpose of this section, because it provides the pipeline with no incentive to provide the service. LILCO argues that interruptible transportation should be subject to the same posting and bidding requirements as released capacity to ensure that neither interruptible nor released capacity will have an inherent advantage over the other service. Although not entirely clear from its comments, LILCO appears to propose that pipelines be obligated to sell interruptible service to the highest bidder, rather than being able to selectively discount. The petitioners requesting rehearing have not been aggrieved by the suggestion that the Commission would consider a revenue crediting approach proposed in a specific restructuring proceeding. In implementing its regulations, the Commission will not adopt rigid rate-making methodologies that fail to reflect the reality of the market or the intent of its regulations. When 71/ Arcadian; ConEd; Industrial Groups. Docket No. RM91-11-004, et al. - 44 - the Commission permitted discounting of interruptible transportation, it had to adopt rate-making methodologies for projecting revenue responsibility that would not penalize the pipeline for discounting interruptible service. 72/ The Commission suggested a similar revenue crediting mechanism as a means of dealing with the difficulty of estimating discounting. 73/ The Commission will not foreclose the parties in the restructuring proceedings from considering revenue crediting or other approaches, such as LILCO's proposal for bidding on interruptible transportation, as methods for dealing with the uncertainties resulting from the implementation of a capacity releasing mechanism. 74/ If the Commission adopts a revenue crediting or other approach in a pipeline's compliance filing, it will reevaluate any such mechanism in the pipeline's next rate case after the parties have experience with capacity releasing. Questar requests clarification that under a potential revenue crediting approach the pipeline would not have to credit firm shippers for the portion of interruptible revenue reflecting its variable costs (usage charge). The Commission will clarify 72/ See Associated Gas Distributors v. FERC, 824 F.2d 981, 1012 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988). 73/ Interstate Natural Gas Pipeline Rate Design, 47 FERC  61,295, at pp. 62,056-57 & n. 49 (1989). 74/ In response to LILCO's request that interruptible capacity be subject to the same posting requirements as released capacity, the Commission notes that section 284.9(b)(3)&(4) already requires pipelines to post information about interruptible service on an EBB. Docket No. RM91-11-004, et al. - 45 - that the revenue credit should apply only to the extent that revenues from interruptible transportation recover costs allocated to firm transportation. Pipelines would be able to retain the usage component of the interruptible rate so long as the usage charge is calculated on the basis of total throughput. 13. Administrative Issues Involving Capacity Release a. Electronic bulletin board In Order No. 636, the Commission required that pipelines conduct their capacity release programs through electronic bulletin boards (EBBs). In Order No. 636-A, the Commission directed the pipelines to provide for interactive EBBs in their compliance filings or to provide a reasonable explanation of their inability to do so. 75/ The Commission further encouraged the industry to develop uniform standards and conventions for EBBs and committed to establish a technical conference to determine the industry's progress in developing interactive, user-friendly EBBs and uniform EBB standards. Williston and ANR request clarification of the requirements needed to make EBBs interactive, since they claim capacity release is not simply a transaction between the releasing and replacement shipper, but requires some pipeline involvement. ANR suggests that, in certain situations, transactions could be consummated on the EBB without any, or with limited, pipeline intervention. 75/ Order No. 636-A at p. 30,549-50. Docket No. RM91-11-004, et al. - 46 - The Commission did not seek to define the precise parameters of an interactive EBB, believing that the industry, through the restructuring proceedings, is in the best position to reach such determinations. As a general matter, the Commission expects pipelines to provide EBBs that will permit posting of capacity available for release and bids for that capacity directly on the EBB, and electronic confirmation of the completed transaction on the EBB. The Commission envisions that, in the near future, all pipelines should be able to provide for entire transactions to take place using EBBs, including, for example, electronic contractual consummation of completed transactions. UGI and the Industrial Groups argue that EBBs are the key to capacity reassignment and that the Commission must take action to ensure that EBBs on different pipelines are coordinated. They urge the Commission to defer mandatory bidding through EBBs until a coherent national or regional EBB policy is established. UGI reasserts its position that facilities and personnel running the EBB should be separate from those used for managing interruptible transportation to ensure that the pipelines do not abuse the EBB process for competitive purposes. The Commission will not defer the requirement for conducting capacity release transactions through an EBB. The capacity release mechanism is an integral part of the restructuring required by Order No. 636 and therefore must be implemented at the same time as the other requirements of Order No. 636 to ensure that the parties have a mechanism for reallocating Docket No. RM91-11-004, et al. - 47 - capacity. 76/ While the Commission believes that EBB technology and coordination may improve over time, it is convinced that the pipelines currently have the ability to develop effective EBBs and capacity release mechanisms. The Commission also believes that the industry, not the Commission, is in the best position to develop the specific technical standards for EBBs and for coordination among EBBs. The Commission considers its most effective role as facilitating the process of improving EBBs by bringing those with the technical expertise together in a technical conference. The Commission adheres to its determination in Order No. 636-A that separation of EBB personnel is not necessary to prevent the pipelines from giving undue preference to their own interruptible transportation. As discussed in Order No. 636-A, the Commission has taken a number of steps which it believes are all that is currently needed to address this issue. 77/ b. Implementation of releases ANR and CIG request clarification that pipelines can adopt procedures for capacity release that provide sufficient advance notice to accommodate the pipelines' contract administration process. The Commission is not sure whether these requests apply 76/ As discussed in Order No. 636-A, the Commission will not permit reallocations of capacity to take place without compliance with the posting and bidding requirements of section 284.243 to ensure that capacity reallocations can be effectively monitored for possible undue discrimination. Order No. 636-A at pp. 30,552-53. 77/ Order No. 636-A at pp. 30,563-64. Docket No. RM91-11-004, et al. - 48 - to releases under the short-term exception or under the general bidding requirements of the capacity release mechanism. With respect to the short-term exception under section 284.243(h), the Commission adopted this exception specifically to avoid any impediments to short-term releases of capacity and therefore the pipelines should not adopt any procedures that would interfere with the execution of releases under the short- term exception. With respect to releases under the general provisions of section 284.243, the Commission reiterates its position in Order No. 636-A that, in most instances, pipelines should be able to provide procedures to accommodate short-term releases on the EBB so that release transactions can take place for one day or less any time during the month and that such transactions can be finalized within 24 hours. 78/ Pipelines must justify any provisions that do not meet this standard. In Order No. 636-A, the Commission suggested that the parties to the restructuring proceedings consider pre-qualification for creditworthiness as a means to expedite releases, 79/ and they similarly should consider appropriate mechanisms for dealing with contract execution and other issues so as to ensure a viable capacity release mechanism. c. Administrative fee In Order No. 636-A, the Commission provided that pipelines could not recover the costs of operating their capacity release 78/ Order No. 636-A at p. 30,554. 79/ Order No. 636-A at p. 30,558. Docket No. RM91-11-004, et al. - 49 - programs through a separately stated administrative fee, but instead should include the fixed costs of their programs in their rates. The pipelines, however, could charge a fee for using the EBB that reflected the variable costs of such use. 80/ In addition, the Commission required that pipelines must permit posting on the EBB of offers to purchase capacity and stated that the shipper posting such offer would have to pay any posting fee required. 81/ CIG and Tenneco request rehearing, contending that the Commission should permit a separately stated administrative fee for using the EBB that covers fixed and variable costs so that only shippers making use of the EBB would pay the costs of providing the service. ANR and CNG request clarification that the separately stated usage fee reflecting variable costs would be charged to the users of the EBB, not through commodity rates. CNG also requests clarification that the Commission's reference to a posting fee for offers to purchase capacity refers to the separately-stated usage fee for use of the EBB. The Commission required the pipelines to recover the fixed costs for operating the capacity release program through their rates to ensure that the market for released firm capacity was not unduly burdened by high rates for using the EBB and thereby placed at a disadvantage to interruptible capacity. The Commission continues to find this rationale persuasive and 80/ Order No. 636-A at p. 30,564. 81/ Order No. 636-A at p. 30,565. Docket No. RM91-11-004, et al. - 50 - therefore denies CIG's and Tenneco's requests for rehearing. The Commission reiterates that the pipelines may charge a separately stated usage fee, reflecting only the variable costs of usage, charged to those using the EBB. 82/ The Commission clarifies that shippers posting offers to purchase capacity can be charged only the same usage fee assessed other users of the EBB. 14. Retention of Capacity Brokering In Order Nos. 636 and 636-A, the Commission concluded that, with the adoption of a capacity release mechanism, it should not approve new individually authorized capacity brokering and other capacity assignment certificates. In addition, in a separate order issued April 8, 1992, the Commission amended the terms and conditions of existing capacity brokering and other assignment programs to conform to the capacity reallocation mechanisms adopted in Order No. 636. 83/ The AGA argues that the Commission should allow the parties to the restructuring proceedings to develop workable alternatives to capacity releasing under the rule and not ban programs similar to capacity brokering. The AGA concludes that "where state commissions are actually regulating, or seek to regulate, 82/ Pipelines need to demonstrate that the costs included in the EBB usage charge reflect only the variable costs of customers' use of the EBB. 83/ Algonquin Gas Transmission Co., 59 FERC  61,032 (1992), reh'g denied, 60 FERC  61,113 (1992). Docket No. RM91-11-004, et al. - 51 - capacity brokering, it would be beneficial to allow capacity brokering programs to develop under state purview." 84/ For the reasons given in Order Nos. 636 and 636-A and in the Algonquin Gas Transmission Co. orders of May 8 and August 3, 1992, 85/ the Commission denies AGA's request for rehearing. In brief, the Commission believes that exclusive federal regulation of interstate capacity assignment programs is necessary to establish a uniform capacity reallocation program, which the Commission can monitor to ensure that the secondary transportation capacity market operates without discrimination. 15. Buy/Sell Arrangements The Commission concluded in El Paso Natural Gas Co. that it has jurisdiction over buy/sell arrangements where, for example, an LDC purchases gas in the production area from an end user or merchant designated by an end user, ships the gas on its (the LDC's) own capacity, and sells the gas to the end user at the retail delivery point. 86/ In Order Nos. 636 and 636-A, the Commission concluded that as of the effective date of a pipeline's compliance with Order No. 636, no new buy/sell arrangement can be consummated and all allocations of capacity must be done under the capacity releasing mechanism. 84/ Petition at 4. 85/ 59 FERC  61,032 and 60 FERC  61,113 (1992). 86/ 59 FERC  61,031 (1992), order denying reh'g and clarifying prior order, 60 FERC  61,117 (1992), appeal docketed, Windward Energy & Marketing Co. v. FERC, No. 92-1361 (D.C. Cir. Aug. 13, 1992). Docket No. RM91-11-004, et al. - 52 - PSE&G asks the Commission whether the Commission's ban applies only to LDCs or also applies to marketers and producers. The Commission concludes that the prospective ban on buy/sell arrangements applies to all holders of capacity on an interstate pipeline for the reasons set forth in El Paso, supra. The Commission sees no difference between LDCs and other capacity holders with respect to the Commission's determination "that to permit the coincidence of buy/sell transactions with capacity reallocation under the mechanism established in Order No. 636 would interfere with our objectives in creating a nationally uniform [capacity release] program." 87/ 16. Jurisdiction Over Municipalities In Order No. 636-A, the Commission concluded that while municipalities are beyond the jurisdiction of the Commission, they may release capacity on a pipeline only by complying with the procedures pertinent to the pipeline's releasing mechanism because the conditions of the program pertain to the mechanics of the release by and through the pipeline. The APGA and Citizens Gas seek rehearing of the Commission's conclusion that municipalities must comply with the requirements of a pipeline's capacity release program. They argue that the Commission has exceeded its authority under the NGA because a municipality is not a natural gas company as defined in NGA section 2. They add that the Commission has expressly held in two orders with respect to capacity brokering that municipalities 87/ 60 FERC  61,117 at p. 61,384. Docket No. RM91-11-004, et al. - 53 - are not subject to the Commission's NGA jurisdiction. 88/ They maintain that the difference between capacity brokering and releasing -- that is, that under the former assignments may be effected directly while under the latter may only be effected through the pipeline -- does not modify the NGA's exemption for municipalities. The APGA maintains that municipalities may release capacity without restriction on the contractual price negotiated or the choice of buyer. Citizens Gas contends that municipalities may not be subjected to Commission action that would restrict substantially their ability to release, including by implication buy-sell agreements. The Commission denies rehearing. While the Commission has no NGA jurisdiction over municipalities as gas sellers or transporters, the Commission has exclusive preemptive jurisdiction over access to interstate pipeline capacity. 89/ The Commission's authority over transportation by a pipeline under the NGA includes the eligibility criteria for becoming a shipper. 90/ The Commission sees this as no different from its authority to determine terms and conditions of service, which 88/ Texas Eastern Transmission Corp., 51 FERC  61,170 (1990), Texas Gas Transmission Corp., 55 FERC  61,208 (1991). 89/ See the discussion in El Paso Natural Gas Co., 60 FERC  61,117 at p. 61,384 (1992). 90/ Cf. Mississippi River Transmission Corp. v. FERC, 969 F.2d 1215, 1217 (D.C. Cir. 1992) (The Commission's authority over the transportation of gas in connection with an unregulated direct sale "is beyond dispute.") Docket No. RM91-11-004, et al. - 54 - the APGA concedes municipalities should abide by. 91/ Whether the shipper is a natural gas company is irrelevant to the Commission's plenary authority over access to interstate pipeline capacity under the NGA. The cases cited by petitioners are not on point. It is true that they hold that municipalities need not be certificated in a capacity assignment program and that they need not comply with conditions imposed upon program participants as transporters. However, as the Commission concluded in Order No. 636-A, those cases are not controlling when the Commission has exercised its authority to require that releases be effected by and through the pipeline. In that event, the capacity releasing mechanism in its entirety must be complied with just as a municipality must comply with any other pipeline term or condition of service. To allow municipalities to freelance their releasing would not be in harmony with the Commission's goals of a uniform capacity reallocation program to eliminate discrimination in the assignment of pipeline capacity. Of course, the municipalities are not covered by the Commission's grant of a limited jurisdiction certificate in section 284.243(g) of the Commission's regulations. Finally, to grant APGA's request would create a regulatory gap that would frustrate the non-discrimination feature of Order No. 636. Most municipalties are self-regulated (i.e., not 91/ Cf. FPC v. Louisiana Power & Light Co., 406 U.S. 621 (1972) (The Commission has authority over curtailment programs under its jurisdiction over transportation). Docket No. RM91-11-004, et al. - 55 - subject to state commission authority). To grant APGA's request would, therefore, create a class of shipper controlling access to interstate capacity without either federal or state commission review. This regulatory gap would give municipalities a competitive and otherwise non-market advantage over all other shippers. Simply put the fundamental premise of capacity releasing -- to ensure non-discriminatory access to the secondary transportation market -- would be undermined. Allowing such a regulatory gap to exist in regulatory access to the interstate market is not in the public interest. C. Upstream Capacity Assignment In Order No. 636, the Commission adopted new section 284.242 of its regulations, which provides that open-access pipelines must allow firm transportation customers of downstream pipelines to acquire capacity on upstream pipelines held by downstream pipelines. The main issues raised are whether bundled sales customers should have a priority in acquiring upstream capacity and whether downstream pipelines can retain upstream capacity. 1. Priority for Bundled Sales Customers UDC argues that the Commission must amend section 284.242 of the regulations to state affirmatively that firm sales customers of a pipeline have first priority to allocation of upstream transportation capacity formerly used to provide the pipeline's bundled sales service. It states this will reflect Order No. 636-A's statement that "customers of downstream pipelines have Docket No. RM91-11-004, et al. - 56 - priority access to upstream transportation and storage capacity." 92/ UGI also argues that section 284.242 should be amended so that the phrase "without undue discrimination" does not compromise converting customers' priority rights in the allocation of all upstream capacity and storage. 93/ UGI maintains that this right is necessary to continue the level of firm deliverability embedded in converting sales customers' prior sales contracts. The Commission clarifies that current bundled firm sales customers of downstream pipelines have a priority right during the restructuring proceeding over other pipeline customers to upstream transportation and storage capacity to the extent that capacity is needed to maintain their pre-restructuring level of maximum daily entitlement to service. This is not an absolute right because there may be circumstances where upstream transportation or upstream storage or both are not necessary to 92/ Order No. 636-A, at p. 30,568. UDC also states that "Order No. 636-A clarified that current bundled firm sales customers of pipelines have a priority right to upstream and storage necessary to maintain their level of maximum daily entitlement to service, whether or not they elect no-notice transportation service." Petition at 15. However, Order No. 636-A at the cited text referred only to downstream storage. Order No. 636-A at p. 30,578. 93/ Section 284.242 provides as follows: An interstate pipeline that offers transportation service on a firm basis under Subpart B or G of this part must offer without undue discrimination to assign to its firm shippers its firm transportation capacity, including contract storage, on all upstream pipelines, whether the firm capacity is authorized under Part 284 or Part 157. Docket No. RM91-11-004, et al. - 57 - maintain the downstream pipeline customer's level of maximum daily entitlement. This parallels the Commission's conclusions in Order No. 636-A that current bundled firm sales customers have a priority right to the storage necessary to maintain their level of maximum daily entitlement to service and that customers that converted earlier were able to do so without access to storage. If upstream capacity or storage is available after bundled firm sales customers elect their levels of capacity, the pipeline must offer and allocate the remaining capacity among all its shippers on a nondiscriminatory basis. That is, current system users other than bundled firm sales customers have no priority over new transportation customers for upstream transportation and storage capacity that is not selected by current bundled firm sales customers. The Commission will not amend section 284.242 because this is a capacity allocation matter. The priority for bundled firm sales customers does not contravene the requirement that the downstream pipeline offer its upstream capacity without undue discrimination because the allocation priority is reasonable when necessary to preserve the bundled firm sales customer's level of pre-restructuring maximum daily entitlement upon conversion to unbundled service. 2. Retention of Upstream Capacity By Pipelines The Commission previously denied requests that pipelines be permitted to retain capacity on their own systems downstream of the point of unbundling on their systems. ANR seeks rehearing of Docket No. RM91-11-004, et al. - 58 - the Commission's statement that a downstream pipeline holding capacity on upstream pipelines may not perform a sales service at the interconnection with an upstream pipeline. It argues that a pipeline will be unable to compete with other merchants, that it will be precluded from selling gas supply under contract, and will be forced to buy out marketable gas supplies with little or no leverage. It adds that its suppliers will demand the higher market price from ANR's former customers. Natural refers to Order No. 636-A's prohibition on downstream pipelines holding capacity on upstream pipelines as properly interpreted to mean that a pipeline sales division cannot retain upstream capacity on a preferential basis. It is concerned that Order No. 636-A could be interpreted to preclude the pipeline sales division from holding any capacity on other pipelines upstream of the point of unbundling, which would freeze it out of access to significant supply areas during the restructuring proceedings. UGI argues that the Commission should allow downstream pipelines to show that it is necessary for them to retain title to upstream capacity to meet their existing firm transportation obligations to their customers for both peak-day entitlements and quality of service. UGI maintains that the quality of service provided by Columbia Gas Transmission Company will likely be lower than it is now if Columbia must assign its over 80 interconnections with upstream pipelines on a piecemeal basis. Arkla contends that downstream pipelines should be able to retain Docket No. RM91-11-004, et al. - 59 - title to, but not the use of, upstream capacity to provide greater flexibility to the pipeline. The Commission adheres to its conclusion that downstream pipelines may not hold capacity on upstream pipelines to perform a sales service at the interconnection with an upstream pipe- line. 94/ Pipelines, such as ANR and Natural, can still compete with other merchants by selling, in the production area, gas supplies under contract or obtained in the future. Pipelines, as merchants, are not forced to buy out marketable gas supplies nor are they frozen out of significant supply areas. Natural's interpretation, that the Commission has prohibited only retention of upstream capacity on a preferential basis, is incorrect because that would permit a pipeline to sell gas at downstream interconnections with upstream pipelines. As noted earlier, a pipeline's marketing affiliate can obtain capacity on any pipeline. As stated in Order No. 636-A, downstream pipelines can retain some capacity on upstream pipelines to the extent they demonstrate it to be necessary for operational management and balancing purposes and the performance of the no-notice transportation service. 95/ To the extent UGI's and Arkla's arguments involve operational concerns, they are case-specific. Hence, UGI and 94/ As stated in Order No. 636-A, downstream pipelines can hold capacity on upstream pipelines in the production area. Order No. 636-A at p. 30,566. 95/ Order No. 636-A at pp. 30,566-67. Docket No. RM91-11-004, et al. - 60 - Arkla should raise their concerns in the relevant restructuring proceedings. Of course, the Commission recognizes that, on some pipelines, operational problems could arise owing to the assignment of upstream capacity involving many interconnections and downstream customers. Hence, the parties to the restructuring proceeding are encouraged to develop innovative proposals to deal with this problem. For example, it may be adequate for the downstream customers to appoint an agent to arrange transportation for them as a group or they could take some form of joint title to the upstream capacity (e.g., an undivided interest). 3. Relationship of Section 284.242 to Restructuring Order No. 636-A stated that a downstream pipeline may reduce its upstream capacity "with the consent of the potentially affected customers of the downstream pipeline." 96/ ANR maintains that one or two customers should not be able to refuse to consent and cause all customers to incur the cost of unneeded capacity so that the two can reserve capacity for possible future use. ANR suggests the Commission "impose a presumption that a customer's election not to receive a permanent assignment of capacity is deemed an assent by that customer to a capacity reduction or termination under section 284.14(c)(4)." 97/ 96/ Order No. 636-A at p. 30,641. See also id. at p. 30,568. 97/ Petition at 8. Docket No. RM91-11-004, et al. - 61 - The Commission denies ANR's request. The requirement of unanimity only pertains to consent to assignment or relinquishment of upstream capacity in the restructuring proceeding. It is necessary to ensure that customers of downstream pipelines have adequate opportunity to make their decisions about upstream capacity during the restructuring proceeding. Once the upstream pipeline completes its restructuring process, the downstream pipeline may release its Part 284 capacity under section 284.243 of the Commission's regulations without the consent of downstream customers. If that release is permanent, then it will not be available for the downstream customers to take assignment under section 284.242. If the release is not permanent, the downstream customer may exercise its section 284.242 rights, subject to the release. 4. Timing Of Implementation Transco asks the Commission to clarify how and when the assignments under section 284.242 are to be accomplished. Transco maintains that it should be able to make those assignments to its shippers on a self-implementing basis prior to the effective date of its Order No. 636 compliance filing because section 284.242 became effective on May 18, 1992, and because Order No. 636 stated that "section 284.242 capacity reassignments 'must be effectuated in the restructuring proceedings' prior to release of capacity under new section 284.243." 98/ Transco 98/ Motion for Clarification at 2, citing Order No. 636 at p. 30,417 n. 120. Docket No. RM91-11-004, et al. - 62 - further asserts that one upstream pipeline has notified Transco that the upstream pipeline interprets Order No. 636 to preclude the effectiveness of upstream capacity assignments until the restructuring proceedings are completed and that it would not consent to Transco's assignments until it received assurance that its service obligation to Transco was superseded by its service obligation to the shippers obtaining assigned upstream capacity. Last, Transco points out that the Commission has stated it will allow early implementation of certain aspects of Order No. 636, such as open access storage and capacity releasing. 99/ Brooklyn Union supports Transco's motion and argues that consent by upstream pipeline suppliers is not required to effectuate permanent assignments of upstream capacity and that, upon such assignment, the upstream pipeline's service obligation to the downstream pipeline is replaced and superseded by its obligation to the new firm shipper. 100/ Brooklyn Union maintains that, to effectively evaluate the available range of services, shippers need to know the full amount of upstream and on-system capacity available to them. Natural responds that it supports upstream capacity assignments prior to full implementation of Order No. 636 by the downstream pipeline only if the upstream pipeline consents. It 99/ Citing Northern Natural Gas Co., et al., 59 FERC  61,362 at p. 62,363 (1992). See also ANR Pipeline Co., 59 FERC  61,205 at p. 61,724 (1992). 100/ Brooklyn Union's motion for leave to answer Transco's motion is granted. Docket No. RM91-11-004, et al. - 63 - maintains this is necessary so that a downstream pipeline that has not complied with Order No. 636 cannot gain a temporary competitive advantage. Natural adds that an assignee of upstream capacity must meet the upstream pipeline's creditworthiness provisions as is the case for replacement shippers under section 284.243. 101/ Section 284.14(b)(i) of the Commission's regulations requires pipelines to make a compliance filing that, among other things, implements Subpart H of Part 284, including provisions to implement "assignment of capacity rights on upstream pipelines to firm customers." 102/ Hence, assignments under section 284.242 are not self-implementing for the downstream pipeline; it must implement such assignments through its compliance filing with the Commission. This is necessary so the Commission can resolve any issues involving the appropriate allocation of capacity by downstream pipelines on upstream pipelines. The Commission will permit a downstream pipeline to make a compliance filing in its RS docket to implement its upstream pipeline capacity assignment prior to the effective date of other aspects of its compliance filing under Order No. 636. The downstream pipeline must include in its compliance filing its allocation methodology, including how it will take into account the rights of current bundled sales customers to upstream 101/ Order No. 636-A at p. 30,558. 102/ 18 CFR 284.14(b)(l)(xiv). Docket No. RM91-11-004, et al. - 64 - capacity. 103/ Natural should raise its objections to early approval in response to the downstream pipeline's compliance filing. Upstream pipelines do not have to file tariff provisions to implement section 284.242. However, they must permit the assignment, even if it is prior to the effective date of the upstream or downstream pipeline's compliance filing under Order No. 636. Because the assignee has met the downstream pipeline's creditworthiness requirements, the Commission sees no reason for it to requalify under the upstream pipeline's standards. In any event, the Commission has not been made aware of situations where upstream and downstream pipelines have significantly different creditworthiness requirements. The assignment of upstream capacity will result in a new transportation agreement under Part 284 between the upstream pipeline and the assignee. 104/ Upon the effective date of that agreement, the contractual arrangement between the upstream pipeline and downstream pipeline is terminated and abandonment is authorized as stated in Order No. 636-A. 105/ 103/ See Part C.1., supra with respect to the priority of current bundled sales customers to upstream capacity. 104/ Even if the downstream pipeline held capacity on the upstream pipeline under Part 157, the transportation agreement between the assignee and the upstream pipeline will fall under Part 284. This will provide the assignees with the flexibility to fully utilize available sources of supply. 105/ Order No. 636-A at p. 30,567. Docket No. RM91-11-004, et al. - 65 - D. No-Notice Transportation Service In Order No. 636, the Commission required pipelines to provide a no-notice transportation service under which firm shippers may receive delivery up to their firm entitlements on a daily basis without penalty. Petitioners raise a variety of issues dealing with the availability of and eligibility to receive no-notice service. 1. Availability of No-Notice Service In Order Nos. 636 and 636-A, the Commission concluded that a pipeline was required to offer a no-notice transportation service only to customers that were entitled to receive a no-notice, city-gate, firm sales service on May 18, 1992, and that pipelines are not required to offer a no-notice service to other customers because they have not been receiving such a service. The Commission encouraged the pipelines to offer a no-notice transportation service to all transportation customers on a non- discriminatory basis. Northern States argues that the Commission erred by limiting required no-notice service to bundled, city-gate, firm sales customers under contract as of May 18, 1992. Northern States argues that it is necessary to offer no-notice service to all firm shippers to eliminate undue discrimination between classes of service. Prior Energy similarly argues that pipelines should be required to offer no-notice service to all shippers who wish to purchase it on an open access, non-discriminatory basis. Prior Energy contends this is necessary to avoid discrimination Docket No. RM91-11-004, et al. - 66 - between customers by allowing customers who were also customers on May 18, 1992, to receive a service unavailable to anyone else. The APGA also argues that the Commission erred in limiting required no-notice service to customers that were entitled to receive no-notice firm city-gate sales service on May 18, 1992. The APGA argues that other customers should be entitled to no- notice service, "subject to (1) the rights of pre-existing bundled sales customers and (2) limitation of facilities." 106/ The APGA maintains that this is necessary because some customers may have declined more firm sales service because of the high cost of supplies or because facilities may have been completed but not approved. The APGA adds that this restriction may undermine the growth in the natural gas industry because LDCs will not be able to render incremental service on a reliable basis. The APGA maintains that a pipeline should bear a heavy burden of showing that it cannot provide incremental no-notice service because it lacks operational flexibility. Southwest Gas and Indicated UtiliCorp Divisions argue that no-notice service should be offered to customers who previously converted to transportation to ensure comparability of service as envisioned by Order No. 436's policy that the quality and priority of service to a converting customer would be no lower than the quality of the prior sales service. 107/ Southwest 106/ Petition at 7. 107/ Southwest Gas cites Order No. 436, FERC Stats. & Regs. [Regulations Preambles]  30,665 at p. 31,517 (1985): (continued...) Docket No. RM91-11-004, et al. - 67 - Gas adds that the Commission has arbitrarily changed its comparability policy which was reflected in the Commission's reliance on comparability in proposing this rule and in adopting no-notice service. It further argues that, in converting, customers relied upon continuation of the comparability principle to ensure no service degradation and that, on some pipelines (e.g., El Paso Natural Gas Company), comparability concerns were yet to be resolved. Last, it maintains that reliability of unbundled transportation service via no-notice service is just as important to customers who converted prior to May 18, 1992. The Commission denies rehearing. The Commission established the no-notice transportation service so that bundled, city-gate, firm sales customers can continue to receive service of the same reliability and quality in the unbundled environment as they received in the bundled environment. The Commission did not require pipelines to expand the eligibility for the no-notice transportation beyond those sales customers receiving no-notice service on May 18, 1992, for several reasons. First, because a stand-alone, no-notice transportation service is a new service, 107/(...continued) Firm sales customers that convert their contract demand rights to transportation rights. . . will have the same priority of service under their converted transportation service as they did under their firm sales service agreements. There is no change in the quality or priority of their service, because the priority of their claim on the pipeline's capacity is unchanged by conversion. Docket No. RM91-11-004, et al. - 68 - it is prudent to preserve only the status quo to allow pipelines to gain experience with its operation. Second, customers who were not receiving no-notice service (as part of their bundled sales service) on May 18, 1992, were not relying on that service because pipelines did not offer a no-notice transportation service. Third, those customers could not reasonably expect to receive no-notice service in the future. Order No. 436's requirement of service comparability, while broad, did not encompass no-notice firm transportation. Hence, the Commission did not change its comparability policy to the detriment of customers who converted prior to May 18, 1992. In addition, the Commission's Notice of Proposed Rulemaking (NOPR) did not explicitly propose no-notice transportation service. That service was required for bundled, city-gate, firm sales customers in the final rule in response to the comments to the NOPR and related technical conference held on January 22, 1992. 108/ To conclude, the Commission required no-notice transportation service in response to a particular problem raised by petitioners vis a vis a particular service -- no-notice bundled, city-gate, firm sales service. Nonetheless, the Commission strongly encourages the pipelines to make no-notice transportation service available to customers on a non-discriminatory basis to the maximum extent possible. 108/ Order No. 636 at pp. 30,408-09. Docket No. RM91-11-004, et al. - 69 - 2. One-Time Election In Order No. 636-A, the Commission concluded that pipeline sales customers have a one-time right to elect no-notice transportation during the restructuring proceeding. The APGA argues that this limitation is untenable because the pipeline's customers cannot make their decisions without knowledge of the Commission approved criteria and rates of no-notice service and without some practical experience. The APGA seeks clarification that "(1) a pipeline shall not require a binding and permanent election of no-notice service until after the pipeline's tariffs are made effective following restructuring; (2) customers electing no-notice service may alter their nominations prospectively under procedures set forth in the tariff." 109/ Similarly, the regulatory commissions of the states of Iowa, Missouri, and Wisconsin argue that it is impossible for LDCs to elect no-notice service until the Commission rules on the pipeline's compliance filing. They argue that the Commission should allow the free availability of no-notice service until system users have the experience to make informed choices. The Commission continues to believe that the right to elect no-notice transportation must be exercised in the restructuring proceedings. The Commission recognizes that final elections on the precise levels of no-notice service may depend on the Commission's final disposition of the compliance filing, so that the final elections may need to be made after the Commission's 109/ Petition at 9. Docket No. RM91-11-004, et al. - 70 - order accepting the compliance filing. The Commission, however, will not require pipelines to provide the ability to elect new or added no-notice service after the effective date of restructuring. The purpose of no-notice transportation is to provide former bundled sales customers with continuity of service upon the effective date of the pipeline's compliance filing. Pipelines may, if they wish, permit their customers to switch between no-notice and other transportation services after the restructuring proceedings so long as this ability is available on a nondiscriminatory basis. The pipeline and the customer would execute a new contract for the different service and they would terminate the contract for the previous service. This is similar to the requirement that if a pipeline voluntarily offers no- notice service in the restructuring proceeding to customers other than those who qualify under the rule, it must do so on a non- discriminatory basis. 110/ 3. Upstream Pipeline and Other Deliveries The APGA and AGD ask the Commission to clarify that upstream pipelines will be required to provide a no-notice transportation service at the downstream pipeline delivery point. The APGA maintains that customers that qualify for no-notice service on downstream pipelines must be offered no-notice service on upstream pipelines, even if they have no direct customers that qualify for the service. 110/ Order No. 636-A at p. 30,574. Docket No. RM91-11-004, et al. - 71 - The Commission clarifies that upstream pipelines need to provide no-notice transportation service only to those customers to whom they provided no-notice service on May 18, 1992, and to the capacity assignees of those customers under section 284.242 of the Commission's regulations. 111/ This is because it is reasonable to assume that a downstream pipeline that provided no- notice service without no-notice service from upstream pipelines can continue to provide no-notice service without requiring the upstream pipeline to serve the downstream customers on a no- notice basis. In short, the assignees of the downstream pipeline step into its shoes for this purpose when they take the capacity on the upstream pipeline. New Jersey Natural contends that if a customer received firm no-notice sales service at a place other than its city gate, it should be entitled to receive no-notice transportation. The Commission clarifies that an upstream pipeline that provided a no-notice sales service on May 18, 1992, to a customer that did not take delivery at its city gate must provide no- notice transportation to that customer at the non-city gate delivery point. This comports with the Commission's conclusion that customers receiving no-notice service on that date should have the right to maintain the no-notice aspect of their service. The Commission discussed no-notice service in the context of 111/ See Order No. 636-A at pp. 30,572-73, where the Commission's description of no-notice service to downstream customers assumes that they can succeed to any no-notice service held by the downstream pipeline on upstream pipelines. Docket No. RM91-11-004, et al. - 72 - citygate service because that was the predominant no-notice service. Brooklyn Union argues that it should be entitled to no- notice transportation regardless of whether it took its sales gas at its city gate from the selling pipeline or through an intermediary pipeline. It states that it purchases gas from certain pipelines that are not connected to its city gate with other pipelines transporting the gas to its city gate. It cites as an example its purchases from CNG Transmission Corporation that are delivered to Brooklyn Union's city gate by Transco and by Texas Eastern Transmission Corporation. UGI notes its concern that it cannot become a no-notice transportation customer on the upstream pipeline in lieu of the no-notice sales service it receives from Columbia Gas. UGI takes the Columbia Gas directly from Texas Eastern. With respect to the scenario described by Brooklyn and UGI, where each bought gas from one pipeline but took delivery from another pipeline, the Commission interprets no-notice to mean that Brooklyn Union and UGI are entitled to no-notice service from the delivering pipeline (i.e., Transco and Texas Eastern), if the delivering pipeline was contractually obligated to deliver the gas to them on a no-notice basis on May 18, 1992. However, whether Brooklyn Union or UGI is entitled to no-notice service on an upstream pipeline (e.g., CNG) is an issue for the restructuring proceeding. Docket No. RM91-11-004, et al. - 73 - 4. Option to Elect No-Notice or Traditional Transportation Service In Order No. 636-A, the Commission concluded that "a sales customer, at its election during the restructuring proceeding, may choose no-notice or traditional firm transportation or a combination of the two." 112/ CIG argues that the Commission erred by permitting former bundled sales service customers to choose their transportation services. CIG maintains that while the Commission recognized that no-notice transportation service was the appropriate substitute service for bundled sales service, it did not show that the firm transportation option is needed on all pipelines. CIG claims that this option is peripheral to the problem faced by the Commission and, therefore, improper. 113/ In addition, CIG contends that it will lose the needed centralized coordination and control of its system if customers are permitted to elect traditional firm transportation service. It maintains that traditional firm transportation customers might adversely affect its system capacity, storage operations, gathering system, the thermal content of its gas, and transition costs. It asks the Commission to eliminate the traditional firm transportation option or alternatively reaffirm that pipelines can condition that service in a way that ensures operational control. 112/ Order No. 636-A at p. 30,577. 113/ Citing Associated Gas Distributors v. FERC, 824 F.2d 981, 1018-20 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988). Docket No. RM91-11-004, et al. - 74 - The Commission's intent in the instant rule is to afford former bundled sales customers a meaningful choice of transportation services best suited to their needs. In addition, no-notice service was established as an additional, or enhanced, form of firm transportation service and not as a service in lieu of traditional open access firm transportation service. Hence, while the Commission improved traditional open access firm transportation service (e.q., storage and flexible delivery points), the Commission intended no-notice transportation service as an additional transportation option for no-notice sales customers. The Commission reaffirms that pipelines may need to impose operational conditions on traditional open access firm transportation to perform no-notice transportation. The pipelines, of course, must propose those conditions in their compliance filings so that the Commission can evaluate them to determine if they are reasonable operational conditions under sections 284.8(c) to be applied without discrimination as required by section 284.8(b). 114/ 5. Flexible Delivery Points In Order No. 636-A, the Commission stated that pipelines must provide their no-notice transportation service at flexible delivery points. United argues that the Commission should eliminate this requirement because it will result in inefficient 114/ See also the discussion of operational control in the discussion of storage, infra, Part E.2. Docket No. RM91-11-004, et al. - 75 - usage of the pipeline system and result in greater costs for no- notice shippers. 115/ It adds that this requirement goes beyond the Commission's justification for no-notice service and the Commission's NGA section 5 authority to modify unreasonable contracts. It argues that the Commission has mandated a service clearly superior to the bundled, no-notice, firm city-gate, sales service provided on May 18, 1992. United concludes that no- notice service beyond the delivery points specified on May 18, 1992, should be optional on a non-discriminatory basis. Upon further reflection, the Commission will further clarify its position on the availability of flexible delivery points for no-notice service. Because no-notice service is limited to a discrete set of former sales customers and is intended to duplicate service provided under the pipeline's bundled sales service, a pipeline will not be required to provide flexible delivery points for its obligation to provide transportation, on a no-notice basis, without scheduling penalties. In other words, pipeline customers are entitled to no-notice service at their primary firm delivery points at the time they convert from bundled sales service to no-notice transportation service. The pipeline customers are not limited to their delivery points as of May 18, 1992. For example, a pipeline sales customer with delivery points A, B, and C pre-restructuring will retain those delivery points post-restructuring for no-notice service but will 115/ United refers to the cost of transmission and storage capacity reserved by it to provide no-notice delivery at any delivery point. Docket No. RM91-11-004, et al. - 76 - not be entitled to receive no-notice service at other primary firm delivery points or at secondary firm delivery points. Pipelines are free, however, to provide for flexible delivery points for no-notice service when operationally feasible. One of the primary reasons the Commission required the provision of flexible delivery points was to facilitate capacity release of firm transportation capacity. No-notice service is a firm transportation service under which firm shippers may receive delivery up to their firm entitlements on a daily basis without penalty. No-notice service, therefore, consists of two aspects: firm transportation and no-notice delivery. The releasing shipper can release its firm transportation capacity with the right to flexible delivery points. However, the no-notice delivery aspect of its service pertains only to current delivery points as described above and not to flexible delivery points, which are part of the firm transportation aspect of its service. 6. Operational Flow Orders In Order No. 636, the Commission stated that "pipelines have the right to impose reasonable operational conditions and to issue, on a non-discriminatory basis, operational flow orders without liability, except for negligence or undue discrimination, to be able to provide a no-notice transportation service." 116/ New Jersey Natural asks the Commission to clarify that pipelines may not use operational flow orders to impose "must take" requirements on its customers. It maintains that "must 116/ Order No. 636-A at p. 30,575. Docket No. RM91-11-004, et al. - 77 - take" requirements will subvert the efficiency goal of a competitive market if customers must take gas regardless of economic and market conditions. It adds that they may not be able to physically take the gas and that unmarketable gas would increase costs to their ratepayers and could harm their markets in the long run. It further contends that operational flow orders might require LDCs to take gas above their contractual obligations to pipelines and might undermine no-notice service by requiring LDCs to take gas instead of reducing takes below the nominated volumes without notice. A pipeline may not issue an operational flow order that would require a shipper to ship gas above its reservation quantity. However, the Commission reaffirms that pipelines are entitled to impose reasonable operational conditions, including operational flow orders. The pipeline, therefore, can make its shippers inject gas into the system within their contract quantities ("must ship" gas) when and where necessary to maintain the system's operational integrity and to enable the pipeline to provide no-notice transportation service. The Commission, as stated, will review the conditions proposed by pipelines to ensure they are reasonable and are nondiscriminatory. In addition, as no-notice service evolves, and experience is gained, the Commission expects to revisit the conditions in light of that experience. In particular restructuring compliance filings, the Commission will consider arguments that particular conditions are unworkable with respect to particular pipeline customers. Docket No. RM91-11-004, et al. - 78 - E. Storage In Order No. 636, the Commission amended section 284.1(a) of the Commission's open access regulations to define transportation as including storage. This section deals with petitioners' contentions about allocation of the open-access storage capacity and the rights of existing holders of storage capacity. 117/ 1. Allocation Of Downstream Storage Capacity In Order No. 636-A, the Commission clarified Order No. 636 by stating that current bundled firm sales customers have a priority right to the storage necessary to maintain their level of maximum daily entitlement to service whether or not they elect no-notice transportation service. The Commission further stated that previously converted customers are not entitled to the same priority as customers converting under Order No. 636-A because the former customers were able to convert without storage to meet their needs. In addition, the Commission stated that current system users are to have no priority over new transportation customers for any storage capacity available after converting customers exercise their priority right to storage. The Indicated UtiliCorp Divisions argue that the Commission erred in denying guaranteed access to storage for previously converted sales customers. It argues that pipelines (such as Williams Natural Gas Company) used their storage to support their transportation customers on peak days and included storage costs 117/ Transco's request for clarification regarding unbundling at the outlet side of its Eminence storage field is an issue for its restructuring proceeding. Docket No. RM91-11-004, et al. - 79 - in their firm transportation rate. It asks the Commission to clarify that, "unless a former sales customer expressly has relinquished its right to system storage capacity upon exercise of its conversion rights, it retains a priority right to that capacity." 118/ It adds that the relinquishment issue should be left to individual restructuring proceedings. The United Cities also argue that LDCs that previously converted to firm transportation should have priority rights to pipeline storage facilities. United Cities maintain that those customers have used the storage bundled within pipeline sales to meet swings in demand above their firm transportation base load. United Cities add that providing certain customers with "artificially high" pipeline storage capacity will cause the pipeline to operate below maximum efficiency. They claim this is so because those customers will use storage for the middle of their load profile, thereby reducing peak withdrawals. Prior Energy objects to the priority for converting sales customers on the grounds that they may not value it as highly as other shippers, such as marketers. Prior Energy maintains that Order No. 636-A thwarts the goal of vigorous competition by relegating non-sales customers to a second-tier of storage claimants. The Commission reaffirms its clarification in Order No. 636-A that only current bundled firm sales customers have a priority right to storage. Customers that have previously 118/ Petition at 7. Docket No. RM91-11-004, et al. - 80 - converted to firm transportation under Part 284 without contract storage are not entitled to a priority because they were able to receive their firm transportation entitlement level without any contract storage rights. A pipeline's use of system storage to support transportation service, and the allocation of storage costs to transportation, was not related to firm entitlement levels, but to operational management and balancing. 119/ Pipelines may continue to reserve some amount of system storage for operational management and balancing to support traditional transportation services to customers, including previously converted customers, as well as no-notice transportation. The pipeline has the burden of showing what level of storage it needs to support its services. The Commission's grant of priority to bundled sales customers to preserve service levels is necessary to ensure their certificated levels of service. "Value of service" concepts are not pertinent to this priority right to the storage. 2. Existing Contract Storage Service In Order No. 636-A, the Commission concluded that while current contract storage customers retain their full right to capacity as specified in their contracts, the terms and conditions associated with those rights could be changed, if they 119/ System storage includes facilities owned and used by the pipeline to store its own gas for operational reasons such as for balancing. System storage also has been used in lieu of transportation capacity to make bundled sales. Docket No. RM91-11-004, et al. - 81 - are unreasonable in light of Order No. 636's requirements of no- notice transportation and open access contract storage. 120/ AGD, Brooklyn Union, PSE&G, and UGI argue that the Commission has not justified why it is necessary to affect existing storage arrangements. 121/ AGD contends that the Commission has offered no explanation about why a pipeline cannot use the same physical and operational assets that it uses to render no-notice sales service to provide no-notice transportation service. AGD, PSE&G, Brooklyn Union, and UGI maintain that a reduction in the quality of currently certificated contract storage could jeopardize an LDC's ability to serve its customers during peak periods. They ask the Commission to state that it will not permit changes to their contract storage service quality, such as adverse modifications to existing contract storage capacity and injection or withdrawal schedules. AGD and PSE&G maintain that any such degradation of service would be a de facto abandonment and would be inconsistent with the abandonment requirements of NGA section 7(b). The Commission clarifies that, while it has authorized pipelines to propose to change existing storage arrangements, if necessary, to provide no-notice transportation service, the pipeline must still show that the changes are necessary and reasonable. This includes an analysis of the impact of a change 120/ Contract storage describes storage capacity with respect to which the customer can inject its own gas. 121/ AGD and UGI argue similarly with respect to existing transportation service. Docket No. RM91-11-004, et al. - 82 - on current contract storage customers. The Commission has not authorized any reduction in contract storage capacity. The Commission views changes to injection and withdrawal schedules as changes to terms and conditions, rather than changes to the level of certificated service. Hence, the Commission concludes that changes to existing contract storage terms and conditions will not need action under NGA section 7(b). 122/ F. Market Centers/Pooling Areas In Order No. 636, the Commission adopted sections 284.8(5) and 284.9(5), which prohibit tariff provisions that inhibit the development of market centers. The Producer Associations, as a progress report, allege that long-line pipelines are proposing rate features that will make it uneconomical for gas suppliers attached to those pipelines to switch pipelines at a market center to serve markets on a different pipeline. They cite the following examples: Rate features such as "system access charges," a requirement that firm mainline transportation must be supplied by firm production-area transportation contracts, and GSR surcharges applicable to production- area transportation make it very difficult and expensive for gas suppliers to access markets through transportation on multiple pipelines. In addition, permitting pipelines to charge their forward haul rates for backhaul service has, on several pipelines, insulated markets from competition by off-system suppliers. Further, several pipelines have proposed transportation rates based upon the zone of the delivery point, irrespective of the length of haul. 122/ The pipelines may change the terms and conditions of other services in a similar manner, if necessary to provide no-notice transportation. Docket No. RM91-11-004, et al. - 83 - Such tariffs also have the effect of discouraging competition. 123/ NERCO contends that pipelines are developing proposals that limit pipeline-to-pipeline competition in the supply area and inhibit the creation of market centers and commercially useful pooling points. NERCO cites as an example the implementation of production area rates that are too low and the definition of access area to the mainline to include inputs that should be outside the area. NERCO asks the Commission to clarify on rehearing that "individual pipelines may not, in the course of the restructuring proceedings, implement production area rates and other onerous proposals that inhibit pipeline-to-pipeline production area competition and, thus, inhibit the creation of market centers and commercially useful pooling points." 124/ The Commission reemphasizes that pipelines may not implement rates (or terms and conditions of service) that inhibit the creation and development of pooling areas and market centers. Market centers are areas where a) pipelines interconnect and b) there is a reasonable potential for developing a market institution that facilitates the free interchange of gas. The size of a given market center may depend on the specific configuration of the pipelines involved. However, the Commission expects generally that market centers should normally be fairly small -- for instance, a 30-mile radius around a central point. 123/ Petition at 2, 3. 124/ Petition at 14, 15. ConEd endorses NERCO's request. Docket No. RM91-11-004, et al. - 84 - In order to facilitate gas transactions, many market centers are likely to offer services that correct imbalances among pipelines (for instance, through storage). 125/ Rate structures can inhibit market centers when (for instance) they require shippers to pay for substantial amounts of capacity both upstream and downstream of a market center in order to use only the upstream or downstream part of the pipeline. Postage stamp rates and rates based on large zones can have this effect. Similarly, rates can inhibit market centers when a pipeline charges a large zone rate simply to transfer gas among two other nearby pipelines within a market center. In both cases, the result amounts to tying transportation services together that are commercially distinct and is contrary to the spirit of service unbundling. In addition, inappropriate rates for backhauls or penalties for scheduling and balancing can inhibit market center development. Either can prevent a shipper from using its capacity rights flexibly and inhibit the flexible commercial interchange of natural gas. The Commission does not require pipelines to adopt any particular approach to ensure that they do not inhibit the development of market centers. 126/ However, the Commission 125/ See, for example, illustrations of market centers in Importance of Market Centers, Office of Economic Policy, FERC (Washington, D.C.), August 21, 1992. 126/ Depending on the pipeline configuration and operation, it may be possible, for example, to establish special zones for market centers, small zones or rates based on 100 mile increments, or separate "within market center" (continued...) Docket No. RM91-11-004, et al. - 85 - reiterates that the effects of pipeline rates and terms and conditions of service on market centers and pooling areas should be resolved in individual restructuring proceedings. 127/ G. Flexible Receipt and Delivery Points 1. Small Customers Prior Energy asks the Commission to clarify whether small customers are entitled to use flexible receipt and delivery points. Small customers are firm shippers under Part 284 of the Commission's regulations and therefore are entitled to flexible receipt and delivery points just as any other Part 284 firm shipper. Flexible delivery points, however, are of primary importance to facilitate capacity releasing. Since small customers paying one-part rates are not able to release capacity, the availability of flexible delivery points may be of only minimal value to them. 2. Penalties In Order No. 636-A, the Commission concluded that "[i]ssues involving provisions governing the use of receipt and delivery points, including appropriate penalties, must be addressed in the restructuring proceedings." 128/ The Commission added that "there must be some valid operational reason for imposing 126/(...continued) rates for hauls to and from interconnections within larger zones. 127/ See, e.g., El Paso Natural Gas Co., 60 FERC  61,109 (1992). 128/ Order No. 636-A at p. 30,584. Docket No. RM91-11-004, et al. - 86 - penalties on changes in volumes to delivery points within an interrelated service area." 129/ The Fuel Managers Association is concerned about unduly strict scheduling requirements and scheduling penalties. It asks the Commission to clarify that a pipeline must demonstrate affirmatively, through documented evidence submitted during the restructuring proceeding, that any proposed scheduling requirement or penalty mechanism is needed to address operational concerns on its system and why a less onerous scheduling requirement or penalty would not be sufficient to address its operational concerns. It maintains that a mere statement by a pipeline that it needs its scheduling requirements or penalties to inhibit abusive behavior should not satisfy its burden of proof. The Commission grants the Fuel Manager Association's clarification and agrees that pipelines must demonstrate that their proposed scheduling requirements and penalty mechanisms are reasonable operational conditions. The Commission observes that scheduling requirements and penalties serve different functions. Scheduling requirements are needed to provide the pipeline with advance information to operate its system efficiently. Penalties are designed to inhibit behavior inimical to the operational integrity of a pipeline system. 129/ Id. Docket No. RM91-11-004, et al. - 87 - 3. Deliveries Within a Zone In Order No. 636-A, the Commission concluded as follows with respect to alternate flexible delivery points within a zone: [S]hippers with upstream delivery points within a zone can select downstream delivery points within the same zone and . . . operational concerns can be met by making service to the downstream delivery point interruptible. This is consistent with the general principle that controls here: a shipper gets flexibility in receipt and delivery points for the part of the system for which it pays a reservation charge. Thus, if a pipeline has zone rates, a shipper gets flexibility within its zone. 130/ New Jersey Natural argues that the alternate flexible firm delivery points downstream in a zone should have priority over the rights of interruptible shippers. It also seeks clarification that shippers on pipelines with postage-stamp transportation rates may designate downstream delivery points without restriction. It maintains that they should be able to do that because both upstream and downstream shippers are paying for access to the entire pipeline system. The Commission's discussion, quoted above, was addressed to the relative rights only of firm shippers. Firm shippers with alternate flexible firm delivery points downstream in a zone have priority over the rights of interruptible shippers but not over firm shippers with primary firm delivery points. Shippers nominating volumes for delivery to primary firm delivery points 130/ Order No. 636-A at p. 30,585. Docket No. RM91-11-004, et al. - 88 - have scheduling priority over shippers nominating volumes for flexible (alternate) firm delivery points. With respect to designation of downstream flexible delivery points, a postage-stamp system should be treated similarly to a zone system. Since shippers on a system with postage-stamp rates pay reservation charges covering the entire system, they may designate downstream alternative firm delivery points on the same basis as shippers within a zone. The Commission strongly encourages pipelines with postage stamp rates to consider developing smaller zones or mileage-based rates, particularly where such rate structures will foster the development of market centers. 4. Curtailments The APGA seeks clarification with respect to the scenario where there is a capacity constraint in the path of firm transportation on behalf of shippers using primary and flexible delivery points. It maintains that since the service to alternate delivery points is interruptible, it should be curtailed prior to service to any primary delivery point. 131/ It adds that this should be so whether the alternate delivery point is upstream or downstream of the primary delivery point. 131/ The firm shipper selects primary delivery points, which are firm for scheduling purposes, and secondary or alternate delivery points, which do not have scheduling priority over primary delivery points of other firm shippers but have scheduling priority over delivery points of interruptible shippers. Docket No. RM91-11-004, et al. - 89 - The Commission clarifies that a pipeline must give scheduling priority to shippers using primary delivery points if there is a capacity constraint when, for example, a compressor is malfunctioning. That is, the shipper scheduling for an alternate firm delivery point is treated as interruptible for scheduling purposes in this situation. 132/ If the constraint develops after gas is scheduled, service to alternate firm delivery points should be considered just as firm as service to primary firm delivery points. V. Transportation Rates In Order Nos. 636 and 636-A, the Commission adopted the SFV method of cost classification for cost allocation and rate design (billing) purposes, required the use of different measures to mitigate cost shifts, and required pipelines to continue to serve small customers at a one-part rate computed using an imputed load factor. Petitioners raise a variety of issues with respect to the mitigation measures and the treatment of small customers. A. Different Ratemaking Techniques In Order No. 636-A, the Commission stated that "it will require the parties to use different ratemaking techniques in connection with the distribution of revenue responsibility among customers to avoid significant cost shifting that may result from the elimination of the two-part demand charge or the allocation 132/ Scheduling service at the alternate firm delivery points is, of course, superior to scheduling interruptible transportation. Order No. 636 at p. 30,583. Docket No. RM91-11-004, et al. - 90 - of costs based on peak day demand." 133/ The Commission strongly encouraged the use of seasonal contract quantities (i.e., seasonal entitlements or CDs) as a means to counteract those shifts and as a replication, in part, of the allocation of costs based on peak and annual considerations. The Commission permitted the parties to explore other methods. 1. Opposition to Different Ratemaking Techniques Several petitioners oppose the use of different ratemaking techniques to mitigate significant cost shifts. In particular, they oppose the use of seasonal contract quantities or annual volumes as the mitigation technique. Allied-Signal objects to the using of different ratemaking techniques to avoid significant cost shifts owing to SFV because in its view the customer class phase-in method, the capacity adjustment and releasing mechanisms, and the use of a one-part volumetric rate at an imputed load factor for small customers provide all the mitigation necessary. The Industrial Groups similarly argue that firm customers can mitigate via capacity releasing and alternatives such as peak shaving, storage, and conservation. The Commission believes that the Order No. 636-A mitigation measure is superior to the methods referred to by Allied-Signal. It is broader based than the treatment afforded small customers and historic customer classes in that it mitigates for all customers which face a significant cost shift. Moreover, it 133/ Order No. 636-A at p. 30,599. Docket No. RM91-11-004, et al. - 91 - ensures mitigation as part of the ratemaking process rather than relying solely on the possibility that capacity can be released or other measures implemented. Finally, the Commission in the past has used ratemaking approaches (such as imputed load factors and annual nominations) that recognized that customer load factors vary. Allied-Signal, the Industrial Groups, Sierra Pacific, Louisville, and LILCO maintain that the use of seasonal contract quantities or techniques based on annual volumes will have a variety of undesirable impacts. For example, they argue that such mitigative techniques will be inefficient with respect to such matters as customer load factors, patterns of pipeline usage, storage acquisition and use, and capacity releasing. The Commission concludes it is premature to speculate as to the generic impact of seasonal contract quantities or other mitigation measures. Petitioners may raise their contentions about impact in specific restructuring proceedings when the issue is joined, and where arguments can be linked to the specific circumstances of the pipeline and its particular customers. The Industrial Groups argue that the end result of mitigation is a welfare-type subsidy for low load factor customers while Louisville argues that seasonal contract quantities are an inequitable subsidy because they hurt residential customers of LDCs who have undertaken load factor improvement efforts. The Commission believes it is appropriate to minimize significant cost shifting that may occur among Docket No. RM91-11-004, et al. - 92 - customers so that the impact of SFV, to aid competition as discussed in Order Nos. 636 and 636-A, is not distributed inequitably among the shippers on the interstate pipeline network. The Commission does not consider this to be an unfair "subsidy," because it does no more than maintain the status quo with respect to the relative distribution of revenue responsibility. The Industrial Groups and Allied-Signal maintain that seasonal contract quantities will undermine or distort SFV's price signals. Sierra argues that seasonal contract quantities undermine the Commission's goals in that they will improperly affect a gas customer's choice about its gas seller. It maintains that this will result because the demand charges on different pipelines will be determined based on seasonal demands. It points out that on pipelines with identical costs the demand charges will differ because they have a difference in seasonal demand. The Commission sees no adverse impact on price signals or improper impact on a gas purchaser's choice of gas sellers stemming from the use of seasonal contract quantities or similar measures because the pipeline's reservation charge will still be billed under the SFV method. In addition, that seasonal contract quantities will produce different reservation charges on pipelines with identical costs is a fact entitled to no weight. That situation is just as likely to occur without seasonal contract quantities because it is unlikely that two pipelines Docket No. RM91-11-004, et al. - 93 - would have identical reservation quantities with daily reservation quantities applicable throughout the year. In addition, it is highly unlikely that any two pipelines would have identical costs. Sierra further argues that this mitigation approach is inconsistent with Commission policy that transportation rates are to reflect allocative and productive efficiency. It maintains this is because seasonal contract quantities encourage demand on peak days and penalize off peak use. The Commission did not adopt SFV to promote allocative and productive efficiency in the use of pipeline capacity. 134/ Rather, it adopted SFV, as fully discussed in Order Nos. 636 and 636-A, to promote the goal of an efficient, national gas market by allowing all gas merchants to compete equally without regard to fixed transportation costs included in the pipeline's usage charge. The Commission's decision to require pipelines to implement ratemaking techniques to eliminate cost shifts resulting from the change to SFV does not interfere with this goal because the usage charge for firm transportation would be unaffected by any such ratemaking techniques. In any event, the lower usage charge under SFV should enhance productive efficiency by promoting gas on gas competition, reducing transportation usage rates and encouraging increased throughput. Sierra maintains that, in effect, there is no difference between the D-2 charge and seasonal contract quantities. It adds 134/ Order No. 636-A at p. 30,605. Docket No. RM91-11-004, et al. - 94 - that seasonal contract quantities reintroduce the problems associated with D-2s, such as how they are chosen and whether renominations will be allowed. It argues that Order No. 636-A makes implementation problems more severe by making it difficult to predict needs. It also maintains it is unclear what effect a customer's seasonal contract quantity will have on the pipeline's certificate obligation. Seasonal contract quantities are different from, and in the Commission's judgment, superior to the manner in which D-2 charges operated. D-2s did not reduce the firm customer's daily entitlement, while seasonal contract quantities do place a contractual limit on capacity rights. D-2s also did not permit the pipeline to sell unsubscribed firm off-peak capacity, while seasonal contract quantities would permit such sales of unsubscribed off-peak firm capacity. The Commission believes that the issue of how seasonal contract quantities are chosen is an issue for the restructuring proceedings. 135/ As with no- notice service, this election should be made during the restructuring proceedings. Pregranted abandonment under section 284.221(d) of the Commission's regulations is granted to the extent there are reduced seasonal quantities. The parties to the restructuring proceedings should address the issue of whether 135/ That is, pipeline customers do not have a unilateral right to seasonal contract quantities. However, a pipeline that does not want to have seasonal contract quantities must develop another methodology to address potential significant cost shifts, as discussed in Order No. 636-A. Docket No. RM91-11-004, et al. - 95 - shippers should have renomination rights after a pipeline's restructuring becomes effective. LILCO maintains that seasonal contract quantities will enable pipelines to collect excess revenues associated with uncommitted capacity from which it can collect interruptible transportation revenues. The Commission sees the interruptible revenue issue raised by LILCO as no different than the allocation of costs to interruptible service ordinarily faced by the Commission. 136/ Sierra argues that the use of seasonal contract quantities is merely a cost-shift mechanism that has no relationship to how costs are incurred. The Industrial Groups argue that facilities are built to meet peak demands and that off peak usage adds only variable costs. Hence, they maintain, any technique based on annual factors would allow customers to escape cost responsibility. The Commission stated in Order No. 636-A that it adopted SFV because the pro-competitive goals to be accomplished via SFV generally outweigh the ratemaking principle of allocating fixed costs to annual throughput. However, the Commission required adjustments in connection with the distribution of revenue responsibility among customers to avoid significant cost shifts among pipeline customers resulting from varying load profiles. 136/ See the discussion of this issue in the capacity releasing part of this order, supra. Docket No. RM91-11-004, et al. - 96 - The Commission believes it is appropriate to recommend the use of seasonal contract quantities to mitigate significant costs shifts that may occur in individual cases because the use of annual or similar factors is a well-settled method of distributing revenue responsibility among pipeline customers that will not conflict with the goals to be achieved via SFV by retention of a one-part reservation charge for billing purposes. Southwest Gas asks the Commission to clarify that (except for two-part demand charges) it will permit any variety of either entitlement-based allocation methods (e.g., seasonal or maximum daily entitlements) or demand-based allocation methods (e.g., coincident peak demand). At this time, the Commission is not prohibiting any particular techniques except, as discussed below, that two-part demand charges may not be used for billing purposes. Southwest Gas seeks clarification about whether allocation methods to reduce cost shifting are to be applied uniformly to all customers. Since the extent of cost shifting and the application of any ratemaking technique is dependent on the circumstances facing each pipeline, the Commission cannot make a generic determination of this issue. Parties in the individual restructuring proceedings should consider and develop the ratemaking methodology best suited to reducing the cost shifts for each pipeline. To conclude, the Commission adheres to its conclusion that pipelines must "use different ratemaking techniques in connection Docket No. RM91-11-004, et al. - 97 - with the distribution of revenue responsibility among customers to avoid significant cost shifting that may result from the elimination of the two-part demand charge or the allocation of costs based on peak day demand." 137/ The Commission believes it is appropriate to "minimize significant cost shifting" among customers, 138/ so that the impact of adopting SFV to aid competition as discussed in Order Nos. 636 and 636-A is not distributed inequitably among the shippers of varying load profiles on the interstate pipeline network. The Commission also continues to strongly encourage the use of seasonal contract quantities to mitigate significant cost shifts that may occur owing to the adoption of SFV. However, the Commission recognizes that it may not be appropriate in all circumstances to use seasonal contract quantities and encourages creativity in the tailoring of mitigation techniques suited to the specific facts of each case. Hence, the Commission will not, as requested by the APGA, adopt a presumption favoring the use of seasonal contract quantities. 2. Meaning of Significant Cost Shifts Several petitioners ask the Commission to define significant cost shifting. Allied-Signal maintains that at a minimum this means a ten percent or more rate impact of SFV on any customer class. The Industrial Groups would define a significant increase as over ten percent. The Producer Associations would also apply 137/ Order No. 636-A at p. 30,599. 138/ Id. Docket No. RM91-11-004, et al. - 98 - the 10 percent threshold. Sierra argues that all costs (transportation, storage, and gas costs) reflected in the delivery price of gas to the pipeline's customer must be considered. The Commission clarifies that all transportation costs (i.e., costs allocated to transmission, including system storage retained by the pipeline) are to be considered in applying the "significant" cost shift test. 139/ The delivered cost of gas is irrelevant to the impact of SFV on a customer's transportation costs. In addition, this test is to be applied by customer rather by customer class. 140/ However, the Commission declines to set a bright-line test for determining "significant" cost shifts because this depends heavily on the facts of each case. The only bright-line test occurs at the end of the restructuring ratemaking process when pipelines must phase-in cost shifts over no more than a four-year period, if the use of SFV, after implementation of other ratemaking techniques designed to minimize cost shifts, still results in a 10 percent 139/ In addition, if the pipeline used MFV to design its contract storage rates, it must determine if the use of SFV will result in a significant cost shift for existing contract storage customers. However, if the rate design for contract storage did not change, then it need not be included in determining whether significant cost shifts will occur. 140/ Northwest Pipeline Corp. 61 FERC  61,165 (1992), United Gas Pipeline Co., 61 FERC  61,161 (1992), Alabama-Tennessee Natural Gas Co., 61 FERC  61,164 (1992), Mississippi River Transmission Corp., 61 FERC  61,163 (1992), and Pauite Pipeline Co., 61 FERC  61,162 (1992). Docket No. RM91-11-004, et al. - 99 - or greater increase in revenue responsibility for any historic customer class. Allied-Signal argues that the use of different ratemaking techniques should be used to mitigate the significant impact of SFV and not to eliminate all cost shifts by putting customers into the same revenue position as they were under MFV. Similarly the Fuel Managers Association contends that mitigation must not create cost shifting to high load factor customers by over- mitigating the cost shift to low load factor customers caused by SFV. The Commission clarifies its goal is to avoid significant cost shifts resulting from the change to SFV and not to provide an opportunity for some customers to make themselves better off at the expense of other customers. 3. Phase-Out The Industrial Groups contend that any ratemaking techniques used to avoid significant impacts should be phased out over the four-year transition period. Sierra also argues that these measures should be transitional, as were D-2s, and not permanent. The Commission clarifies that there is to be no automatic phase-out period for any technique used to avoid potential significant shifts in the assignment of revenue responsibility. The Commission will examine the appropriateness of the assignment of revenue responsibility in future NGA section 4 or 5 cases. Customers can file complaints under NGA section 5 for Commission reconsideration of the lawfulness of effective rates and the underlying method for distributing the revenue requirement. Docket No. RM91-11-004, et al. - 100 - 4. Seasonal Capacity Availability and Seasonal Rates The Fuel Managers Association argues that pipelines must make available, on an open access basis, any seasonal firm capacity that becomes available through the use of seasonal contract quantities. Similarly, Blue Flame argues that the pipelines should be able to offer services that take advantage of seasonal demands for gas from special use customers. Blue Flame maintains that the Commission should not have discouraged the creation of customer classes, 141/ which limits pipeline services to firm peak-day transportation, interruptible transportation and the small customer transportation services. The Fuel Managers Association also argues that the Commission should clarify that the use of seasonal rates is particularly important to encourage the use of capacity in non- winter periods that becomes available because of the use of seasonal contract quantities. It is concerned that pipelines will have little incentive to discount rates if all costs are allocated to existing customers. Sierra argues that any seasonal allocation to address shifts in revenue responsibility must reflect cost incurrence with costs classified between winter and summer seasons and then allocated 141/ Blue Flame refers to the statement in Order No. 636-A that "as a general matter, the Commission discourages the creation of customer classes, other than the special small customer class provided for in this rule, or if necessary during the four year mitigation period." Order No. 636-A at p. 30,599-60. Docket No. RM91-11-004, et al. - 101 - based on seasonal demands to yield winter and summer reservation charges. The Commission clarifies that it has put no limit on the current ability of pipelines to offer firm transportation service in any particular circumstance. Part 284 pipelines have always been and remain required to offer all firm capacity that becomes available. This will include capacity that becomes available through the use of seasonal contract quantities, 142/ subject to any operational constraints. The Commission will not require seasonal rates. 143/ Seasonal rates are not related to the instant rule's goals or to the mitigation of significant cost shifts. 144/ As indicated in Order No. 636-A, it may be appropriate to apply the principles enunciated in the Rate Design Policy Statement in determining whether seasonal rates are appropriate. 145/ The Commission will consider the Fuel Managers Association's argument about the incentive to discount in connection with a particular case involving off-peak service. 142/ See Northern Natural Gas Co., 61 FERC  61,079 (1992) (approving rate schedule under which shippers can transport on a seasonal basis). 143/ Seasonal entitlements differ from seasonal rates in that seasonal entitlements may yield one rate applicable throughput the year. See Order No. 636-A at p. 30,599 n. 308 for an example. 144/ See Order No. 636-A at p. 30,606 with respect to cost incurrence and the instant rule. 145/ Id. at p. 30,605. Docket No. RM91-11-004, et al. - 102 - 5. Annual Allocation Measures In Order No. 636-A, the Commission concluded that pipelines may not continue to use two-part reservation charges for either allocation or billing purposes. The APGA asks the Commission to clarify that pipelines and their customers may use D-2 charges, if D-2s serve the purpose of distributing revenue responsibility among customers to avoid significant cost shifting. The APGA maintains that D-2s may be the best solution to cost shifting on certain pipelines. CIG argues that a two-part demand charge does not undermine the Commission's policies in adopting SFV, because the charge is not based on usage but is assessed on the basis of peak entitlements regardless of actual volumes transported. CIG adds that a two-part demand charge might be appropriate if a pipeline, like CIG, cannot provide maximum service entitlement levels throughout the year. It asserts that this would properly reflect cost incurrence. CIG further argues that a two-part reservation charge is consistent with the mitigation of cost shifts and is superior to seasonal contract quantities, because on its system temperature fluctuations occur throughout the year. Southwest Gas argues that the Commission should permit D-2 charges because they are not a usage based charge. It adds that the end-result should determine the reasonableness of any approach. The Commission concludes again that pipelines may not use two-part reservation charges for billing. It is true that the Docket No. RM91-11-004, et al. - 103 - D-2 charge is not a usage charge in the sense that customers pay as they take service. However, the D-2 charge is similar to a usage charge in that the D-2 charge was to reflect demand for annual service in light of estimated use. In any event, the D-2 charge was derived, in part, to help pipelines in their role as merchants by enabling them to better estimate customers' annual gas purchases. In the competitive sales market with competitive pricing mechanisms for unbundled gas sales, which may include some type of gas inventory charge, the D-2 is no longer needed. Seasonal contract quantities also reflect the fact that a pipeline cannot provide maximum service levels throughout the year by allowing lower off-peak levels. That there are temperature fluctuations throughout the year does not militate against seasonal contract quantities. Rather, it suggests the use of monthly contract quantities, which the Commission encourages the parties to pursue in the restructuring, or subsequent, proceedings. However, pipelines may use annual measures for cost allocation so long as only a one-part reservation charge is used for billing purposes. As stated in Order No. 636-A, the Commission will not foreclose the use of any annual measures as a vehicle for allocating revenue responsibility (e.g., among rate zones) so long as the pipeline uses a one-part reservation charge for billing purposes and does not create different charges in the tariff for individual customers because of the use of D-2s or Docket No. RM91-11-004, et al. - 104 - other annual allocation measures. 146/ The Commission is permitting the use of annual measures because they may be the most appropriate method for certain cost allocations (e.g., among rate zones) to avoid significant shifts of revenue responsibility. Last, CIG states that its annual service limitations predate the Commission's adoption of the modified fixed variable method, have been negotiated based on operational constraints, and are incorporated in its certificates. Hence, it seeks clarification that the adoption of a one-part reservation charge does not affect its annual service limitations. The Producer Associations argue that if the Commission allows fixed cost allocation based on D-2 nominations, customers should pay higher rates for taking deliveries over their nominations and should not be allowed to release capacity in excess of the nominated level. Similarly, Allied-Signal argues that, if annual volumes are used as a mitigation technique, there should be some restriction on the ability of a customer to demand service above its annual level without penalty. The Commission clarifies that a pipeline may retain some form of annual service limitation post-restructuring in connection with a one-part reservation charge, as long as the annual service limitation does not operate as a D-2 charge. Furthermore, nothing in this rule obligates a pipeline to provide service in excess of its pre-restructuring certificate 146/ Order No. 636-A at p. 30,595 n. 287. Docket No. RM91-11-004, et al. - 105 - obligations. In any event, this issue is unrelated to the rate design issues addressed in Order No. 636. 6. Capacity Reduction Meridian argues that SFV should only be adopted if the pipeline is capacity-constrained or full unless the customers are permitted to reduce or terminate their service unilaterally. In Order Nos. 636 and 636-A, the Commission denied the right of customers to unilaterally reduce or terminate transportation service from the pipeline. The Commission also, as discussed in Order No. 636-A, did not apply the policy of adopting a rate design to ration capacity because in "the prevalent economic and market circumstances, . . . the goal of achieving an efficient, national gas market is the factor that should control the selection of appropriate rate design method." 147/ Hence, Meridian's argument is rejected. B. Rates for Small Customers In Order No. 636-A, the Commission clarified that all pipelines that on May 18, 1992, offered a small customer sales or transportation rate service on a one-part volumetric basis at an imputed load factor rate must continue to offer firm and no- notice transportation services on the same basis. The Commission also suggested pipelines should consider increasing the class of 147/ Order No. 636-A at p. 30,605. See also Order No. 636-A at pp. 30,637-38, where the Commission concludes that customers do not have the unilateral right to cost-free releases of capacity. Docket No. RM91-11-004, et al. - 106 - small customers by raising the eligibility level to up to 10,000 Mcf or Dth per day. 1. The Use of an Imputed Load Factor Peoples Gas, the Northern Distributor Group, and Atlanta Gas argue that there is no basis for the Commission's requirement that pipelines continue indefinitely to offer small customers a one-part volumetric rate at an imputed load factor. They argue, among other things, that this results in two shippers paying different rates for the same service and is therefore discriminatory. They also argue it is unfair because large LDCs serve customers in poorer communities in large urban areas and serve communities that are smaller than the pipeline's small customers. The Northern Distributor Group argues that, as provided in Order No. 636, imputed load factor rates for small customers should only be used as a transitional measure to be phased-out within four years. It asserts that this will adequately protect small customers against cost shifts. It also maintains that the use of imputed load factors results in a subsidy which does not serve equality or competitiveness. It adds that the requirement that the rate be changed only in an NGA section 4 or section 5 proceeding will have a chilling impact on changes because the burden will be on the proponent of change and that the pipeline will have little incentive to change the rate because it is recovering its costs. It concludes that either the rate should be negotiable in the restructuring proceedings or prior Docket No. RM91-11-004, et al. - 107 - settlements should remain in effect. In that vein, it contends that a settlement with Northern Natural Gas Company contemplated the eventual elimination of one-part rates. 148/ The Commission's aim with respect to service to small customers is to continue the status quo prior to the instant rule, subject to the few changes in terms and conditions adopted in this Rule. While some petitioners read Order No. 636 to mean that service to small customers at a one-part rate was to be continued only in connection with phased-out mitigation, that was not the Commission's intent. Arguments that the small customer rate should be discontinued should be raised in pipeline proceedings under NGA sections 4 or 5. 149/ On the other hand, the APGA argues that the Commission erred in failing to make the one-part rate design for small customers, as well as other ratemaking techniques employed to moderate the impact of SFV, a permanent rate design requirement for pipelines. 150/ In the alternative, the APGA asks the Commission to rule that any changes to the one-part rate design 148/ Northern Natural Gas Co., 53 FERC  61,207 at p. 61,835 (1990). The rate was for a three-year period ending September 30, 1993. 149/ The Commission has, however, incorporated parts of pending proceedings with respect to rate design issues, which include one-part rate matters, into restructuring proceedings. Florida Gas Transmission Co., 61 FERC  61,019 (1992). 150/ The temporal status of the other ratemaking techniques is discussed in other sections of this order. Docket No. RM91-11-004, et al. - 108 - can only be made prospectively under NGA section 5 rather than under NGA section 4, subject to refund. The Northern Distributor Group argues that the use of a small customer imputed load factor rate should be phased-out within four years. As indicated above, the one-part rate design for small customers was continued because the Commission did not intend to change it in this rule. It is no more or less permanent than any rate design and may be changed under sections 4 and 5 of the NGA. Because the one-part rate design for small customers is a continuation of the status quo, it is not subject to phase-out under the instant rule. 2. Adjustments to Imputed Load Factor In Order No. 636-A, the Commission stated that the pipeline's one-part, volumetric rate for its small customer service should be computed using the same imputed load factor as was used to compute its previous rate for its small customer sales service. CIG seeks clarification that it can propose to adjust the imputed load factor to reflect changes in the load factor of small customers caused by Order No. 636. It maintains that this may be necessary to ensure that the imputed load factor does not substantially exceed the actual load factor. The Gas Consumers argues that the Commission should require pipelines to derive their one-part rates using the system-wide load factor. It maintains that this is necessary to mitigate Docket No. RM91-11-004, et al. - 109 - cost shifts, which is not done by using the class load factor. It asserts that a Commission mandate is sought because small customers lack the leverage to bargain for such a load factor. The Northern Distributor Group argues that pipelines should be allowed in their compliance filings to propose lowering their current imputed load factor for small customer rates. As stated above, the Commission intends no change in its current policies with respect to the small customer rate. 151/ This includes retention of the imputed load factor used to compute the rate for the small customer sales service unless there is warrant for increasing the imputed load factor as a measure to avoid shifts in revenue responsibility. However, the imputed load factor may not be decreased in the restructuring proceedings. 152/ 3. Eligibility Date In Order No. 636-A, the Commission required pipelines that, on May 18, 1992, offered a small customer sales or transportation service at a one-part volumetric rate, with an imputed load 151/ The only mandatory exception relates to restrictive criteria needed to ensure the pipeline has the opportunity to recover costs assigned to the small customer service. For example, the small customer must exhaust its daily level of firm entitlement before shipping gas under any interruptible transportation service available from the pipeline. 152/ An exception would exist when the issue has been raised in a rate proceeding that has been incorporated into the restructuring proceeding. E.g., Florida Gas Transmission Co., 61 FERC  61,019 (1992). Docket No. RM91-11-004, et al. - 110 - factor, to offer all of its firm transportation services on the same basis to eligible small customers. The Gas Consumers argue that the Commission's justification for the use of one-part rates applies equally to all customers with peak capabilities of less than 10,000 Mcf per day, regardless of whether they were charged previously under one-part rates with imputed load factors. The Gas Consumers maintain that if the Commission grandfathers the one-part rate, it should do so with respect to all pipelines that ever offered service at a one-part rate to small customers, because many pipelines have replaced their one-part rates with two-part rates. Hence, it states, that, on May 18, 1992, most small customers that had received service under a one-part rate for years were receiving service under a two-part rate. The Northern Distributor Group argues that the small customer class should not be open to customers new to a pipeline system after May 18, 1992, to avoid further subsidies, which prevent unfair competition. The Commission clarifies that, if a downstream pipeline offered service at a small customer rate on May 18, 1992, it must offer it to all customers directly connected to it who meet its eligibility criteria, even if such a customer was not a customer at that rate on May 18, 1992. The Commission's intent in Order No. 636-A was to grandfather service at the small customer rate to a particular class of customers and not particular customers. 153/ That is, if the pipeline had a small customer rate 153/ Order No. 636-A at p. 30,600. Docket No. RM91-11-004, et al. - 111 - schedule on May 18, 1992, it must retain that schedule and offer service thereunder to all customers who qualify. If a pipeline had discontinued all service at its small customer rate on May 18, 1992, and the Commission has approved of that discontinuation, it need not reinstate it because small customers were not relying on it. 154/ As discussed below, there may be different considerations for customers of downstream pipelines that take assignments of capacity on upstream pipelines. 4. Upstream Pipelines The APGA seeks clarification about the transportation rate to be paid by small customers which acquire upstream capacity under section 284.242 of the Commission's regulations. It maintains that the small customers charged a one-part rate by the downstream pipeline for transportion should also be charged a one-part rate by the upstream pipeline for upstream transportation. The APGA adds that the upstream pipeline must charge the one-part rate to one-part customers of downstream pipelines, even if the upstream pipeline has no direct customers that qualify for that rate. TVMGA asks whether a pipeline that offered such a service on May 18, 1992, must offer the similar service to a small customer that was not receiving the small customer service on May 18, 1992. It maintains that this is important to small customers of 154/ In response to Gas Consumers' comment, the Commission notes that a majority of pipelines currently offer small customer service using a one-part rate. Docket No. RM91-11-004, et al. - 112 - downstream pipelines which will be taking service on upstream pipelines. The Commission will not require upstream pipelines without a small customer service on May 18, 1992, to institute a small customer service to provide a small customer rate for transportation to small customers on downstream pipelines which, under section 284.242, are receiving an assignment of upstream transportation capacity held by the downstream pipeline. However, if an upstream pipeline had a small customer service on May 18, 1992, the issue of whether it should provide a one-part transportation rate to small customers receiving an assignment of upstream capacity should be considered in the restructuring proceeding. This will enable the parties to consider the small customers' need for such a service on the upstream pipeline and the impact of the additional small customers on the rates charged to the upstream pipeline's current customers under the small customer schedule and its customers paying a two-part rate. 5. Eligibility Criteria In Order No. 636-A, the Commission stated that eligibility criteria for the small customer rate service would be based on existing criteria. 155/ CIG states that one such standard is that eligible entities must be LDCs or municipally-owned gas systems. It asks the Commission to clarify whether CIG can retain this standard and exclude non-LDCs and non-municipalities 155/ This is other than the new criteria set forth in Order No. 636-A, relating to interruptible service and released capacity. See infra. Docket No. RM91-11-004, et al. - 113 - (e.g., producers and marketers) in the new small customer transportation rate schedule. Consolidated Minerals, a direct customer of Florida Gas Transmission Company, argues that pipelines should be required to offer the small customer mitigation measure to all customers using small quantities of gas, whether or not they were jurisdictional customers. Interstate Power asks for clarification that the small customer rate be based only on service criteria in the rate schedule and not on the status of the customer, whether it is an LDC or a municipal utility. As stated, the Commission's intent was not to modify eligibility criteria, except as needed to ensure that the pipeline recovers its costs. Hence, the Commission has made no change to the pipeline's service criteria, including its criteria with respect to the nature of the customer. A direct customer, therefore, would be eligible only if eligible under existing criteria, unless the parties to the restructuring proceeding otherwise agree. In Order No. 636-A, the Commission required pipelines to consider enlarging the size of the small customer class to include any customer with the right to transport up to 10,000 Mcf or Dth per day on a firm basis in order to mitigate the effect of shifting to SFV on small customers who do not currently qualify for a pipeline's small customer rate schedule. The Commission stated further that whether the small customer class should be so Docket No. RM91-11-004, et al. - 114 - enlarged on a specific pipeline is an issue to be considered by the parties in the specific restructuring proceedings. Atlanta Gas argues that the Commission has offered no justification for requiring pipelines to enlarge the size of the small customer class to include any customer with the right to ship up to 10,000 Mcf per day on a firm basis. It objects to the Commission's explanation that this will mitigate cost shifts caused by SFV as not reasoned. Prior Energy argues that the Commission's definition of small customer, as one who ships no more than 10,000 Mcf or Dth of natural gas per day, will enable far too many shippers to qualify. It would permit only customers who at present qualify as small customers on each pipeline to keep that status. Blue Flame also contends that the Commission erred in finding it appropriate to increase the size of the small customers class up to 10,000 Mcf or Dth per day. It asserts this will shift more costs to the usage charge and have an adverse impact on wellhead prices. It maintains that the use of seasonal reservation quantities will adequately treat undue cost shifts and that further mitigation for small customers is an undue preference. Peoples Gas also opposes increasing the class of small customers as suggested by Order No. 636-A because it will simply increase their subsidy. The Commission believes that the issue of whether a particular pipeline should increase the size of the small Docket No. RM91-11-004, et al. - 115 - customer class up to 10,000 Mcf or Dth per day should be addressed in the restructuring proceedings. If necessary, the Commission will examine the issue on the merits, which will, among other things, enable the Commission to examine the extent of any cost shift to the non-small customers and to consider whether such an increase is so pervasive as to have an adverse impact on achieving the goals of the instant rule. In response to Blue Flame, the Commission observes that, unlike seasonal contract quantities, the one-part rate enables the small customers to match payments with receipt of service. In Order No. 636-A, the Commission imposed two restrictions on eligibility for service at the small customer transportation rate. These were that the shipper cannot ship gas under any interruptible transportation service available from the pipeline and cannot ship gas as a replacement shipper under the capacity releasing mechanism of section 284.243 of the Commission's regulations unless the customer has exhausted its daily level of firm entitlement for that day. Tenneco argues that additional restrictions are needed. It maintains that "no other shipper should be permitted to use the small customer's delivery point(s) as secondary points under a firm agreement, and small customers must be prohibited from receiving gas at their delivery points from an [interruptible transportation] shipper." 156/ Tenneco claims that unless this loophole is closed "a small customer could circumvent the 156/ Petition at 9. Docket No. RM91-11-004, et al. - 116 - Commission's restrictions by simply buying gas from a third party shipper at its delivery point and receiving the difference between the shipper's transportation and its own [firm transportation] rate through the price it would pay for the gas." 157/ The Commission's clarifies that its intent was that small customers receiving service at the small customer rate must first use the pipeline's firm transportation under the small customer rate schedule to provide the pipeline with the opportunity to recover its costs assigned to that service. Tenneco's argument comports with the Commission's interpretation of its regulations because it would prohibit evasion of the pipeline's firm transportation under the small customer service. A small customer should not be able to receive gas from third parties at the small customer's delivery points unless the small customer has exhausted its daily level of firm entitlement for that day in the aggregate. Elizabethtown argues that the Commission should eliminate the condition that it (and others) cannot have access to interruptible transportation on Tennessee Gas Pipeline Company's (Tennessee) system at the same time it is using its small customer firm transportation service. Elizabethtown states that it must use interruptible transportation to avoid incurring penalties for exceeding its maximum annual quantity for firm service. Elizabethtown's argument is case-specific and should be 157/ Id. Docket No. RM91-11-004, et al. - 117 - raised in the Tennessee restructuring proceeding so that the Commission can determine, in acting on Tennessee's compliance filing, whether good cause exists to grant relief to Elizabethtown. 6. On-going Proceedings Section 284.14(b)(3)(iv)(A) provides that a pipeline that must offer the small customer service must do so "on the same basis and under the same eligibility criteria as the small customer sales or transportation rate under the pipeline's last- approved tariff provisions for those services." FMNGA states that on May 18, 1992, Florida Gas Transmission Company was billing its small customers on a two-part rate that is subject to refund and to the outcome of a hearing and a final Commission order yet to issue. 158/ Florida Gas' proposed two-part rate was designed to recover the same revenue as the one-part rate contained in its last approved tariff. FMNGA asks the Commission to require Florida Gas to serve its small customers under either (1) the last-approved small customer rate or (2) a small customer rate that is at least as favorable as the rate treatment small customers were receiving as of May 18, 1992, even though the rate may not be a one-part rate based on an imputed load factor. Atlanta Gas argues that the gas subsidy issue is being challenged on certain pipelines such as Southern Natural Gas 158/ See Florida Gas Transmission Co., 56 FERC  61,180, order on reh'g, 57 FERC  61,171, order denying reh'g, 57 FERC  61,376 (1991). Docket No. RM91-11-004, et al. - 118 - Company and so the Commission has erred by deciding the merits of cases subject to on-the-record adjudications, without due process of law. It adds that deferring the resolution of the issue to a new rate proceeding is no answer. The Commission has required Florida Gas to include as part of its compliance filing in Docket No. RS92-16-000 tariff sheets that offer firm transportation service on a one-part volumetric basis to customers presently serviced under Florida Gas' small customer rate schedule. 159/ FMNGA should raise its issues about Florida Gas' treatment of small customers in Florida Gas' restructuring proceeding. The application of the generic determinations will be decided in the specific restructuring cases, with respect to the continuation of small customer rate schedules. C. Miscellaneous Issues 1. Choice of Rates The Municipal Gas Authority of Georgia asks whether small customers have the option to select one-part rate treatment or a two-part rate structure with seasonal billing determinants or some similar measure. It is concerned that on some pipelines it might be argued that seasonal billing determinants or some similar measure are not needed to comply with Order Nos. 636 and 636-A, if the pipeline simply offers a one-part firm transportation rate to small customers. It argues in support that it cannot compete for interruptible industrial load with 159/ Florida Gas Transmission Co., 61 FERC  61,019 (1992). Docket No. RM91-11-004, et al. - 119 - interruptible transportation rates or with released capacity. In addition, it maintains it cannot accept two-part SFV rates without seasonal-type billing determinants. It describes this as a no-win situation, which provides no motivation for small customers to reduce any unnecessary contract entitlement or pursue industrial load. It asks the Commission to require the pipelines to provide a two-part rate structure with seasonal billing determinants for small, low load factor customers, whether or not such billing determinants are established for larger customers, as an option in lieu of one-part rates. The Commission clarifies that the requirement that pipelines continue to offer service to their small customers at the one- part rate, computed using an imputed load factor, and the requirement that they mitigate for significant cost shifts that may occur are independent. If a small customer wants to switch to a two-part rate, it may do so. The pipeline would then have to adopt measures to avoid a significant shift in revenue responsibility due to the switch to SFV, but not due to the loss of the imputed load factor. 2. Phasing-In Cost Shifts In Order No. 636, as modified by Order No. 636-A, the Commission directed pipelines to phase-in cost shifts, if the use of SFV, after implementation of other ratemaking techniques designed to minimize significant cost shifts, still results in a 10 percent or greater increase in revenue responsibility for any historic customer class. This bright line mitigation measure is Docket No. RM91-11-004, et al. - 120 - to phase-in any such rate increase over no more than a four-year period. Southwest Gas seeks clarification about whether a class consists of all those customers under a particular rate schedule or those customers served under a particular rate schedule within the same rate zone. It refers to the order in El Paso Natural Gas Co., as unclear. 160/ There, the Commission stated that it "intended pipelines to perform mitigation measures by rate schedules within specific zones and not just by zones" as unclear. 161/ In the alternative, it asks whether the definition of class is to be determined on a case-by-case basis. Southwest Gas also asks for clarification that the mitigation for 10 percent or greater cost shift applies only to those customers within a class or classes that meet the bright line test. The definition of class is to be determined on a case-by- case basis. However, contrary to Southwest, the mitigation measures required to be phased-in apply to the entire class, not to individual customers. Last, in response to the APGA's suggestion that this should be a permanent measure, 162/ the Commission reaffirms that this mitigation measure is transitional and not permanent. This is because it relates to historic 160/ 60 FERC  61,228 (1992). 161/ Id. at p. 61,768. 162/ The APGA also includes other mitigation measures in its argument that the rate for service to small customers should be permanent. Docket No. RM91-11-004, et al. - 121 - classes, some of which will no longer exist after unbundling is fully implemented. 3. Rates for Part 157 Transportation In Order No. 636-A, the Commission stated that pipelines must charge the same rates for individually authorized NGA section 7(c) (Part 157) transportation and for Part 284 transportation and that it will permit individually authorized transportation rates to be so designed. However, the Commission stated that a party may raise any objection to that design in the restructuring proceeding. Arkla objects to Part 157 shippers paying the same rates as Part 284 shippers for two reasons. First, it maintains that Part 157 transportation will, after restructuring, be inferior to Part 284 transportation (e.g., the former is not permitted to participate in capacity releasing or have flexible receipt and delivery points). Second, it asserts that most individual transportation arrangements are economic only because of the negotiated specific contract rates. It adds that Part 284 rates would unduly deprive the parties of the benefits of their bargains. JMC Power Projects argues that the application of SFV rates to Part 157 shippers without capacity releasing is capricious. The Commission clarifies that it intended only that rates for Part 157 transportation may be designed under SFV, with any appropriate mitigation. Docket No. RM91-11-004, et al. - 122 - The Commission did not mean that a pipeline had to charge the same reservation rate to both Part 157 transportation customers and Part 284 transportation customers. For example, an incremental reservation charge under Part 157 could be higher than a Part 284 reservation charge, even though both are designed under SFV. The application of SFV rates to Part 157 shippers is reasonable without capacity releasing because those shippers are entitled to mitigation to avoid significant shifts in revenue responsibility by customer and to the phasing-in of cost shifts of ten percent or greater for an historic customer class in connection with the application of SFV. 4. Contract Rates Mojave asks for clarification about whether it must adopt SFV when it has contractually agreed to the use of a rate design inconsistent with SFV. It states that while its filed rates are designed under MFV, its contracts provide for rates that put both return on and of equity in the usage charge. The Indicated Shippers respond that this issue is sui generis to Mojave and should be addressed in its restructuring proceeding where they plan to address it. 163/ The Commission agrees with the Indicated Shippers that this issue (of the effect of SFV on existing contracts), should be resolved in individual restructuring proceedings so that the Commission can be informed 163/ The Indicated Shippers' motion to file an answer out-of-time to Mojave's request for clarification and answer is granted. Docket No. RM91-11-004, et al. - 123 - fully about the facts and circumstances pertaining to those contracts and the positions of all parties. The Producer Associations ask the Commission to clarify on rehearing that the "pipeline cannot use two-party negotiations to defeat the procompetitive policies represented by the Commission's adoption of an SFV rate design." 164/ They are concerned about agreements between shippers and pipelines that specify MFV and about most favored nations clauses in some transportation agreements. The Commission reiterates that "it will carefully consider arguments for and against deviations from SFV, with the advocates against SFV bearing the burden of persuasion." 165/ In addition, as further stated in Order No. 636-A, "[a]t a minimum, opponents of SFV must demonstrate that SFV is not needed to effectuate the goals of Order No. 636." 166/ 5. Demand Charge Credits In Order No. 636-A, the Commission concluded that the issue of whether pipelines should be required to provide demand charge credits during service interruption or curtailment, to provide an incentive to expeditiously restore service, should be resolved in individual rate proceedings because it does not pertain to Order No. 636. 167/ 164/ Petition at 5. 165/ Order No. 636-A at p. 30,605. 166/ Id. 167/ Id. at p. 30,607. Docket No. RM91-11-004, et al. - 124 - AGD argues that the imposition of an SFV rate design methodology justifies addressing this issue because it inseparably links firm service and demand charge payments. AGD also maintains that, by not allowing this issue to be considered in the restructuring proceedings, the Commission may have given pipelines unfair bargaining leverage. Last, it contends that the Commission has acted inconsistently with its prior treatment of this issue in Northern Natural Gas Co., where it required the pipeline to give curtailed firm customers demand charge credits. 168/ ConEd similarly argues that the Commission should address this issue in the restructuring proceedings because it is linked to SFV. The Commission denies rehearing because it believes that this issue pertains to a demand charge designed under any rate design and is not so intimately related to SFV or any other provision of Order No. 636 as to require treatment in a restructuring proceeding. 6. Impact of Order No. 636 on Incremental Rates In Order No. 636-A, the Commission stated the following about the impact of Order No. 636 on vintage pricing: Great Lakes Transmission Limited Partnership (Great Lakes) requests clarification that equal transportation on even terms requires the elimination of vintage pricing in favor of a uniform, market-based rate for comparable transportation services (constrained by the pipeline's highest cost-based tariff rate applicable to such services). The Commission will address this issue in Great Lakes' own proceedings concerned with vintage 168/ 57 FERC  61,105 at p. 61,408 (1991). Docket No. RM91-11-004, et al. - 125 - pricing rather than here or in the restructuring proceeding. 169/ Great Lakes and TransCanada ask whether the vintage issue is to be explored in Docket No. RP91-143, which is to deal with other issues with respect to implementing the incremental rates mandated for certain of Great Lakes' new services. 170/ The Fuel Managers Association asks the Commission to clarify that, during the restructuring proceedings, it will consider "whether a pipeline's use of incremental facilities would, as a result of restructuring, (a) justify rolled-in rate treatment for the incremental facilities or (b) require other mitigation measures in such matters as cost allocation or rate design to obtain fair and equitable treatment for incrementally-priced customers." 171/ The Commission agrees that issues with respect to the impact of the instant rule on so-called "vintage pricing" on Great Lakes should be addressed in Docket No. RP91-143. This issue is currently before the Commission and will be considered with the rehearing petitions of Opinion Nos. 367 and 368 and is not to be 169/ Order No. 636-A at p. 30,608. 170/ Great Lakes Transmission Limited Partnership, Opinion No. 367, 57 FERC  61,140 and, Opinion No. 368, 57 FERC  61,141 (1991), reh'g pending of both opinions. The motions of Northern, Texas Eastern Transmission Corporation, and Natural to answer the requests for clarification by Great Lakes and TransCanada are granted. 171/ Petition at 9. They describe as benefits the additional line pack which may aid in the providing of no-notice service and the facilitation of releasing of aggregated capacity caused by increased pipeline capacity due to expansion. Docket No. RM91-11-004, et al. - 126 - considered in Great Lakes' restructuring proceeding. 172/ Further, to the extent the Commission has not previously acted on other rolled-in/incremental issues, they may be addressed in the restructuring proceedings. 7. Processing Rights The Producer Associations argue that the Commission should adopt a generic policy applicable to all Part 284 pipelines engaging in gas processing and suggests the adoption of proposed language dealing with credits and other issues related to processing. The Commission will not use this rulemaking as a vehicle for adopting specific generic language with respect to gas processing since the rulemaking was not intended or designed to adopt generic rules or policies pertaining to gas processing except that the Commission, generally supports the principle that rates for processing should be unbundled from other services. 173/ Further, the Commission has not received comment on the proposed language from other parties. VI. PIPELINE SALES In Order No. 636, the Commission issued blanket sales certificates to open access pipelines authorizing firm and interruptible sales for resale at market-based rates. On rehearing of Order No. 636, the Commission modified Order No. 636 172/ Great Lakes Gas Transmission Limited Partnership, 57 FERC  61,140 and  61,141 (1991). 173/ Order No. 636-A at p. 30, 609 ("[T]he Commission repeats its strong preference for fully unbundled services"). Docket No. RM91-11-004, et al. - 127 - to require pipelines to continue to sell gas to their current small sales customers at a rate that is cost-based for a transitional one-year period. 174/ On rehearing, CNG asks the Commission to clarify that pipelines may impose take-or-pay obligations, minimum bills, one- part demand charges, or other reasonable terms to compensate the pipeline for acquiring the supplies needed to provide sales service to small customers. Further, CNG asks the Commission to condition small customer access to interruptible transportation and released capacity on the customer's satisfaction of its daily level of gas purchases from the pipeline. CNG asserts that small customers will have many options to secure supplies and that pipelines should not be compelled to secure supplies for one year without the small customers incurring some reciprocal obligation to purchase gas from the pipeline, or, at a minimum, compensate the pipeline for standing ready to serve. CNG notes that the Commission recognized the need for mutuality when it addressed small customers' transportation rates and conditioned small customers' access to released capacity and to interruptible transportation on a small customer's exhaustion of its daily levels of firm service entitlement for the day, and that the Commission should treat small customer sales similarly. The Commission will not impose any minimum take requirements on the small customers and will not condition their access to released capacity or interruptible transportation on exhaustion 174/ Order No. 636-A at p. 30,600. Docket No. RM91-11-004, et al. - 128 - of daily purchase requirements. The purpose of providing a transition period for small volume customers is to provide those customers with an opportunity to adjust to purchasing at negotiated prices and to gain experience in dealing with other suppliers. Requiring the small customer to meet minimum purchase requirements would defeat the purpose of this provision. The transitional sales rate should not impose a significant burden on the pipelines. The provision is temporary and will be in effect for only a brief, one-year period. Moreover, by definition, the customers purchasing under this rate will be taking small volumes and the supply impact on the pipeline should be negligible. If a pipeline believes that the supply impact on its system will be substantial, it may address this issue in its restructuring proceeding. For these same reasons, the Commission will not authorize the pipelines to reinstitute a minimum bill for small customers for the transition period. The pipelines have no minimum bill today and the transition period merely maintains the status quo for small customers. The pipelines will be able to recover the gas costs associated with providing this service, but may not do so through minimum take or minimum bill requirements. The pipelines should address in the restructuring proceedings other proposals for cost recovery. PGT asks the Commission to clarify that Order No. 636-A does not preclude cost-based sales rates for other customers as well Docket No. RM91-11-004, et al. - 129 - as small customers. PGT notes that in the NOPR, the Commission specifically indicated that pipelines could chose between cost- based or market-based rates, 175/ but that Order No. 636 does not specifically address this issue. PGT also refers to the statement in Order No. 636-A that the Commission expects that pipelines will terminate their PGA mechanisms and initiate market based pricing of gas in order to remain competitive in the sales market, 176/ but that pipelines are not prohibited from negotiating cost-tracking systems with their customers. 177/ The Commission clarifies that the blanket certificates authorize the pipelines to negotiate sales rates with their customers, and nothing in the rule prohibits the pipelines and customers from agreeing to rates that are based strictly on costs or, for that matter, any other basis. However, the Commission will not establish specific cost-based rates for gas sales for the parties and will not design a specific mechanism for gas cost recovery. This is a matter for negotiation between the parties. Because the Commission has decided to allow the parties to negotiate gas sales prices, the Commission will not engage in the same kind of regulatory oversight and review that it has used with the PGA mechanisms for the review of gas sales prices. The Commission intends to concentrate its regulatory focus on the transportation aspects of the pipeline's business. However, as 175/ IV FERC Stats & Regs  32,480 at pp. 32,559 - 32,560 (1991). 176/ Order No. 636-A at p. 30,651. 177/ Id. at 30,651 n.473. Docket No. RM91-11-004, et al. - 130 - the Commission explained in Order No. 636, 178/ the parties to the restructuring proceedings may seek to prove that adequate divertible supplies of gas do not exist with respect to a particular pipeline and, if the parties sustain the burden of proof on this issue, the Commission will engage in more active regulation of that pipeline's sales. VII. PIPELINE SERVICE OBLIGATION (AFTER RESTRUCTURING) In Order No. 636-A, the Commission modified Order No. 636 to provide that in exercising the right of first refusal to retain capacity, the long-term firm transportation customer must match the price offered by a competing bidder, up to the maximum just and reasonable rate, and the longest contract term, up to a maximum period of 20 years. The requests for rehearing 179/ object to the Commission's determination that capping the bidding at 20 years is an appropriate balance of the pipeline's need for stability and the customer's need for flexibility. In addition, UDC and UGI Utilities argue that the Commission should exempt from pregranted abandonment all firm shippers with contractual waivers of pre-granted abandonment. LILCO and APGA ask the Commission to require pipelines to accept the highest bid for capacity, even if the bid is below the maximum rate. A. Length of Contract Term 178/ Order No. 636 at p. 30,441. 179/ Requests for rehearing on this portion of the rule were filed by AGA, AGD, ConEd, Interstate Power, Utilicorp Divisions, Northern States, Peoples Gas, PSE&G, UGI, UDC, Washington Gas, State Commissions, NJBRC, Industrial Groups and Consolidated Minerals. Docket No. RM91-11-004, et al. - 131 - The parties argue that the 20-year cap on the bidding adopted by the Commission does not reflect the comments of the parties, does not remedy their concerns, does not address pertinent facts raised by the parties, is not supported by record evidence, and, therefore, is arbitrary, capricious, and not reasoned decisionmaking. These parties note that the majority of commenters asked for a cap on the bidding at a term of five years, others asked for a cap of three to ten years, but no one suggested the 20-year cap adopted by the Commission. In addition, they assert that the Commission has not addressed their concern that LDCs cannot accurately forecast their needs so far into the future nor answered their argument that this bidding requirement will in fact limit competition, contrary to the goals of the rule, by denying LDCs the flexibility to respond to changing market conditions. 180/ Further, the parties state the Commission has failed to respond to the contention that this bidding requirement tips the balance in favor of unregulated producers and marketers and will encourage speculation in pipeline capacity. Consolidated Minerals argues that under the rule, large shippers will reserve space on constrained pipelines to repackage it, and thus will determine who will have access to the pipeline. 180/ State Commissions note that the Department of Energy has recently sought comments on the effect of long term contracts on competition for natural gas. Notice of Inquiry, 57 Fed. Reg. 38182 (August 21, 1992). Docket No. RM91-11-004, et al. - 132 - In addition, State Commissions argue that the Commission failed to explain why long-term needs should have priority over short-term needs, and Interstate Power argues that the Commission failed to address its concern that these long-term contracts will not withstand state prudence reviews. People's Gas and UGI argue that this provision, coupled with the SFV rate design, will give pipelines no incentive to maintain or improve service. AGD and Interstate Power assert that there is no record evidence to support the Commission's rationale that 20 years has been the traditional length of service contracts in the industry. Further, several parties assert that the examples given by the Commission of such long-term contracts 181/ are not representative of industry practice because these contracts support construction, and new projects generally require long- term agreements to support financing arrangements. The Commission denies rehearing on this issue. The parties have misunderstood the purpose of the bidding cap and how the Commission expects the cap to function. Various parties have suggested that the Commission cap the bidding at one to ten years because they believe that to be an appropriate contract length for them in the current environment. The Commission, however, will not select the contract term for the parties. The purpose of the rule is to permit the market to determine contract terms, 181/ The Commission cited Pacific Gas Transmission, 56 FERC  61,192 (1991) and Iroquois Gas Transmission System, 53 FERC  61,194 (1990), reh'g granted in part and denied in part, 54 FERC  61,103 (1991) as examples of 20-year contracts. Order No. 636-A at p. 30,631 n.437. Docket No. RM91-11-004, et al. - 133 - including duration. Therefore, the Commission capped the bidding at what it believes to be a reasonable outer boundary which still permits flexibility. The Commission is not requiring 20-year contracts and does not expect 20-year contracts to become the norm. Rather, the Commission capped the bidding at the outer, reasonable edge in order to give the market maximum flexibility to work within reasonable bounds. A firm shipper will have to commit to a 20-year contract only if a competing bidder values the service sufficiently to bid the maximum period. Indeed, it is inconsistent that some petitioners argue that the 20-year contract cap is too long while at the same time they express concern about security of supply in obtaining long term capacity. There is, of course, always a risk and an element of uncertainty in any forecast of future needs. LDCs are not unique among gas users in this regard. The Commission does not believe that LDCs are at a disadvantage with respect to other gas users in predicting future needs when exercising the right of first refusal. It is the Commission's judgement, based on industry practice, and in view of the types of contracts cited in Order No. 636-A, 182/ that 20 years is a reasonable accommodation between the interests of stability and flexibility and provides a workable framework for market determinations. It is the Commission's judgement as well that the 20-year cap is a reasonable balance between ensuring that capacity is allocated to shippers that most value it and the LDC's need to maintain 182/ Order No. 636-A at 30,631 n.437. Docket No. RM91-11-004, et al. - 134 - security of supply through capacity entitlements. However, if all the parties to a pipeline's restructuring proceeding agree to a different number of years for the contract cap, then the Commission will allow it. UtiliCorp Divisions argue that the Commission does not give adequate weight to the presumption in favor of continued service or to the danger that the pipelines will use monopoly power to extract non-price concessions from the LDCs. Therefore, it concludes, the Commission has failed to adequately address the basis of the remand in AGA II, that the Commission has not explained how pregranted abandonment trumps another precept of regulation, i.e., the protection of consumers against monopoly power through the refusal of service at the end of the contract period. Industrial Groups argue that there may be instances where continued service for a short term is in the public interest, but the procedure adopted here does not afford parties the opportunity to explain the relevant circumstances. As the Commission has explained, the right of first refusal procedure affords protection to the existing customer against any exercise of monopoly power. 183/ The existing customer can always continue to receive service if it matches a competing bid. If there is no competing bid, the existing customer can always continue to receive service for any period it chooses by agreeing to pay the maximum rate. It is not contrary to the public interest to require customers to match the longest term bid to 183/ Order No. 636-A at p. 30,631. Docket No. RM91-11-004, et al. - 135 - continue to receive service -- especially where there is a reasonable cap on what constitutes the longest term bid. As the Commission explained in Order No. 636-A, long-term contracts generally benefit the system as a whole because they provide stability and benefits to all customers, 184/ and section 7 of the NGA does not require the Commission to examine the particular circumstances of each case. 185/ The right of first refusal procedure guarantees that existing customers may have continued service, while allowing market forces to play a significant role in determining the contract price and term. B. Contractual Waiver of Pregranted Abandonment In Order No. 636, the Commission stated that the pregranted abandonment provisions would not apply to conversions that took place during the period that the stay of pregranted abandonment under Order No. 500-J was in effect. 186/ In Order No. 636- A, the Commission clarified that it would not expand the exemption from the pregranted abandonment provisions beyond those conversions that took place during the time the Order No. 500-J stay was in effect and stated that specific contracts that contain a waiver of the right to pregranted abandonment should be examined in the restructuring proceedings and not in this generic proceeding. 184/ Order No. 636-A at p. 30,630. 185/ Mobile Exploration and Production Southeast, Inc. v. United Distribution Companies, 111 S. Ct. 615 (1991). 186/ Order No. 636 at p. 30,452. Docket No. RM91-11-004, et al. - 136 - On rehearing, AGD and UDC argue that the Commission erred in deferring the examination of specific contractual waivers of pregranted abandonment to the restructuring proceedings. These parties argue that they won this protection through difficult negotiations and should not be required to fight this battle again during restructuring. UGI argues that the voluntary waiver of pregranted abandonment completely eliminates the legal and theoretical basis for requiring that capacity subject to these contracts go through the right of first refusal process in order to avoid pregranted abandonment. The parties ask the Commission to affirm, generically, that existing rights to waiver of pregranted abandonment will remain unmodified. As the Commission explained in Order No. 636-A, the exemption from pregranted abandonment for conversions that took place during the Order No. 500-J stay is based on the Commission's decision in that proceeding and the resulting expectations of the parties. 187/ It is appropriate, therefore, to clarify in this proceeding that those conversions will not be subject to pregranted abandonment. Further, as a general matter, the parties may resolve issues in Commission proceedings by contractual agreements or settlements, and the Commission generally favors the resolution of issues by settlement. However, the Commission will not rule on the viability of any current settlements or contractual agreements in whole or in part, on a generic basis. The relationship between 187/ Order No. 636-A at 30,636. Docket No. RM91-11-004, et al. - 137 - the provisions of existing settlements or agreements and the provisions of this rule will have to be examined on a case-by- case basis. This rule is not intended to affect existing valid waivers of pregranted abandonment, but the Commission will not rule on any specific waiver provisions here. C. Bids Below the Maximum Rate In Order No. 636-A, the Commission clarified that pipelines are not required to discount transportation rates under the rule and that if a lower bid is not acceptable to the pipeline, then the shipper is entitled to continued service at a rate between the minimum and the maximum negotiated by the shipper and the pipeline. 188/ LILCO, APGA, and Meridian ask the Commission to require pipelines to accept the highest bid for capacity made available as the result of the bidding process at the termination of the contract. LILCO states that if pipelines are not required to accept offers at less than the maximum rate, then they will be able to refuse offers for discounted service and seek recovery of the costs associated with the unwanted capacity from their remaining customers through a section 4 filing. To prevent unnecessary cost shifts, LILCO argues, the Commission should grant rehearing and require pipelines to accept bids at less than the maximum rate where there are no other offers for capacity, or forbid pipelines from recovering the cost of unwanted capacity from other shippers. 188/ Order No. 636-A at p. 30,629. Docket No. RM91-11-004, et al. - 138 - APGA and Meridian argue that unless pipelines are required to accept the highest bid, the market will not, in fact, determine the rate. APGA asserts that captive LDCs will have little leverage to negotiate if pipelines can reject a rate below the maximum. Meridian asserts that while the procedure set forth in Order No. 636-A may work on capacity-constrained pipelines, it will not work on pipelines where capacity is not fully utilized. Moreover, Meridian argues, since the bid that is received reflects the market value of the capacity, that is the rate and term that should be matched by the existing shipper. Meridian asks the Commission to clarify that where a pipeline refuses to accept a bid below the maximum rate, the pipeline, and not the customers, is at risk for any shortfall. The Commission will not require pipelines to discount transportation rates. However, if a pipeline fails to attempt to maximize throughput, there is no guarantee that it will be able to recover all the cost of its underutilized capacity from its firm customers when it files its next rate case. 189/ Evidence that a pipeline refused to accept the highest valued bid for capacity below the maximum rate will be given significant weight during its next rate case. Meridian believes that the rule does not require the pipeline to reveal that a below maximum bid, or no bid at all, was offered for the capacity and asks the Commission to clarify 189/ See Order No. 436, Regulation of Gas Pipelines After Partial Wellhead Decontrol, FERC Stats. & Stats. Regulations Preambles 1982-1985  30,665 at p. 31,523. Docket No. RM91-11-004, et al. - 139 - that pipelines must post the highest bid actually received (or the fact that no bid was received). The rule does not explicitly require pipelines to post competing bids on the bulletin board. However, it was the Commission's intent that the existing shipper have notice of the terms of all competing bids. The Commission clarifies that the pipeline must inform the existing shipper of the maximum bid received or the fact that no bids were received on the EBB. Moreover, the pipelines are required to publish in their tariffs the criteria they will use to determine the "best bid." Meridian also asks the Commission to clarify that the previously effective rate should remain in effect during the period the pipeline and the customers are negotiating the terms for continued service. The Commission will grant the clarification. VIII. TRANSITION AND IMPLEMENTATION IN THE RESTRUCTURING PROCEEDINGS A. Capacity Adjustments During Restructuring Under section 284.14(e) of the Commission's regulations, firm shippers (including currently bundled sales customers) must give notice to the pipeline during the restructuring proceeding whether they wish to retain, reduce, or terminate their contractual rights to firm transportation service. The pipeline is authorized to abandon firm transportation service to the existing shipper if another creditworthy shipper offers to pay for the capacity an existing shipper wants to release, or offers to pay a higher rate (up to the maximum rate) than the existing Docket No. RM91-11-004, et al. - 140 - shipper is willing to match, or the pipeline consents to the abandonment even though no other shipper makes an offer for it. Several parties reiterate concerns with issues already addressed in Order No. 636-A or request clarification of certain issues. The Commission will deny the requests for rehearing but clarify certain issues as discussed below. 1. Unilateral Right to Reduce or Terminate CD Meridian asks that existing capacity holders be given a unilateral right to reduce or terminate their contract demand (CD) during the restructuring proceedings. Meridian argues that, facing the prospect of an SFV rate design, shippers should be given the choice to reduce their contract demands or terminate their service agreements, thereby returning capacity to the pool and making it available for assignment to others willing to assume the costs and risks associated with SFV-based rates. Meridian asserts that, under section 284.14(e)(2) of the regulations, a firm customer paying the maximum rate is effectively trapped on pipelines where there is insufficient demand for capacity to be relinquished. Meridian recognizes that the pipeline might have to increase the demand charges of the customers with continued interest in firm service in order to afford relief to those who reduce or terminate their capacity reservations. Cincinnati Gas contends that Order No. 636-A should be revised to impose an obligation on pipelines, in cases where there are no bidders for particular capacity during the Docket No. RM91-11-004, et al. - 141 - restructuring process, to enter into good faith negotiations with the current capacity holder for the purpose of agreeing to a rate reflective of the capacity's actual worth. If such negotiations do not result in an agreement on an acceptable rate, Cincinnati Gas argues that shippers should be allowed to release the capacity, and that any costs associated with such releases should be treated as stranded costs. The Commission has already considered and rejected proposals like Meridian's and Cincinnati Gas' in Order No. 636-A. 190/ In order to afford unilateral relief to firm customers that want to reduce or terminate their capacity reservations, or reduce their rates for capacity during restructuring, before their contractual obligations for the capacity have expired, the costs allocated to rates for the capacity in question would have to be absorbed by the pipeline or reallocated to other firm customers who may have no current need for the capacity. The parties are, of course, free to negotiate capacity allocation matters during the restructuring proceedings. 2. Expiration of Bundled Sales Contracts During Restructuring UtiliCorp Divisions asks a question arising from the restructuring proceeding of Williams Natural Gas Company, where it indicates that certain sales customers have executed contracts that expire when superseded by another contract, or November 1, 1993, at the latest. UtiliCorp Divisions ask whether a current 190/ Order No. 636-A at p. 30,637-39. Docket No. RM91-11-004, et al. - 142 - firm capacity holder with a contract that terminates on or prior to the date of restructuring, i.e., the effective date of the pipeline's tariffs to comply with Order No. 636, may retain capacity following restructuring by agreeing to pay the pipeline's maximum rates and freely select the term for the first post-restructuring contract, or must also match the duration of a contract bid by potential new customers for that capacity. UtiliCorp Divisions argue that historic customers should be permitted to elect any term for their first post-restructuring contract as long as they are willing to pay the maximum rate. It reads Order No. 636-A to permit that result, and to defer the application of the right of first refusal procedures until after the term of the first contract. UtiliCorp Division also ask a subsidiary question: If the existing capacity holders whose sales contracts expire on or before November 1, 1993, have to match the length of terms offered by competing bidders, do they have to offer to enter into contracts for a term of 15 years, as Williams requires, or may they simply agree to match the length of term offered by competing bidders? The Commission will not address the specific facts and circumstances in the Williams restructuring proceeding in this generic order. However, UtiliCorp Divisions' rehearing request indicates a general area of confusion which needs clarification. Questions have arisen about the applicable policies when long-term bundled sales contracts expire after the effective date of Order No. 636, but before the effective date of a pipeline's Docket No. RM91-11-004, et al. - 143 - blanket sales certificate under section 284.284, when the pipeline's bundled sales service is converted to unbundled sales and transportation services. The pipeline must continue to provide service under the service obligation of its existing certificate until its section 284.284 blanket certificate becomes effective. The pipeline and the sales customer may enter into a relatively short-term contract, intended to apply until the effective date of the pipeline's blanket sales certificate under section 284.284. If the pipeline and the sales customer enter into a contract for bundled sales service that extends beyond the date that the pipeline implements unbundled service, the contract will be converted into an unbundled sales and unbundled transportation contract on the effective date of the pipeline's 284.284 blanket certificate. The question arises whether the sales customer whose contract lapses during the restructuring process, and which is not renewed, has a right of first refusal to retain its firm transportation capacity upon the effective date of the pipeline's section 284.284 certificate, and whether a customer with a short-term interim sales contract has a right of first refusal to retain its capacity upon expiration of its short-term contract on or after the effective date of the pipeline's section 284.284 certificate. In ANR Pipeline Company, 191/ the Commission decided to treat short-term (less than one year) interim, bundled sales contracts as long-term contracts for purposes of affording the 191/ 60 FERC  61,319 (1992). Docket No. RM91-11-004, et al. - 144 - bundled sales customers the right of first refusal to avoid automatic abandonment of their firm transportation capacity -- even if the contracts in fact expire in less than one year. The Commission will apply the same treatment given to short-term contracts in ANR to other pipelines undergoing restructuring whose long-term sales contracts expire during the restructuring process. A customer whose long-term bundled sales contract (one year or more) expires after May 18, 1992, but before the effective date of a pipeline's section 284.284 certificate, is entitled to retain its firm capacity by exercising a right of first refusal, as described in section 284.221(d) of the Commission's regulations, in connection with implementation of the pipeline's section 284.284 certificate. The customer is entitled to exercise its right of first refusal to avoid abandonment of service whether or not it executes an interim contract, or upon expiration of any interim contract, whether the interim contract is for more or less than one year. In exercising this right of first refusal in connection with implementation of the pipeline's section 284.284 certificate, a customer is entitled to retain its firm capacity by matching the price offered by a competing bidder, up to the maximum rate, 192/ and the duration of the term bid, up to a maximum 192/ The pipeline may choose not to accept any bid at less than the maximum, in which event the existing customer will have to pay the maximum rate to retain its capacity. See Order No. 636-A at p. 30,629. However, as discussed above, if the pipeline refuses to accept a bid at less than the maximum rate, and the capacity goes unsubscribed, then this will be given significant weight in the pipeline's next rate case. Docket No. RM91-11-004, et al. - 145 - of 20 years. The pipeline may not require a customer exercising its right of first refusal to contract for some term of longer duration than a term offered by a competing bidder. And, as the Commission said in Order No. 636, if there are no competing bidders, the existing customer is entitled to continue service for whatever term it chooses. 193/ 3. Liability of Existing Shipper for Reallocated Capacity Barclays seeks clarification that if capacity is reallocated during restructuring, and a new shipper's contract is for a shorter term than the existing shipper's term, the existing shipper will remain liable for the remainder of the term of the original contract. Barclays argues that if a holder of long-term firm capacity seeks to relinquish that capacity to another bidder during the restructuring proceeding, the pipeline, in addition to applying its creditworthiness standards, should remain protected not only from a shortfall in price but also from a shortfall in contract duration. The Commission will grant this clarification. In Order No. 636-A, the Commission stated that when another creditworthy shipper offers to pay a rate that is equal to or greater than the existing capacity holder's rate for a part of the capacity the existing holder seeks to relinquish, a pipeline would be required to release the existing capacity holder from its contractual 193/ Order No. 636 at p. 30,449. Docket No. RM91-11-004, et al. - 146 - obligation for the part sought by the other shipper. 194/ By extension, an existing capacity holder remains liable under the original contract for any part of a term remaining under the original contract when the contract of the shipper to whom capacity is relinquished expires. 4. Discounted Transportation Rates CIG argues that the Commission erred in permitting an existing shipper with a contractually guaranteed transportation discount to retain the capacity in the restructuring proceeding by matching bids only up to the contractual rate, rather than the maximum rate. According to CIG, this policy undermines the allocative efficiency of capacity reallocation during restructuring. At the very least, CIG contends, an existing shipper with a discount that will not match higher bids for the capacity should not be entitled to the service enhancements provided for firm service under Order No. 636. The allocative efficiency of capacity reallocation during restructuring is subordinate to the contractual rights of existing capacity holders. If a shipper contracted for long-term transportation capacity at a guaranteed discount, and has a contract that establishes its contractual right to receive that discount, the shipper is entitled to the benefits of its bargain under the contract, even if unforeseen circumstances render that service more valuable than it was when the bargain was made. This result is merely the obverse of the continuing liability of 194/ Order No. 636-A at p. 30,639. Docket No. RM91-11-004, et al. - 147 - a shipper that agreed to pay the maximum rate under its contract, even though unforeseen circumstances result in the shipper's rates unexpectedly increasing, or the shipper's need for the service unexpectedly decreasing. 5. Direct Feed Situations UGI describes a contract for purchase of gas from Columbia under which delivery is made to UGI from Texas Eastern, a pipeline upstream of Columbia, a situation UGI characterizes as a "direct feed." UGI requests the Commission to clarify that if Columbia assigns its capacity on Texas Eastern to UGI, UGI will be entitled to a reduction in firm entitlements from Columbia, without exit fees or transition cost allocation, following the assignment of "direct feed" upstream capacity. Otherwise, UGI asserts that it will be liable for demand charges and transition cost charges to both Texas Eastern and Columbia for the same firm capacity. The Commission will not attempt to resolve this case- specific issue arising from what appears to be an anomalous situation in this generic proceeding. The issue should be presented in Columbia's restructuring proceeding. B. Transition Costs 1. Allocation of Gas Supply Realignment Costs to Interruptible Transportation In Order 636-A, the Commission required pipelines to recover 10 percent of their gas supply realignment (GSR) costs through their rates for interruptible transportation (IT) under their Part 284 blanket certificates. Many of the requests for Docket No. RM91-11-004, et al. - 148 - rehearing of Order No. 636-A take issue with this requirement. Various parties oppose the allocation of GSR costs to interruptible transportation customers and propose that such costs be recovered from firm transportation (FT) released under the pipeline's capacity release program, or released firm transportation subject to a right of recall, as well as interruptible transportation. Some parties advocate that the 10 percent of GSR costs allocable to interruptible transportation should be recoverable from firm transportation if the pipeline does not provide interruptible transportation service, or if the volumes of interruptible transportation service it provides are insufficient to bear the 10 percent allocation. Other parties propose that a higher percentage of GSR costs should be recoverable from interruptible transportation service, or that all GSR costs should be recoverable through a volumetric surcharge on all throughput. a. Arguments against the allocation to IT The American Paper Institute asserts that GSR costs should not be allocated to interruptible transportation customers, or at least, not to the extent that interruptible transportation customers pay higher GSR costs per unit than firm transportation customers. GSR costs should not be allocated to Part 284 interruptible transportation customers, the Paper Institute argues, because interruptible transportation customers will not benefit from Order No. 636, they have not and will not cause GSR costs, and achieving the transition required by Order No. 636 Docket No. RM91-11-004, et al. - 149 - through subsidization by interruptible customers is not in the public interest. It is not appropriate, according to the Paper Institute, to view opportunities for interruptible transportation customers to obtain firm service through the capacity release program as a basis for charging GSR costs to interruptible transportation customers. Furthermore, the unbundling requirements of Order No. 636 do not benefit interruptible transportation customers, and pipelines in many restructuring proceedings are attempting to reduce the scheduling and balancing flexibility available to traditional transportation services, including interruptible transportation service. The Paper Institute also notes that if the amount of interruptible transportation throughput is sufficiently low, it is conceivable that interruptible transportation customers could pay more, on a per unit basis, than do firm customers, and advocates that the Commission should at least adopt a mechanism which avoids that result. Industrial Groups argue that the Commission's decision to allocate 10 percent of the GSR costs to interruptible transportation services is arbitrary and capricious, and that the rate impact of spreading GSR costs to a shrinking class of interruptible transportation customers is significant, and far out of proportion to any imaginable benefit to interruptible transportation shippers from the restructuring rule. 195/ 195/ They argue that the Texas Eastern filing of nearly $.28 per dekatherm for the GSR charges on interruptible (continued...) Docket No. RM91-11-004, et al. - 150 - Industrial Groups argue that the Commission erred in Order No. 636-A by allocating GSR costs to interruptible transportation and non-converting firm transportation customers without a showing that interruptible transportation and non-converting firm shippers have contributed in any way to the incurrence of such costs, or that the ordered level of allocation produces just and reasonable rates. They also assert that sales contracts, and any costs that might be incurred to modify them, are unrelated to any service provided by pipelines for transportation customers who have never been pipeline sales customers, or who converted to transportation before the issuance of Order No. 636. 196/ Industrial Groups assert that interruptible transportation customers are provided no additional rights or services under the restructuring rule, and that because GSR costs are sales-related, they are not affected by the amount of interruptible transportation service a pipeline provides. They argue that the 195/(...continued) transportation, which more than doubles the cost of various production and market area hauls, illustrates that the Commission cannot arbitrarily assign a predetermined percentage of costs to interruptible transportation. 196/ Gas Consumers also argue that customers who pursued the Commission's policies under Order No. 436 and converted to transportation-only will not benefit from Order Nos. 636 and 636-A, and should therefore not bear the transition costs of restructuring, because they have already paid the transition costs of converting to transportation under Order No. 436. The rationale for allocating transition costs to firm transportation customers receiving service under Part 284 certificates, regardless of whether they are discontinuing purchases of gas from the pipeline, has been fully explained in Order No. 636-A, and will not be repeated in this order. See Order No. 636-A at p. 30,650. Docket No. RM91-11-004, et al. - 151 - initiatives adopted in Order No. 636, such as unbundling, flexible receipt and delivery points, and creation of a uniform national capacity release program, will enhance the ability of firm shippers to use their reserved capacity more efficiently, but diminish the quality and reliability of interruptible transportation service by reducing the amount of pipeline capacity available for interruptible transportation service. In fact, they argue, these measures may lead to complete displacement of interruptible transportation service. Industrial Groups also argue that the Commission's cost-spreading rationale is inconsistent with its decision to exempt NGA section 7 shippers and pipelines themselves from sharing transition costs. 197/ In the Commission's judgment, applying the principle of cost causation is more important when allocating costs and designing rates for the long term, and deviations from that principle may be justified for short term rates. The issue the Commission faces in this proceeding is how to provide for an equitable means of allowing recovery of the costs of the transition to a restructured pipeline industry and a more competitive natural gas market. The Commission recognizes that interruptible transportation service as such did not give rise to the GSR costs at issue here. Furthermore, interruptible transportation as such may not be enhanced or improved by the requirements of 197/ Arcadian also contends that there is no justification for treating IT shippers differently than section 7(c) shippers. Docket No. RM91-11-004, et al. - 152 - restructuring. However, customers that have historically used interruptible transportation, and may continue to use it on a restructured pipeline, have access to the enhanced firm services. More importantly, they will benefit significantly from access to the more competitive gas market that will be available as a result of restructuring. The Commission intends to spread the costs of transition over a broad base of customers that have access to these benefits. 198/ Shippers on a restructured pipeline should not be able to completely avoid a fair share of the GSR transition costs by limiting their usage of the services available under the pipeline's Part 284 blanket certificate to interruptible transportation service. Producer Associations contend that the Commission erred by requiring that 10 percent of the GSR costs must be recovered through a usage surcharge on interruptible transportation because of the adverse effect of such charges on the net-back price of gas at the wellhead. Blue Flame also alleges that recovery of 10 percent of the GSR costs from interruptible transportation penalizes small and medium sized producers because of the net- back effect on spot prices. Arkla states that the Commission apparently recognized cost causation principles in deciding not to allocate GSR costs to 198/ For the same reason, the Commission will deny LILCO's request that future open-access, transportation customers, that obtain service after restructuring is completed, should not be subject to transition costs. Docket No. RM91-11-004, et al. - 153 - individually certificated section 7(c) transportation agreements, but failed to consider these principles in allocating GSR costs to Part 284 interruptible transportation customers. The Commission recognizes that allocation of a small portion of a pipeline's GSR costs to interruptible transportation service may have some adverse impact on producer prices, at least for some transactions for a short term, but the public interest in a more equitable spreading of such costs to a broad base of pipelines' customers outweighs the possible short-term impacts on producers. The restructuring requirements of Order No. 636 are applicable to service under a pipeline's Part 284 blanket certificate. They do not pertain to transportation service under individual section 7(c) certificates. Part 157 shippers therefore do not get either the benefits or the burdens of Order No. 636. b. Recovery of GSR costs not recoverable from IT Several petitioners contend that the Commission should permit alternative mechanisms for recovery of the 10 percent of GSR costs allocated to interruptible transportation, such as applying an equivalent surcharge to released firm capacity, either capacity subject to recall or all released capacity. 199/ These petitioners assert that, with the implementation of capacity release, they will be unable to recover the GSR costs assigned to interruptible transportation, 199/ ANR (recallable releases); CIG (recallable releases); Southern (all releases); Tenneco (all releases). Docket No. RM91-11-004, et al. - 154 - because competition from released capacity will significantly reduce interruptible throughput, and the imposition of a surcharge on interruptible transportation will further reduce interruptible sales by making the rates for interruptible service uncompetitive with the rates for released capacity. They maintain that released capacity is the equivalent of interruptible capacity and should therefore bear the same responsibility for GSR costs. The Commission does not agree that the implementation of capacity release programs will necessarily result in the elimination of interruptible transportation service or in the pipeline's inability to recover GSR costs assigned to such service. Nor will the allocation of GSR costs necessarily make interruptible transportation uncompetitive with released firm capacity or reduce interruptible throughput. If the market for interruptible transportation is competitive, as petitioners assume, pipelines will price to reflect competitive forces in the market, not costs. By pricing interruptible transportation competitively, the pipelines should be able to continue to sell the service. The Commission is not requiring pipelines to allocate such a high level of GSR costs to interruptible transportation service so that rates which recover such costs will render the service unmarketable. Natural requests clarification that the Commission will allow the pipelines to develop mechanisms to adequately deal with any underrecovery of costs allocated to interruptible Docket No. RM91-11-004, et al. - 155 - transportation. Natural asserts that the allocation of transition costs to interruptible transportation service will undermine the Commission's principle of 100 percent recovery of transition costs unless the Commission clarifies that pipelines are to be afforded flexibility to develop adequate mechanisms to deal with any underrecovery. According to Natural, higher rates for interruptible transportation service will render increasingly difficult the collection of any of the costs required by Order No. 636-A to be allocated to such service. Natural urges the Commission to permit a wide range of alternative mechanisms for recovery of the GSR costs allocated to interruptible transportation under Order No. 636-A, including * allocation of zero non-gas fixed costs to interruptible services, with actual dollars collected by the pipeline for these services used first to collect the transition costs; * direct billing (and/or reallocation to the demand surcharge or other cost recovery mechanism) of any underrecovered amounts after a predetermined time period; * recovery in a later period (and/or under a different mechanism) of costs not recovered earlier due to seasonal or market factors. K N asserts that because interruptible transportation is not available on all pipelines, and, where it is available, actual throughput may be significantly less than projected throughput used to design rates, the requirement that GSR costs be recovered from interruptible transportation customers may mean that certain pipelines will not recover 100 percent of their gas supply realignment costs, absent an unconditional true-up mechanism Docket No. RM91-11-004, et al. - 156 - applicable to all firm Part 284 transportation customers, which provides for recovery of carrying charges. LILCO, on the other hand, seeks clarification that a true-up mechanism for recovery of GSR costs allocated to interruptible transportation service may not provide for recovery from firm transportation service, but only from future interruptible service. POPCO and PIOC allege that the Commission cannot require 10 percent of their GSR costs to be recovered from interruptible transportation service because they have never provided, and never expect to provide, interruptible transportation service. According to POPCO and PIOC, they were both certificated as gas supply projects, not transportation networks, and both are "open access" transporters pursuant to Order No. 509, but neither have ever received a request for firm or interruptible transportation of a presently deliverable gas supply. POPCO states that if the Commission applies its "90-10" rule to POPCO and PIOC, both pipelines will be denied an opportunity to recover the 10 percent of GSR costs allocated to interruptible transportation service. The effect of capacity releasing on the levels and rates for interruptible transportation, and the ability to recover the assigned GSR costs, will depend on many factors, including the extent of projected GSR costs, characteristics of the pipeline's system, the pipeline's capacity release procedures, the extent to which flexible receipt and delivery points are available, the rate design used for interruptible transportation, and the use of Docket No. RM91-11-004, et al. - 157 - seasonal contract entitlements. 200/ As the Commission stated in Order No. 636-A, the Commission does not intend for the pipelines to have to absorb the portion of GSR costs assigned to interruptible transportation and encourages the pipelines and the parties to the restructuring proceedings to be creative in fashioning rate mechanisms, such as an appropriate true-up mechanism, that provide a reasonable opportunity for pipelines to recover those costs. 201/ Furthermore, if a pipeline's experience after restructuring indicates that it will be unable to recover the 10 percent of GSR costs allocable to interruptible transportation, either because it is providing no interruptible transportation, or a de minimis level of such transportation, the Commission will consider proposals in limited section 4 rate filings to provide for recovery of those unrecoverable costs. 202/ However, the Commission will not accept proposals to assess any of the 10 percent of GSR costs allocable to interruptible transportation solely to released firm capacity. 200/ For example, as the Commission pointed out in Order No. 636-A, under a potential revenue crediting approach for interruptible transportation, pipelines could retain a portion of the revenue from interruptible transportation to recover GSR costs allocated to interruptible transportation. Order No. 636-A at p. 30,563 n. 164. The use of seasonal contract entitlements likely would result in interruptible transportation being available in the off-peak season. 201/ Order No. 636-A at p.30,647. 202/ This order constitutes such appropriate notice under the Natural Gas Act as may be necessary to the public, including all current and future shippers, that the Commission expects to take appropriate steps in the future to ensure that the pipelines have an opportunity to recover any unrecoverable GSR costs allocated to IT service. Docket No. RM91-11-004, et al. - 158 - Released firm capacity already bears the cost of the reservation fee surcharge. Thus, permitting pipelines to assess the use of released firm capacity with an additional increment of GSR costs, while the pipeline's interruptible transportation bears only one such assessment, would give an undue competitive advantage to the marketing of interruptible transportation. c. Recovering a higher percentage of GSR costs from IT, or all GSR costs through a surcharge on all throughput Gas Consumers advocate the reduction or elimination of transition costs to firm transportation customers, particularly small customers, and reallocation to producers and interruptible customers, the primary beneficiaries of the restructuring. Gas Consumers argue that a portion of all transition costs, not just GSR costs, should be allocated to interruptible transportation customers, and that the allocation should be based on the benefit received by allocating transition costs on the basis of throughput or some other method that assigns costs based on benefits rather than an arbitrary percentage. New Jersey Natural contends that the Commission erred by failing to allocate 50 percent of the GSR costs to interruptible transportation service, commensurate with the benefits interruptible customers have received from pipeline restructuring. Peoples Gas argues that transition costs should be allocated to interruptible transportation (as well as all other) customers volumetrically on a pro rata basis to reflect more accurately Docket No. RM91-11-004, et al. - 159 - their use of pipeline services and the improved quality of service that the Commission intends for all customers to receive in the future. The Commission's decision to require the allocation of only 10 percent of the GSR costs is improper and unreasonable, according to Peoples Gas, because end-use customers getting their gas delivered through interruptible transportation were probably all sales customers of pipelines or LDCs when the pipeline contracts giving rise to the GSR costs were entered into, and interruptible transportation customers are presently a major customer group on the pipeline systems, and the most likely beneficiaries of the restructuring rules. Western Resources argues that allocation of GSR costs should have been left to individual proceedings. According to Western Resources, recovery of 10 percent of the GSR costs from interruptible transportation service is not enough on Williams' pipeline system, and the Commission erred by so limiting the recovery of such costs. The task of determining fair allocations of transition costs is ultimately thankless, even though we bring all our experience and best judgment to bear on it. The Commission has already considered and rejected the arguments against any allocation of GSR costs to interruptible transportation service. The Commission will also reject the requests to require the allocation of more GSR costs to interruptible transportation service and to allocate such costs on a volumetric basis. As the Commission explained in Order No. 636-A, assessing 10 percent of Docket No. RM91-11-004, et al. - 160 - the transition costs to interruptible rates will be a short term feature of the pipeline's rates and is a reasonable trade-off in light of the rule's long term benefits. 203/ Thus, a 10 percent allocation of GSR costs to interruptible transportation customers is a reasonable accommodation of the many factors and interests at issue here. 204/ As the United States Supreme Court has stated, "[a]llocation of costs is not a matter of the slide-rule. It involves judgment on a myriad of facts. It has no claim to an exact science." 205/ The provisions of Order Nos. 636 and 636-A on allocation of transition costs are not incorporated in the regulations, but are policy statements. The Commission will review specific proposals for recovering transition costs with reference to the particular circumstances of each pipeline system and the degree of support those proposals enjoy from the affected parties. d. Use of a surcharge vs. allocating GSR costs to interruptible transportation LILCO states that the Commission erred by requiring pipelines to allocate 10 percent of their GSR costs to interruptible transportation service instead of recovering such costs through a surcharge on interruptible transportation. According to LILCO, pipelines will simply reduce the costs that 203/ Order No. 636-A at p. 30,647. 204/ See Christian Broadcasting Network, Inc. v. Copyright Royalty Tribunal, 720 F.2d 1295, 1304 (D.C. Cir. 1983)(choice of a particular percentage allocation not reviewable for exact precision, but simply for rationality). 205/ Colorado Interstate Co. v. FPC, 324 U.S. 581, 589 (1945). Docket No. RM91-11-004, et al. - 161 - they would otherwise allocate to interruptible service by an amount sufficient to offset the allocated GSR costs, so that interruptible customers will not in fact pay any GSR costs, and rates to firm transportation shippers will not be any lower. Furthermore, LILCO asserts, if pipelines adopt a crediting method of accounting for interruptible transportation revenues, firm transportation customers will be deprived of any credit for the GSR costs allocated to interruptible service, and will thus be paying those costs indirectly. The Commission will deny LILCO's request for rehearing. Ten percent of a pipeline's GSR costs must be allocated to the rates for its interruptible service, and may not be recovered through a surcharge. Although LILCO makes the valid point that the allocation of GSR costs to a service with rates determined by competitive forces may not necessarily affect the rates they charge, the allocation of GSR costs increases the maximum rates for interruptible transportation, and service provided at the maximum rates will recover more costs than service at maximum rates without the allocation. Whether GSR costs are directly allocated to interruptible transportation service or recovered by means of a volumetric surcharge on interruptible rates would not alter the effect of competition on discounted transportation rates. The Commission will consider the fairness of a pipeline's proposed allocation of costs to interruptible and firm service, or the fairness of any proposed mechanism for crediting revenue Docket No. RM91-11-004, et al. - 162 - from interruptible service to firm transportation customers, on a case-by-case basis. e. True-up mechanisms to ensure recovery of GSR costs allocated to interruptible transportation service Arcadian states that the Commission erred in authorizing true-up mechanisms to recover gas supply realignment costs allocated to interruptible transportation service. Arcadian argues that a true-up mechanism, which would assure a pipeline that any GSR costs not recovered through interruptible transportation rates in one period would be recovered in subsequent periods, would create the same problems as revenue crediting, by eliminating incentives for a pipeline to market interruptible services, and conflict with the Commission's primary aim of improving the competitive structure of the natural gas industry. As noted above, in Order No. 636-A, the Commission stated that it does not intend for the pipelines to absorb any portion of the GSR costs and encouraged the pipelines and the parties to the restructuring proceedings to be creative in fashioning rate mechanisms, such as an appropriate true-up mechanism, that provide a reasonable opportunity for pipelines to recover those costs. 206/ Putting a pipeline "at risk" of not recovering those costs by requiring it to assign a certain amount of GSR costs to the rate for each unit, on the basis of an estimated level of interruptible transportation volumes, might increase the 206/ Order No. 636-A at p.30,647. Docket No. RM91-11-004, et al. - 163 - pipeline's incentive to provide interruptible transportation at the estimated level. However, such a policy would not necessarily improve the pipeline's ability to market the estimated level of interruptible service or provide a reasonable opportunity to recover the assigned GSR costs. 2. Recovery of Costs in Account No. 191 Accrued Before July 31, 1991 INGAA advocates allowing direct billing through the PGA mechanism of pre-July 31, 1991 costs in pipelines' Accounts No. 191. According to INGAA, the Commission's analysis of the issue in Order No. 636-A overlooked the fact that there are still unrecovered gas costs which accrued prior to July 31, 1991, that will be outstanding upon compliance with Order No. 636 and termination of the PGA mechanism. INGAA asserts that pipelines with such costs may not have an ample opportunity to recover them in the last remaining PGA periods, because pre-July 31, 1991 underrecoveries would not normally be recovered until the 1993 PGA year. INGAA asserts that the Commission needs to specifically provide a mechanism for recovery of these prudently incurred costs which would have, until the issuance of Order Nos. 636 and 636-A, been fully recoverable under the PGA rules. INGAA also states that the Commission should provide for a waiver of the PGA regulations and allow the pipeline to include all such costs in its demand charge during the final PGA period. CNG states that the Commission's conclusion that pipelines will have an ample opportunity to recover their pre-July 31, 1991 costs before they terminate their PGA mechanisms is wrong. CNG Docket No. RM91-11-004, et al. - 164 - asserts that the Commission has twice rejected CNG's requests to obtain demand charge treatment for the recovery of Texas Eastern's GSIRC charges, and has instead required CNG to recover those amounts in its commodity surcharge. CNG asserts that, as a result, it has accumulated significant amounts in its Account No. 191 that would be difficult to recover under the normal operation of the PGA mechanism. 207/ Columbia requests clarification that Order No. 636-A does not preclude recovery of pre-July 31, 1991 gas costs if a pipeline can show that there are valid reasons why such costs have not been recovered via the PGA mechanism. Columbia states that it has not, as yet, made certain payments to its gas suppliers relating to its gas purchases during periods preceding its bankruptcy filing and cannot do so absent an appropriate order of the Bankruptcy Court. Columbia predicts that such an order will not be issued in time for such costs to be recovered prior to the elimination of its PGA. Natural urges the Commission to acknowledge that particular situations may arise which require a case-by-case examination of the PGA recovery issue. Natural states that its PGA was suspended as of December 1, 1990, under its Gas Inventory Demand Charge (GIDC) procedures, and that while certain amounts collected pursuant to the GIDC have been applied to recovery of 207/ See CNG Transmission Corporation, 61 FERC  61,156 (1992)(Commission accepted tariffs, subject to refund and further review, to accelerate recovery of CNG's Account No. 191 balances and thereby minimize transition costs upon restructuring.) Docket No. RM91-11-004, et al. - 165 - the PGA balance, Natural expects that, absent a further settlement, some balance will remain as of the date Order Nos. 636 and 636-A are fully implemented on its system. 208/ PSE&G requests clarification that any pre-July 31, 1991 costs in Account No. 191 not recovered before termination of a pipeline's PGA must be absorbed by the pipeline. UtiliCorp Divisions request the Commission to grant rehearing on its treatment of Account No. 191 balances, which UtiliCorp Divisions characterize as in essence an adoption of a FIFO (first-in, first-out) method for determining whether accumulated balances have been eliminated. According to UtiliCorp Divisions, Commission statements in Order No. 636-A imply that a pipeline may attribute all of its recovery of gas costs under its PGA mechanism to reduction of its unrecovered balanced accrued before July 31, 1991 -- even during periods when unrecovered balances are increased -- and argues that such an accounting method would permit pipelines to circumvent the filed rate doctrine. The Commission recognizes that, due to various specific circumstances, such as those described above, some pipelines will not be able to recover all of their unrecovered purchased gas costs that had accrued before July 31, 1991, under the normal application of the regulations, before they terminate their PGA mechanisms upon implementation of restructuring. Therefore the 208/ See Natural Gas Pipeline Company of America, 61 FERC  61,238 (1992)(order approving settlement on, inter alia, past PGA balances and underrecoveries of GIDC costs). Docket No. RM91-11-004, et al. - 166 - Commission will give serious consideration to petitions for waiver of provisions of the regulations, e.g., the provisions regarding the FIFO method, if necessary to afford pipelines a reasonable opportunity to recover their pre-July 31, 1991 costs before the termination of their PGA mechanisms. Although the Commission will be flexible in the application of the PGA regulations in order to enable the pipelines to recover the costs in Account No. 191, the Commission cannot permit radical departures from the principles upon which the PGA regulations are based. 209/ Waivers of the technical provisions of the PGA regulations may not be sufficient, however, to afford some pipelines a reasonable opportunity to recover all of their pre-July 31 costs, and some pipelines may be unable to recover those costs prior to termination of their PGAs. The Commission will consider creative proposals developed by pipelines to enable them to recover their costs 210/ that do not run afoul of the filed rate doctrine. The Commission also encourages the pipelines and their customers to enter into settlements to resolve the recovery of any remaining Account No. 191 balances. Accordingly, the 209/ See, e.g., Carnegie Natural Gas Company, 60 FERC  61,225 (1992) (Commission denied Carnegie's request for waiver of the regulations to suspend its surcharge rates and to offset its commodity surcharge balance with demand refunds); and CNG Transmission Corporation, 60 FERC  61,227 (1992) (Commission denied a request for a waiver of the regulations to defer recovery of a portion of surcharge balance and to use refunds to offset that balance). 210/ See, e.g., CNG Transmission Corp., 61 FERC  61,156 (1992) (permitting sale of gas from storage inventory). Docket No. RM91-11-004, et al. - 167 - Commission will clarify and expand its prior policy to allow proposals from pipelines for special billing mechanisms to recover such costs, and will consider the merits of their proposals on a case-by-case basis. These proposals should be filed as part of the pipeline's restructuring compliance filing. By inviting these proposals, however, the Commission has no intent to be so flexible as to permit a delay in the implementation of the unbundling requirement. 3. Eligibility of Costs for 100 Percent Recovery as GSR Costs a. Eligibility to recover GSR costs incurred outside restructuring CNG argues that the Commission should grant clarification to permit pipelines to recover as transition costs those GSR costs, whenever incurred, that are reasonably related to the pipeline's implementation of Order No. 636. CNG wants the Commission to authorize pipelines to engage in the process of reforming their contracts immediately, even before their customers make final decisions concerning their sales entitlements. Furthermore, CNG does not want the Commission to impose deadlines on the recovery of GSR costs. CNG argues that if a producer-supplier knows that the pipeline will be unable to recover its GSR costs unless a settlement is reached by a certain date, the producer-supplier will be unwilling to negotiate. INGAA objects to the Commission's statement in Order No. 636-A that the use of a surcharge on transportation rates to recover GSR costs will be limited to such costs that arise as a Docket No. RM91-11-004, et al. - 168 - result of customers' decisions as a result of the restructuring proceedings, and that if customers reduce or terminate their sales entitlements upon expiration of their contract terms after restructuring, the costs of any further gas supply realignments would only be recoverable through market-based sales rates. 211/ INGAA requests the Commission to clarify that the mechanism to recover gas supply realignment costs will be applicable to all prudently incurred costs resulting from pipelines having to reform to market levels, or terminate altogether, their existing supply contracts with producers, even if these costs arise outside of the formal restructuring period. Tenneco requests the Commission to clarify that pipelines may realign contracts prior to implementation of their restructured services. Tenneco notes the Commission's statement in Order No. 636-A that "[i]f all customers terminate their sales entitlements during restructuring, a pipeline may have to buy out all of its gas supply contracts. . . , " 212/ and seeks clarification that this statement does not, by implication, prohibit pipelines from realigning contracts prior to implementation of their restructured services. Tenneco asserts that early contract realignment will help to reduce transition costs. K N seeks clarification that sales customers whose contracts expire after restructuring remain liable for GSR costs. K N 211/ Order No. 636-A at p. 30,649. 212/ Id. at p. 30,657. Docket No. RM91-11-004, et al. - 169 - states that it does not believe that current sales customers whose contracts will expire in the near future are allowed under Order Nos. 636 and 636-A to escape gas supply realignment costs by requiring that K N remain in the merchant role only for the duration of their current contract, and then escaping without any gas supply costs responsibility. The Commission denies rehearing of the eligibility issues raised in the rehearing petitions. As the Commission explained in Order Nos. 636 and 636-A, a pipeline's costs of realigning gas supply contracts are eligible for recovery if these costs are attributable to the implementation of Order No. 636. 213/ The costs eligible for recovery are limited to costs that arise as a result of sales customers' decisions during the restructuring proceedings either to reduce or terminate their gas supply obligations with the pipeline. 214/ In their compliance filings, pipelines must propose a mechanism for recovery of these costs. The determination of whether specific costs are attributable to the implementation of Order No. 636 will have to be decided on the basis of the specific facts. Pipelines do not have to delay entering into negotiations to realign their gas supply contracts until after their customers have made final choices during the course of the restructuring proceedings in order for the costs of those realignments to be eligible for the special billing 213/ Order No. 636 at p. 30,459. 214/ Order No. 636-A at p. 30,649. Docket No. RM91-11-004, et al. - 170 - mechanisms for GSR costs under Order No. 636. 215/ However, a pipeline may not retain contracts to provide gas sales in a competitive market and then seek recovery for any further realignment of those contracts that may become necessary. As the Commission stated in Order No. 636-A, pipelines continuing to engage in a merchant function after restructuring are free to set the prices and terms for those contracts, but, by the same token, must bear the risk of their decisions and provide for further realignment in their gas supply agreements. 216/ Enron asserts error in the Commission's statement that Order No. 636 was not intended to affect the provisions of existing settlements resolving transition costs. Specifically, Enron cites the Commission's decision in Florida Gas Transmission Company 217/ that the costs of certain take-or-pay settlements entered into in December 1991 and January 1992, and subject to the provisions of Florida Gas' transition cost recovery (TCR) mechanism, could not be eligible for recovery as GSR costs under Order No. 636. Enron argues that the Commission improperly established a "bright line" test for eligibility, without giving Florida Gas an opportunity to show that the issuance of the NOPR in this proceeding had significantly altered 215/ Enron requests clarification that the definition of GSR costs includes costs resulting from pipelines having to reform to market levels, or terminate altogether, their existing supply contracts with producers. The Commission grants this request. Both such costs are included. 216/ Order No. 636-A at p. 30,649. 217/ 59 FERC  61,413 (1992). Docket No. RM91-11-004, et al. - 171 - the circumstances under which Florida Gas had agreed to its TCR mechanism, and had caused the incurrence of the gas supply realignment costs in question. The Commission will not address case-specific applications of its rule in this generic proceeding, but will address these issues in specific cases. The Commission has already rejected Florida Gas' arguments on rehearing for allowing it further opportunity to establish the eligibility for recovery of the costs in question as Order No. 636 transition costs. 218/ CIG asks for clarification that the GSR cost recovery mechanism can be utilized in connection with the realignment of producer contracts that extend beyond the term of existing sales contracts. The Commission grants the requested clarification. Prior to Order No. 636, pipelines' service obligations to their sales customers extended beyond the expiration of their sales contracts with those customers. Thus, the fact that the terms of gas supply contracts to be realigned extend beyond the terms of an existing pipeline's sales contracts has no bearing on the eligibility for recovery of the costs of realigning those contracts as transition costs under Order No. 636. 218/ Id., 61 FERC  61,016 (1992). The Commission also will not address, in this proceeding, UGI's arguments on rehearing that the Commission should not allow Columbia to retain the benefits from the "Global Settlement" and prior agreements while freeing them from the risk assumed relating to contract management, and UGI's request for a ruling that Columbia may not recover contract rejection costs arising from its bankruptcy. Docket No. RM91-11-004, et al. - 172 - b. Eligibility for recovery of GSR costs by pipelines with GIC mechanisms Enron seeks clarification that a pipeline is not precluded from seeking to recover GSR costs where a pipeline has utilized a GIC mechanism. It seeks assurance that the Commission will consider, on a case by case basis, the ability of the pipeline to recover GSR costs through the Order No. 636 mechanism. ANR requests clarification that it will be permitted to recover its GSR costs through an Order No. 636 recovery mechanism notwithstanding its implementation of a GIC charge for an interim period under a recently approved rate case and restructuring settlement. The Commission reiterates that gas supply costs for which GIC charges have been collected cannot be recovered again as transition costs. 219/ However, a pipeline may incur GSR costs as a result of its customers' actions under Order No. 636 that could not have been anticipated in designing the GIC and cannot be recovered through a GIC. The Commission will consider, on a case-by-case basis, whether the gas supply realignment costs attributable to an Order No. 636 restructuring of a pipeline with a GIC are eligible for recovery through the special billing mechanism of Order No. 636. PGT requests clarification that a pipeline that establishes cost-based rates for its unbundled sales service will continue to 219/ Order No. 636-A at p. 30,654. The Commission prohibits a pipeline with a GIC mechanism in place from filing under Order No. 528 to recover take-or-pay costs. Docket No. RM91-11-004, et al. - 173 - be eligible for recovery of prudently incurred gas supply realignment costs under Order No. 636 or Order No. 528. 220/ Initially, the basis of a pipeline's rates for its unbundled sales of gas is not relevant to its eligibility to recover take- or-pay costs under Order No. 528 or gas supply realignment costs under Order No. 636. As noted earlier, the basis for establishing the price for unbundled gas sales is a matter between the pipeline and its customers. The recovery of gas supply costs, including any costs of contract reformation after restructuring, must be negotiated by the parties. How the price under a particular unbundled sales contract is based will be a contractual, not a regulatory matter. c. Prudence Northern Indiana questions the Commission's statement in Order No. 636-A that downstream pipelines should not have to absorb any of the transition costs billed to them by upstream pipelines, and advocates holding downstream pipelines to the same standards of prudence review of transition costs as any other costs. The Commission is not requiring any pipelines -- upstream or downstream -- to absorb transition costs under Order No. 636. However, just as upstream pipelines are subject to challenges to their prudence with regard to incurring transition costs, the Commission clarifies that downstream pipelines will also be 220/ The term "gas supply realignment costs" is applicable to transition costs incurred as a result of restructuring under Order No. 636, but not to take-or-pay buyout or buydown costs recoverable under Order No. 528. Docket No. RM91-11-004, et al. - 174 - subject to such challenges in connection with passing through transition costs billed to them by upstream pipelines. The transition costs incurred by the downstream pipelines as a result of implementing this rule are like any other costs incurred by the pipelines, and nothing in this order is intended to preclude a challenge to their prudence. CNG questions the Commission's statement in Order No. 636-A that the added presumption of prudence afforded to costs filed for recovery under Order Nos. 500 and 528 does not apply to GSR costs, and seeks clarification that the incurrence of GSR costs is presumptively prudent. CNG urges the Commission to reaffirm the established policy that a pipeline does not bear the burden of proving its prudence unless another participant introduces evidence that creates a serious doubt about the pipeline's prudence. The Commission clarifies that it has not changed the established burden of proof. The Order Nos. 500 and 528 special presumption of prudence, based on a percentage absorption of costs, does not apply to GSR costs. Gas Consumers assert that prudence reviews do not sufficiently protect small customers. They also assert that if pipelines attempt to recover non-restructuring costs as transition costs, the practical burden is on the customers to prove the imprudence of those costs not associated with Order No. 636. Gas Consumers argue that the Commission should shift the initial burden of going forward on prudence to the filing Docket No. RM91-11-004, et al. - 175 - pipeline and provide better guidance on what constitutes recoverable GSR costs under restructuring. 221/ The Commission will continue to develop policies and guidelines on defining what costs are eligible for treatment as GSR costs as issues arise. Pipelines have the burden of establishing that such costs are eligible for the special billing mechanisms under Order No. 636. As stated above, the special presumption of prudence under Order Nos. 500 and 528 do not apply, but customers will have the burden of presenting evidence that costs that would otherwise be eligible for such billing mechanisms cannot be recovered because they were not prudently incurred. Cincinnati Gas argues that the Commission's decision to preclude prudence challenges to previously approved cost- recovering mechanisms under Order Nos. 500 and 528 cannot be fairly applied in the circumstances on the Columbia system. Cincinnati Gas requests the Commission to clarify that Columbia's customers and the affected state commissions will be permitted to challenge the prudence of the company's pre-Order No. 636 reformation costs in any proceeding involving the flowthrough of GSR costs. Cincinnati Gas also argues that the Commission should allow challenges to Columbia's prudence under the global settlement if its GIC is terminated. The Columbia-specific issues will be resolved in the appropriate proceeding concerning 221/ CNG also requests guidance as to identification of the kinds of costs that constitute GSR costs. Docket No. RM91-11-004, et al. - 176 - Columbia's GSR costs on the basis of the unique facts in that proceeding. CNG states that the Commission should not presume that a pipeline's failure to exercise a "FERC-out" clause would be imprudent. CNG contends that the Commission should also assist pipelines by providing guidance on the propriety of exercising rights under a "FERC-out" clause. Specifically, CNG asks if any aspect of Order No. 636 has the effect of preventing a pipeline from recovering, as part of the pipeline's cost of service, the full amounts paid for natural gas, asserting that many of its gas purchase contracts contain a provision like this. Or do the provisions in Order No. 636 that permit pipelines to recover GSR costs mean that pipelines cannot rely on such contract language to excuse payment of the full contract price? CNG asserts that, without Commission guidance on this issue, litigation will arise in a host of jurisdictions and produce inconsistent interpretations of the Commission's intentions. 222/ The Commission did not establish any presumption of imprudence by a pipeline that fails to exercise a "FERC-out" clause. Nor will the Commission resolve questions about a pipeline's rights under particular provisions in a gas supply contract. First, the Commission's jurisdiction over producer supply contracts is limited to only a very few contracts, and will be completely abolished as of January 1, 1993, under the 222/ CNG also raises this same question in a petition for declaratory order filed on October 16, 1992, in Docket No. RP93-12-000. Docket No. RM91-11-004, et al. - 177 - provisions of the Natural Gas Wellhead Decontrol Act of 1989. 223/ Furthermore, even if the Commission had jurisdiction over certain contracts in the days remaining before January 1, it would defer resolution of contract interpretation questions of the kind raised by CNG to state or federal courts. Under Pennzoil Co. v. FERC, 224/ the Commission would be required to apply the applicable substantive state law to interpretation of such contracts, so an effort at Commission interpretation would not necessarily achieve the uniformity that CNG advocates. 225/ UtiliCorp Divisions objects to the Commission's statement in Order No. 636-A that it does not intend downstream pipelines to absorb any of the transition costs billed to them by upstream pipelines and the Commission's allowance of mechanisms in downstream pipelines' restructuring compliance filings to flow through those costs. UtiliCorp Divisions argues that such a policy violates the Commission's general policy against cost trackers and fails to provide an incentive for pipelines to vigorously contest both the prudence of the upstream pipeline in incurring such costs and the allocation of those costs to the downstream pipeline. 223/ Pub. L. No. 101-60, 103 Stat. 157 (1989). 224/ 645 F.2d 360 (5th Cir. 1981), cert. denied, 454 U.S. 1142 (1982). 225/ In view of this ruling on CNG's request for rehearing, its petition for declaratory order will also be denied for these reasons. Docket No. RM91-11-004, et al. - 178 - One-hundred percent recovery of Order No. 636 transition costs billed to downstream pipelines by upstream pipelines is consistent with the Commission's policy permitting such recovery of take-or-pay settlement costs under Order No. 528. Permitting the use of some form of tracking mechanism for such passthrough is reasonable in view of the nature of the costs, although the details of the recovery mechanism must permit reasonable opportunities for interested parties and the Commission to review and challenge the prudence of the costs. 4. Transportation Contracts at Fixed Rates or Discounts. Enron objects to the Commission's statement in Order No. 636-A that "[i]f a pipeline agreed to provide transportation service at a fixed rate, without a right to passthrough any surcharges or other cost increases, then the pipeline will have to bear the costs of the bargain it made." 226/ Enron contends that pipelines should be allowed to recover transition costs from customers with existing transportation service agreements containing fixed rates, discounts, or caps. Enron argues that pipelines could not have anticipated the transition brought about by Order No. 636 and the resulting transition costs, and that denial of relief from their fixed rate contracts is directly contrary to the assurances of Order No. 636 that pipelines could recover 100 percent of all prudently incurred transition costs. 226/ Order No. 636-A at p. 30,662. Docket No. RM91-11-004, et al. - 179 - Williston asserts that a pipeline may have entered into fixed rate transportation contracts with firm transportation customers that are not former sales customers, and may have been willing to accept the risk of underrecovery from these customers of a portion of the costs contemplated under Order Nos. 500 and 528, but that the sweeping restructuring mandated by Order No. 636 has fundamentally changed the assumptions on which these agreements were based. Williston also objects to the Commission's rejection of the suggestion that pipelines be allowed to recover transition costs from other customers, or during later periods, when they are unable to fully recover such costs due to the need to discount transportation rates. According to Williston, the Commission's policy simply denies recovery of a portion of a pipeline's prudently incurred transition costs, despite general statements to the contrary. Natural argues against the requirement of allocating GSR costs to transportation under fixed rates or discounted arrangements negotiated before issuance of Order No. 636-A. Natural states that it has had to offer discounts or enter into fixed rate contracts, and that allocation of transition costs to these contracts would, absent some alternative recovery mechanism, preclude Natural from recovering transition costs in direct contravention of the Commission's stated intent. According to Natural, it had no basis, at the time the agreements were negotiated, to anticipate that such arrangements would subject it to absorption of transition costs. Docket No. RM91-11-004, et al. - 180 - Natural also objects to requiring the allocation of transition costs to future discounted or fixed rate transportation agreements. Natural asserts that parties require a reasonable level of rate certainty to enter into firm transportation arrangements, and that since the transition costs a shipper may have to bear are not well defined, pipelines and shippers will be reluctant to enter into new contracts. Certain firm transportation arrangements will simply not bear the additional burden of transition costs, according to Natural, and the Commission's policy will distort the market for, and economics of, firm transportation. The Commission clarifies that its statements in Order No. 636-A were not intended to apply a different standard to pipelines that offered discounts pre-restructuring. The Commission's policy is that pipelines will be permitted to recover 100 percent of their prudently incurred gas supply realignment costs that result from compliance with Order No. 636. 227/ In their compliance filings, pipelines may propose methodologies to ensure their ability to recover their prudently incurred GSR costs given the individual circumstances on their systems, including discounted transportation provided pre- restructuring. Pipelines choosing to offer discounted firm transportation in the future, however, do so at the risk of not being permitted to recover GSR costs associated with those contracts. 227/ Order No. 636 at p. 30,460. Docket No. RM91-11-004, et al. - 181 - 5. Stranded Costs CNG urges the Commission to provide guidance on the recoverability of stranded costs. Specifically, CNG wants to know whether the cost of facilities no longer needed to render restructured services -- unused gathering facilities, production area stubs and laterals, non-productive assets, and any unrecovered purchased gas costs -- are recoverable as stranded costs. CNG contends that after restructuring is complete and unbundled services begin, customers will challenge both the eligibility and prudence of the pipeline's transition costs. CNG states that few pipelines will be willing to risk the incurrence of costs that might arguably, for want of guidance, be challenged as ineligible stranded costs. To be a "stranded cost," the item must no longer be "used or useful" after restructuring. To qualify for 100 percent recovery under Order No. 636, the facilities must have been rendered no longer used or useful as a result of the pipeline's compliance with the order. The Commission will consider issues concerning the eligibility for recovery of any claimed stranded costs in the proceedings where pipelines seek to recover such costs. However, once a pipeline's costs have been determined eligible for recovery as stranded costs, the pipeline may not subsequently seek recovery of those costs as an element of its cost of service in any future rate proceeding without recognition of the costs it has recovered as stranded costs. Docket No. RM91-11-004, et al. - 182 - Among the costs that are potentially eligible for recovery as stranded costs are the costs of capacity on upstream pipelines and upstream storage (Account No. 858 and 824), storage facilities, production facilities, products extraction facilities, gathering facilities, and transmission facilities. This list is not exhaustive and other costs will be considered on a case-by-case basis. 6. Miscellaneous a. Exit Fees CNG requests authorization to direct bill customers departing the system for their share of the GSR costs, if the customer refuses to agree to a negotiated exit fee. CNG argues that by declining to allow the unilateral imposition of an exit fee or a direct bill on departing customers, the Commission has substantially undercut the pipeline's ability to have the departing customer bear its fair share of the GSR costs. Furthermore, CNG argues that a departing customer's refusal to pay an exit fee will cause remaining customers to shoulder an increasing burden of the GSR costs. Williston also argues that the Commission's prohibition in Order No. 636-A of a unilateral imposition of exit fees on a customer that is reducing or terminating sales, but is not reducing its reservation of transportation capacity, deprives pipelines of a legitimate vehicle for cost recovery. The Commission clarified in Order No. 636-A that it was not authorizing the unilateral imposition of exit fees on customers Docket No. RM91-11-004, et al. - 183 - that are reducing or terminating gas purchases from the pipeline, but not departing the system as transportation customers. As long as a customer remains on the system as a firm transportation customer of the pipeline, the pipeline can recover a portion of its GSR costs through the surcharge on that customer's transportation rates. Pipelines and their customers may negotiate exit fees in lieu of, or in combination with, a surcharge on reservation fees for recovering GSR costs. The Commission strongly encourages this. 228/ A customer may also negotiate the payment of an exit fee for a release from its obligation to pay for firm transportation capacity, and thus depart the system altogether. But, absent such a negotiated exit fee, the Commission will not require customers to pay exit fees or permit them to be direct billed for the recovery of GSR costs. b. Limited section 4 filings to recover transition costs UtiliCorp Divisions also objects to the Commission's clarification in Order No. 636-A (which UtiliCorp Divisions contends is a change in position rather than a clarification) that pipelines may file to recover GSR costs and to direct bill Account No. 191 balances in limited section 4 proceedings. UtiliCorp Divisions argues that the Commission's actions here contrast, without reasoned basis, with its prior rulings barring 228/ If a customer leaves the system as a transportation customer before its contract expires, the pipeline will be in a posistion to charge that customer an exit fee since the early (and valid) termination of the contract can only be accomplished by mutual agreement by the pipeline and shipper. Docket No. RM91-11-004, et al. - 184 - transition cost trackers in the context of gas inventory costs charges by an upstream pipeline to a downstream pipeline. UtiliCorp Divisions contends that only if all costs are considered in one proceeding, both those which have increased and those which have decreased, can the Commission be assured that the overall rates charged customers are reasonable as required by the NGA. Unrecovered Account No. 191 balances and GSR costs may be recovered through one-time-only or short-term charges that are not necessarily related to a pipeline's ongoing patterns of revenues and expenses. Accordingly, there is no particular benefit in reviewing the amounts or eligibility for recovery of these costs, along with all of the pipeline's other costs, in the context of a general section 4 rate case. Moreover, the details of the cost recovery mechanisms will have been resolved in the restructuring proceedings prior to the time limited section 4 filings are made to recover these costs. Transco requests the Commission to allow limited section 4 filings to recover stranded costs. Transco states that the requirement to use a full-blown section 4 rate case to recover stranded costs is administratively burdensome, because it is predictable that every pipeline will incur stranded costs, and the Commission and interested parties will be inundated with a new major rate case by every restructuring pipeline. According to Transco, stranded costs do not represent new costs, but costs that are currently being collected in rates in a manner that can Docket No. RM91-11-004, et al. - 185 - be expected to change as a result of restructuring, and the requirement of a full section 4 rate filing will deny pipelines full recovery of transition costs by delaying the implementation of rates to recover costs no longer recovered under restructured rates. There is enough for affected parties to do in the next year, Transco asserts, without imposing the demands of a full- blown general rate proceeding, where a proceeding on a limited section 4 filing would afford a fair examination of the costs at issue. The Commission will allow pipelines to make limited section 4 filings to recover Account No. 858 costs and the costs of stranded facilities that are currently incrementally priced, such as storage facilities on some pipeline systems. Since these costs are already in the cost of service, they could be recovered through a tracking-type procedure. However, pipelines must file to recover the costs of most, if not all other stranded facilities in general section 4 rate proceedings. A full section 4 proceeding is necessary because of the necessity of determining depreciable plant balances, associated taxes and other direct costs, and appropriate allocations of indirect costs to the stranded items. c. When can pipelines begin recovery of transition costs? PSE&G requests clarification that even a limited section 4 filing to recover transition costs must comply with the requirement of section 154.63(e)(2) of the Commission's Docket No. RM91-11-004, et al. - 186 - regulations 229/ that any projected estimate of such costs must be known and measurable with reasonable accuracy as of the date of the pipeline's filing. PSE&G also requests clarification that a pipeline may not begin to recover any transition costs, even subject to refund, until such time as the Commission has issued a final order on the merits of the pipeline's compliance filing in which the Commission makes findings that the pipeline is in full compliance with the requirements of Order Nos. 636 and 636-A. UDC requests that the Commission not allow pipelines to begin recovering potential, estimated transition costs through their compliance filings. UDC states that the Commission should clarify that the pipeline may not recover transition costs from its customers until those costs are actually incurred, unless the parties otherwise agree. LILCO also requests clarification that GSR costs are only recoverable after they have been incurred, but also requests that if pipelines are allowed to recover estimated (but not yet incurred) GSR costs, interest not be allowed on the unpaid balance of any such estimated costs. GSR costs must be actually incurred, or known and measurable with reasonable accuracy, in order to qualify for recovery by the pipeline. 230/ Pipelines may not begin recovery of any 229/ 18 CFR  154.63(e)(2)(1992). 230/ For purposes of recovering GSR costs, the Commission will consider reasonable variations from the test year requirements utilized in general section 4 rate cases. Docket No. RM91-11-004, et al. - 187 - transition costs under Order No. 636, even subject to refund, until after the Commission has found the pipeline to be in full compliance with the requirements of Order Nos. 636 and 636-A. Finally, pipelines will not be permitted to recover interest on the unpaid balance of any estimated GSR costs. Pipelines should not make filings to begin recovery of their GSR costs until after the Commission has approved the recovery mechanisms for such costs included in their restructuring compliance filings. When the Commission rules on a compliance filing, it will specify a prospective date when the tariff sheets implementing restructured services will become effective. Pipelines will then have an opportunity to make a limited section 4 filing to begin recovery of actual GSR costs, under the approved mechanism, contemporaneously with the implementation of the restructured services. d. Small customers Tennessee and Columbia Small Customers allege that the Commission erred in Order No. 636-A in refusing to reduce small customers' responsibility for transition costs by 50 percent, consistent with the small customer protection mechanism established in Order No. 528-A. They argue that Order No. 636-A does not go far enough to mitigate the negative impact of Order No. 636 on small customers. Order No. 636-A significantly modified the final rule to ensure the ability of small customers to secure the benefits of restructuring and to mitigate adverse effects. The additional Docket No. RM91-11-004, et al. - 188 - mitigation of a 50 percent reduction in transition costs for every small customer on every pipeline system is not warranted. However, pipelines and parties in the restructuring proceedings on particular systems may consider such additional mitigation mechanisms they may agree may be appropriate. e. Refund provision NJBRC advocates that there be no interim collection of transition costs, subject to refund. NJBRC argues that, in light of recent federal court actions in the Columbia bankruptcy proceeding, allowing such recovery prior to a final decision on any challenges to eligibility or prudence will place ratepayers' monies too much at risk. As a general matter, under section 4(e) of the NGA, pipelines are entitled to begin recovering their filed rates, subject to refund, at the end of any suspension period, if the Commission has not rendered a final decision of the justness and reasonableness of the changed rates. Section 4(e) also provides that a pipeline may be required to furnish a bond to ensure the payment of refunds of rate increases collected subject to refund. Parties may petition the Commission to require such a bond where the circumstances might warrant it. The Commission will endeavor to process the filings as quickly as possible (as contemplated by NGA section 4) to try to minimize the length of time rates are collected subject to refund. f. Direct billing of Account No. 858 costs LILCO argues that the Commission erred in permitting Account No. 858 transition costs to be direct billed in the same manner Docket No. RM91-11-004, et al. - 189 - as Account No. 191 costs instead of requiring them to be treated like other GSR costs. 231/ According to LILCO, prudently incurred, eligible, upstream-pipeline GSR costs incurred by the downstream pipeline are no different from its own GSR costs and should be recovered no differently. United asserts that in Order No. 636, the Commission classified Account No. 858 costs that could not be directly allocated to customers of unbundled services as "stranded costs." United requests clarification that Order No. 636-A supersedes Order No. 636 on this point, and that pipelines may direct bill Account No. 858 balances to their own customers. Both LILCO and United misconstrue what the Commission said in Order No. 636-A. The Commission addressed an issue raised by National Fuel concerning pipelines with Account No. 858 trackers, namely, how may a pipeline recover an unrecovered positive balance in such a tracking account upon termination of the tracker? Such a situation is precisely analogous to unrecovered balances in Account No. 191 upon termination of a PGA mechanism, and the Commission provided for direct billing of such balances in both situations. The Commission was not authorizing direct billing of upstream pipeline GSR costs or future Account No. 858 costs that become "stranded" in the course of restructuring. How these costs will be recovered will be dealt with on a case-by- case basis. 231/ LILCO cites Order No. 636-A at p. 30,655. Docket No. RM91-11-004, et al. - 190 - g. Avoiding multiple GSR charges Producer Associations argue that short-haul, production-area transportation, and transportation to pooling points and market centers, should be exempt from GSR recovery programs. Otherwise, they argue, transportation arrangements will be subject to multiple assessments of GSR surcharges that will often discourage the use of the most efficient path to market. Producer Associations cite the Commission's policy of not permitting multiple assessments of Gas Research Institute surcharges as precedent for its proposal. The Commission will not permit exemption of short-haul, production-area transportation, or transportation to pooling points and market centers from GSR surcharges. Such exemptions would frustrate realization of the Commission's goal of spreading transition costs equitably over a broad customer base. However, pipelines and affected parties in the restructuring proceedings should design mileage-sensitive surcharges, so that shippers that use only a portion of the pipeline do not pay a disproportionate share of surcharges. 232/ h. Default under an assigned supply contract Enron seeks clarification that the pipeline must be able to negotiate, as part of the terms and conditions of assigning supply contracts to its customers, a means to recover GSR costs attributable to a customer's default under the assigned contract, 232/ See Mechanisms for Passthrough of Pipeline Take-or-Pay Buyout or Buydown Costs, 54 FERC  61,095 at p. 61,301 (1991)(Order No. 528-A). Docket No. RM91-11-004, et al. - 191 - where the pipeline remains liable to the producer. Otherwise, according to Enron, the pipeline could be in a "catch-22" situation because the customers could take assignment of such contracts and subsequently elect not to perform under such contracts. In Order No. 636-A, the Commission stated that the details of responsibility for transition costs of customers that accept assignment of gas supply contracts, in comparison with those that do not, must be worked out in the restructuring proceedings. 233/ The Commission will consider any reasonable provisions the pipelines and their customers can negotiate to protect the pipeline in the event of a default on an assigned contract. i. Recovery of GSR costs from rates for storage service PSE&G seeks clarification that in the absence of any connection between cost causation and cost incurrence, transition cost surcharges designed to recover GSR costs will not be assessed against storage services, even though storage is now defined as transportation under Part 284. PSE&G argues that there is no connection between a pipeline's incurrence of such costs and its provision of storage service, and that, since storage customers will already be assessed GSR costs in connection with their transportation to and from storage facilities, no additional assessments for storage service are warranted. 233/ Order No. 636-A at p. 30,660. Docket No. RM91-11-004, et al. - 192 - Nothing in Order No. 636 or 636-A requires pipelines to impose demand surcharges for the recovery of GSR costs on unbundled storage service. If a pipeline proposes to impose such a surcharge on storage service, it should explain why the surcharge on transportation to and from the storage facility does not recover a fair share of the GSR costs from the storage customers. j. Great Plains synthetic gas Northern Natural, Transwestern, and Florida Gas (collectively referred to as Enron) request that Order No. 636-A be clarified to reflect that the costs of the Great Plains Gasification Project may not be allocated to NGA section 7(c) shippers. Enron asserts that section 7(c) customers clearly did not cause or were not benefitted by contracts involving the Great Plains synthetic natural gas. Enron asserts that the Great Plains costs have consistently been treated as gas supply costs, while the section 7(c) customers merely utilized the pipeline for transportation. Enron asserts that, in many instances, these costs will be recovered from customers who did not even utilize the pipeline out of the Great Plains project, and that since the 7(c) transporters neither caused nor benefitted from the Great Plains project, allocating costs associated with Great Plains to those transporters would only distort the market signals between supply and demand. In Order No. 636-A, the Commission clarified that it would consider any reasonable proposal by the pipelines that purchase Docket No. RM91-11-004, et al. - 193 - Great Plains gas for recovery of the costs of that gas, whether or not modeled on the proposal approved in a Transco settlement. 234/ If any of the pipelines that purchase Great Plains gas propose to recover the costs of such gas from transportation rates for service under individual section 7(c) certificates, the Commission will consider any arguments for or against such recovery in the proceeding where the proposal is made. k. Triennial rate review New England Power and ConEd assert that the Commission erred by not requiring pipelines to be subject to a three-year rate review. New England Power asserts that the elimination of the triennial rate review requirement allows pipelines, once rates are in place, to sit back and watch their rates of return on equity rapidly escalate, with no corresponding obligation or incentive to refile and reduce their rates. New England Power asserts that unless the Commission institutes remedial measures on rehearing, natural gas consumers will not be sufficiently protected from pipelines' excessive transportation rates. New England Power and ConEd assert that the section 5 complaint procedure is by itself inadequate protection because its remedy is prospective only. Finally, New England Power asserts that the Commission has the authority to require periodic section 4 filings as a condition of some other benefit voluntarily accepted by the pipeline. It asserts that the numerous benefits conferred 234/ Order No. 636-A at p. 30,658. Docket No. RM91-11-004, et al. - 194 - on pipelines by the Order No. 636 regulatory scheme, such as transition cost recovery and SFV rate design, justify imposition of a periodic rate filing requirement. ConEd asserts that in rejecting requests to maintain the three year rate review, the Commission failed to adequately explain how a change from cost-based to market-based rates reduces the need for periodic Commission review of a pipeline's non-gas rates. ConEd asserts that, as with the PGA mechanism, market-based sales rates similarly provide a pipeline with the opportunity to change only one cost element of its rates outside of a general section 4 rate proceeding. Finally, ConEd asserts that a rate design which virtually assures a pipeline full cost recovery regardless of the actual level or quality of service that it provides, i.e., SFV, cries out for greater Commission oversight, not a relaxation of the current rate review process. It is unnecessary for the Commission to attempt to replicate the triennial rate review provisions of the PGA regulations when pipelines terminate their PGAs. In any event, there are limits to the authority of the Commission to require pipelines to periodically justify their existing rate levels. 235/ However, as the Commission stated in Order No. 636-A, the procedures provided under NGA sections 4 and 5 should ensure that a pipeline's rates are just and reasonable under ordinary circumstances, and the Commission intends to exercise its powers 235/ Public Service Commission of New York (PSCNY) v. FERC, 866 F.2d 487 (D.C. Cir. 1989)(requiring periodic filings under NGA section 4 beyond Commission's statutory authority). Docket No. RM91-11-004, et al. - 195 - under those sections to the fullest. In circumstances where there are reasonable expectations of declining costs over the long run, ratemaking methods are available to establish rates that will not over-recover those costs. 236/ Furthermore, parties may negotiate for a pipeline's agreement to file section 4 rate proceedings periodically, or by a date certain. 237/ l. Filing of Firm Transportation Service Agreements APGA requests the Commission to amend the regulations to require pipelines to file their firm transportation service agreements with the Commission or make them available to customers, in order to assure that pipelines treat their customers in a non-discriminatory fashion. APGA states that the Commission has, for example, stated that pipleines must offer evergreen provisions on a non-discriminatory basis, but has not provided a means of determining whether the pipleines are complying with this requirement. The prohibition against discriminatory practices is not a new requirement imposed by Order No. 636, but has always been a requirement under Part 284 of the regulations. The Commission eliminated the requirement that pipelines file copies of their service agreements in 1989 238/ and has received no 236/ See Ozark Gas Transmission System, 50 FERC  61,252 (1990)(order on remand from PSCNY v. FERC, supra), order on reh'g, 53 FERC  61,451 (1990). 237/ Ozark Gas Transmission System, 55 FERC  61,360 (1991). 238/ Final Regulations Clarifying the Filing Obligations for Part 284 Transportation and Sale of Natural Gas, FERC Stats. and Regs. [Regulations Preambles 1986-1990]  30,864. Docket No. RM91-11-004, et al. - 196 - complaints since then, nor is there any basis for concluding that a reinstatement of the requirement is necessary to ensure compliance with the prohibitions against discrimination. However, pipelines should make these contracts available upon request so that interested parties can be assured of compliance. C. Confidentiality of Discovery Data Rochester filed a motion for clarification of the Commission's June 24, 1992 order in these proceedings relating to the use of discovery procedures in the pipeline restructuring proceedings. 239/ Rochester asserts that some pipelines submitting discovery data to the parties and Commission staff have claimed that such material is privileged and confidential pursuant to Rule 602(e)(2) of the Commission's Rules of Practice and Procedure, which provides that an offer of settlement that is not approved by the Commission, and any comment on that offer, is not admissible in evidence against any participant who objects to its admission. Rochester argues that data and material submitted in response to the staff's data requests in restructuring proceedings are not subject to the provisions of Rule 602(e)(2) because they are not offers of settlements or comments on such offers. The Commission grants the requested clarification. Data and material submitted pursuant to staff data requests in a restructuring proceeding prior to the date the pipeline files its compliance filing are not subject to the provisions of Rule 239/ 59 FERC  61,351 (1992). Docket No. RM91-11-004, et al. - 197 - 602(e)(2). Section 388.112 of the Commission's regulations is the relevant provision governing the treatment of material submitted to the Commission under a claim of privilege or confidentiality. Parties may negotiate their own protective agreements regarding information exchanged between the pipelines and parties in the restructuring proceedings. However, the information exchanged in such proceedings is not for the purpose of settlement, but to assure that the pipeline has complied with the Commission's orders. IX. CONCLUSION With this order, the Commission ends this rulemaking process. The regulations governing the historic restructuring of the natural gas pipeline industry are now final. No further petitions for rehearing of Order No. 636-B will be considered. The Commission intends now to turn its attention and resources to processing each pipeline's compliance filing as quickly as possible so that gas consumers throughout the nation can begin to realize the competitive benefits of a restructured gas industry. Docket No. RM91-11-004, et al. - 198 - The Commission orders: Order Nos. 636 and 636-A, and the June 24, 1992 order in this proceeding, are clarified as set forth in this order, and rehearing of Order No. 636-A is denied. By the Commission. Commissioner Moler dissented in part with a separate statement attached. ( S E A L ) Lois D. Cashell, Secretary. APPENDIX Allied-Signal, Inc. - (Allied-Signal) American Gas Association - (AGA) American Natural Gas Corporation and National Energy Systems Company - (American Natural Gas) American Paper Institute, Inc. - (American Paper Institute) ANR Pipeline Company - (ANR) Arcadian Fertilizer, L.P. - (Arcadian) Arkla, Inc. - (Arkla) Associated Gas Distributors - (AGD) Atlanta Gas Light Company and Chattanooga Gas Company - (Atlanta Gas) BarClays Bank, PLC, Canadian Imperial Bank of Commerce, Credit Lyonnnais and The Fuji Bank, Ltd. - (Barclays) Blue Flame Suppliers, Corporation - (Blue Flame) Brooklyn Union Gas Company - (Brooklyn Union) Cincinnati Gas & Electric Company, The Union Light, Heat and Power Company, Lawrenceburg Gas Company and Mountaineer Gas Company - (Cincinnati Gas) Citizens Gas & Coke Utility - (Citizens Gas) CNG Transmission Corporation - (CNG) Colorado Interstate Gas Company (CIG) Columbia Gas Transmission Corporation - (Columbia) Consolidated Edison Company of New York, Inc. - (ConEd) Consolidated Minerals, Inc., Georgia-Pacific Corporation, Rinker Materials Corporation, and U.S. Agri-Chemicals Corporation - (Consolidated Minerals) East Tennessee Group and The Tennessee Valley Municipal Gas Association - (TVMGA) Elizabethtown Gas Company - (Elizabethtown) Florida Municipal Natural Gas Association - (FMNGA) Fuel Managers Association Great Lakes Gas Transmission Limited Partnership - (Great Lakes) Industrial Groups - (Process Gas Consumers Group, American Iron and Steel Institute, Georgia Industrial Group, Association of Businesses Advocating Tariff Equity, California Industrial Group, California Manufactures Association, and California League of Food Processors) Interstate Natural Gas Association of America - (INGAA) Interstate Power Company - (Interstate Power) JMC Power Projects K N Energy, Inc. - (K N) Docket No. RM91-11-004, et al. APPENDIX - 2 - Long Island Lighting Company - (LILCO) Louisville Gas and Electric Company - (Louisville) Memphis Light, Gas and Water Division, City of Memphis, Tennessee, Philadelphia Gas Works, and The American Public Gas Association - (APGA) Meridian Oil Inc. - (Meridian) Midland Cogeneration Venture Limited Partnership - (Midland Cogeneration) Missouri Public Service, Kansas Public Service, Michigan Gas Utilities, & Peoples Natural Gas Company, Divisions of UtiliCorp United Inc. - (UtiliCorp Divisions) Missouri Public Service, Kansas Public Service, & Peoples Natural Gas Company, Divisions of UtiliCorp United Inc. - (Indicated UtiliCorp Divisions) Mojave Pipeline Company - (Mojave) Municipal Gas Authority of Georgia National Association of Gas Consumers - (Gas Consumers) National Fuel Gas Supply Corporation - (National Fuel) Natural Gas Pipeline Company of America - (Natural) NERCO Oil & Gas, Inc. - (NERCO) New England Gas Distributors - (New England Gas) New England Power Company - (New England Power) New Jersey Board of Regulatory Commissioners - (NJBRC) New Jersey Natural Gas Company - (New Jersey Natural) New York State Electric & Gas Corporation - (NYSE&G) Northeast Energy Associates and North Jersey Energy Associates (Northeast Energy) Northern Distributor Group Northern Indiana Public Service Company - (Northern Indiana) Northern Natural Gas Company (Northern), Transwestern Pipeline Company (Transwestern), and Florida Gas Transmission Company (Florida Gas) - (Enron) Northern States Power Company and Northern States Power Company - (Northern States) Pacific Gas and Electric Company - (PG&E) Pacific Gas Transmission Company - (PGT) Pacific Interstate Offshore Company (PIOC) Pacific Offshore Pipeline Company - (POPCO) Panhandle Eastern Pipe Line Company, Texas Eastern Transmission Corporation, Algonquin Gas Transmission Company and Trunkline Gas Company - (PEC Pipeline Group) Peoples Gas Light and Coke Company, North Shore Gas Company and Northern Illinois Gas Company - (Peoples Gas) Power Authority of the State of New York - (Power Authority) Prior Energy Corporation - (Prior Energy) Producer Associations - (Independent Petroleum Association of America, Independent Petroleum Association of New Mexico, Docket No. RM91-11-004, et al. APPENDIX - 3 - Louisiana Association of Independent Producers and Royalty Owners, Ohio Oil & Gas Association, Oklahoma Independent Petroleum Association, and Panhandle Producers and Royalty Owners Association) Public Service Electric and Gas Company and New Jersey Natural Gas Company - (PSE&G) Questar Pipeline Company - (Questar) Rochester Gas and Electric Corporation - (Rochester) Sierra Pacific Power Company - (Sierra) Southern California Edison Company - (SoCal Edison) Southern Natural Gas Company - (Southern) Southwest Gas Corporation - (Southwest Gas) State Regulatory Commissions - (Iowa, Missouri, and Wisconsin) (State Commissions) Tenneco Gas - (Tenneco) Tennessee Small General Service Customer Group & the Columbia Small Customer Group - (Tennessee and Columbia Small Customers) TransCanada Pipelines Limited - (TransCanada) Transcontinental Gas Pipeline Corporation - (Transco) UGI Utilities, Inc. (UGI) United Cities Gas Company - (United Cities) United Distribution Companies (UDC) United Gas Pipe Line Company - (United) Virginia Electric and Power Company - (Virginia Power) Washington Gas Light Company - (Washington Gas) Western Resources, Inc. (Western Resources) Williams Gas Marketing Company - (WGM) Williston Basin Interstate Pipeline Company - (Williston) UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Pipeline Service Obligations ) Docket No. RM91-11-004 and Revisions to Regulations ) Governing Self-Implementing ) Transportation Under Part 284 of ) the Commission's Regulations ) Regulation of Natural Gas Pipelines ) Docket No. RM87-34-069 After Wellhead Decontrol (Issued November 27, 1992) MOLER, Commissioner, dissenting in part: I will not reiterate the points I made in my dissent to Order No. 636-A. However, a new issue is starkly presented to the Commission in this order, and I disagree with how my colleagues have resolved it. In Order No. 636-A we permitted small customers to continue their historical right to a one-part rate. On rehearing the small customers have pointed out that a right to capacity at a one-part rate on the downstream pipeline does not go far enough. They seek one-part rates all the way to the wellhead. In response to their request, the Commission leaves the issue of small customer rates on upstream pipelines to the vagaries of the restructuring proceedings. I disagree with that approach. By limiting the right to a small customer rate to customers "directly connected to" a pipeline, the majority has decided in this order that a small customer may not have access back to the wellhead. Moreover, the upstream capacity may also cost substantially more. This is because the small customer (which has in the past paid Account No. 858 costs as a volumetric charge) may have to pay a two-part rate, with a reservation charge, to get upstream access. I will closely watch how this issue plays out in the restructuring proceedings. For this reason, I must dissent in part. ______________________________ Elizabeth Anne Moler Commissioner