
    MIDWEST GAS USERS ASSOCIATION, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Kansas Power and Light Co., Williams Natural Gas Co., Amoco Production Company, CSG Exploration Co., Union Gas System, Inc., Mike Hayden, Governor of Kansas, et al., Intervenors.
    Nos. 86-1140, 86-1147, 86-1148, 86-1200, 86-1241 and 86-1269.
    United States Court of Appeals, District of Columbia Circuit.
    Argued Sept. 15, 1987.
    Decided Nov. 17, 1987.
    As Amended on Denial of Rehearing Feb. 16, 1988.
    
      Joseph E. Stubbs, with whom John E. Holtzinger, Jr., Ted P. Gerarden, Joseph 0. Fryxell, Washington, D.C., Brian J. Moline and Dana L. Gorman, Topeka, Kan., were on brief for petitioners/intervenors Midwest Gas Users Ass’n, et al., in Nos. 86-1140, 86-1147, 86-1148, 86-1200, 86-1241 and 86-1269.
    Douglas G. Robinson, with whom Douglas E. Nordlinger, Kenneth A. Gross, Washington, D.C., Kirk C. Jenkins and Robert R. Price were on brief for petitioner/intervenor CSG Exploration Co., in Nos. 86-1140, 86-1147, 86-1148, 86-1200, 86-1241 and 86-1269.
    Dale A. Wright, with whom James T. McManus and Michael E. Small, Washington, D.C., were on brief for Williams Natural Gas Co., petitioner in No. 86-1241 and intervenor in Nos. 86-1140, 86-1147, 86-1148, 86-1200 and 86-1269. John H. Cary, Knoxville, Tenn., also entered an appearance for Williams Natural Gas Co.
    Joel M. Cockrell, Atty., F.E.R.C., with whom Catherine M. Cook, Gen. Counsel and Jerome M. Feit, Sol., F.E.R.C., Washington, D.C., were on brief for respondent in Nos. 86-1140, 86-1147, 86-1148, 86-1200, 86-1241 and 86-1269. Joseph S. Davies, Atty., F.E.R.C., Washington, D.C., also entered an appearance for respondent.
    William I. Harkaway, Harvey L. Reiter, Washington, D.C., John K. Rosenberg and Martin J. Bregman, Topeka, Kan., for Kansas Power and Light Co., and Morton L. Simons, Washington, D.C., for Union Gas System, Inc. were on joint brief for inter-venors, Kansas Power and Light Co., et ah, in Nos. 86-1140, 86-1147 and 86-1148.
    David M. Stryker, William H. Emerson, Tulsa, Okl., Kevin M. Sweeney and Jon L. Brunenkant, Washington, D.C., were on brief for Amoco Production Co., intervenor in Nos. 86-1140, 86-1147, 86-1148, 86-1200, 86-1241 and 86-1269.
    Before WALD, Chief Judge, MIKYA and EDWARDS, Circuit Judges.
   Opinion for the Court filed by Chief Judge WALD.

WALD, Chief Judge:

Midwest Gas Users Association, Governor Mike Hayden of Kansas, and The Kansas Corporation Commission (collectively Midwest) petition for review of two orders of the Federal Energy Regulatory Commission (FERC or the Commission). In those orders, the Commission determined that the higher prices established in amendments of a gas purchase contract between the purchaser Northwest Central Pipeline Corporation (Pipeline) and certain limited partnership producers were the product of arm’s-length bargaining and satisfied the “negotiated contract price” requirement established in FERC Order No. 99. Therefore, the Commission concluded, the producers’ tight formation gas qualified for special incentive pricing under § 107(c)(5) of the Natural Gas Policy Act (NGPA). As a result of FERC’s determination that the producers’ gas qualified for higher incentive pricing, gas costs to Pipeline’s customers have increased dramatically; between March 1981 and November 1983, costs to consumers rose by an estimated $100 million. At issue here is FERC’s interpretation of the negotiated contract price requirement — in particular its test for arm’s-length bargaining — and FERC’s decision to defer resolution of certain fraud and self-dealing issues until after the completion of related district court proceedings.

In November 1983, Midwest filed an amended complaint with FERC seeking to prevent the producers from collecting the NGPA § 107(c)(5) incentive price. Midwest alleged that under Title I of the NGPA the higher prices established in the 1981 amendments did not satisfy the negotiated contract price requirement, because (1) when the amendments were executed, the best part of the producers’ drilling was already completed, indicating that the higher prices were not “necessary” to elicit high-cost gas production, as required by NGPA § 107; and (2) Pipeline and the partnerships had overlapping economic interests and therefore could not have bargained at arm’s-length. Midwest also alleged that Pipeline and the producers had engaged in fraud and self-dealing in violation of Title VI of the NGPA.

The Commission in the proceedings below rejected Midwest’s contentions. With respect to the Title I claims, FERC first ruled that any gas designated as tight formation gas qualifies automatically for incentive pricing, as long as the negotiated contract price requirement is met, regardless of whether drilling is substantially completed. The Commission then concluded that the higher prices established in the contract amendments were true negotiated contract prices that reflected arm’s-length bargaining, because Pipeline and the partnerships were not “affiliated entities” within the meaning of NGPA § 2(27), 15 U.S.C. § 3301(27). As to the Title VI claims, the Commission deferred final resolution of the issues of improper affiliation and fraud/abuse, until after the conclusion of related antitrust proceedings in the District Court for the Western District of Missouri.

The producers in this case contend that this court has no jurisdiction to review FERC’s determination that the partnerships’ natural gas qualified for incentive pricing, because under NGPA § 503, 15 U.S.C. § 3413, judicial review is not available if FERC upholds — as it did in this case — rather than reverses a jurisdictional agency determination that certain gas is of the kind that qualifies for incentive pricing. We reject this contention. Under Order No. 99, the negotiated contract price requirement is separate and distinct from the requirement that gas be properly designated tight formation gas by a jurisdictional agency. Indeed, the ascertainment of compliance with the negotiated contract price requirement was not delegated to local jurisdictional agencies. See Pennzoil Co. v. FERC, 671 F.2d 119, 125 n. 15 (5th Cir.1982). Accordingly, § 503, which governs administrative and judicial review of jurisdictional agency determinations, does not apply here, and there is no reason for this court to refrain from exercising jurisdiction over the present case.

On the merits, we conclude that the Commission’s determination that negotiated contract prices do not require case-by-case justification is a reasonable statutory interpretation. However, given the particular economic relationships and incentives in this case, we find that the Commission’s arm’s-length bargaining test was plainly inadequate to ensure that the prices “negotiated” by Pipeline and the partnerships would reflect only market forces. We therefore reverse and remand to the Commission for reformulation of the arm’s-length bargaining requirement. A reasonable test for arm’s-length bargaining must be broad enough to exclude transactions which, although they involve technically “nonaffiliated” parties, nonetheless have the potential to distort market forces in contravention of the declared purposes of the NGPA. In addition, we remand to the Commission the issue of whether the higher prices established in the 1981 amendments could have applied retroactively. Finally, we remand for the Commission to reconsider, in light of the broader arm’s-length bargaining test we are requiring it to formulate, its decision to defer consideration of the Title VI issues until after the completion of related district court proceedings.

I. Background

A. The NGPA and Order No. 99

The NGPA, enacted in 1978, created a new legislative framework for the regulation of natural gas. The NGPA “comprehensively and dramatically changed the method of pricing natural gas produced in the United States.” Public Service Comm’n v. Mid-Louisiana Gas Co., 463 U.S. 319, 322, 103 S.Ct. 3024, 3027, 77 L.Ed. 2d 668 (1983). The aim of the NGPA, however, “remains to assure adequate supplies of natural gas at fair prices.” Transcontinental Gas Pipe Line Corp. v. State Oil & Gas Bd., 474 U.S. 409, 106 S.Ct. 709, 716, 88 L.Ed.2d 732 (1986) (citing S.Rep. No. 436, 95th Cong., 1st Sess. 10 (1977)).

In Title I of the NGPA, which is entitled “Wellhead Pricing,” Congress defined numerous categories of natural gas production and set ceiling prices for “first sales” in each category. See 15 U.S.C. §§ 3311— 3333. Title Y gave the Commission authority to enforce the maximum lawful prices established under Title I. See 15 U.S.C. §§ 3411-3418. In addition, Congress provided the Commission with limited authority to establish special, higher maximum lawful prices for gas supplies recoverable only at particularly high cost:

The Commission may, by rule or order, prescribe a maximum lawful price, applicable to any first sale of any high-cost natural gas, which exceeds the otherwise applicable maximum lawful price to the extent that such special price is necessary to provide reasonable incentives for the production of such high-cost natural gas.

NGPA § 107(b), 15 U.S.C. § 3317(b). In NGPA §§ 107(c)(l)-(4), Congress specifically identified four sources from which gas produced would be deemed “high-cost natural gas.” In NGPA § 107(c)(5) Congress delegated to the Commission the further authority to include within the term “high-cost natural gas” any gas that is “produced under such other conditions as the Commission determines to present extraordinary risks or costs.” 15 U.S.C. § 3317(c)(5).

On July 16, 1979, President Carter recommended to Congress that incentives be established for the development of high-cost natural gas from “tight formations.” Thereafter, the Commission instituted rule-making proceedings to identify tight formation gas for which a special price would be necessary to induce production and to establish a price that would provide a “reasonable” incentive for such production. After the comment period, the Commission promulgated regulations in Order No. 99, to become effective on September 22, 1980, creating an incentive gas price under NGPA § 107(c)(5) for tight formation gas. The Commission established in Order No. 99 that in order for a producer to collect the tight formation incentive price, the producer’s underlying contract with purchasers of the gas must contain a “negotiated contract price,” which the Commission defined as:

any price established by a contract provision that specifically references the incentive pricing authority of the Commission under Section 107 of the NGPA, by a contract provision that prescribes a specific fixed rate, or by the operation of a fixed escalator clause.

18 C.F.R. § 271.702(a)(1) (1986). Order No. 99 was upheld in its entirety on judicial review. See Pennzoil, 671 F.2d 119.

B. The Proceedings in This Case

1. The Wamsutter and Moxa Agreements

On October 1, 1975, Amoco Production Company (Amoco) and CSG Exploration Company (CSG) entered into the Wamsut-ter Limited Partnership Agreement (Wam-sutter Agreement), under which Amoco agreed to commit to Pipeline gas reserves from approximately 400,000 acres in south central Wyoming. On March 15, 1976, Amoco and CSG entered into the Moxa Limited Partnership Agreement (Moxa Agreement). Under that Agreement, Amoco committed for the benefit of Pipeline gas reserves from approximately 200,000 acres in Wyoming. Under each Agreement, Amoco serves as general partner. Section 4.1 of both Agreements (which are nearly identical) defines the general partner’s powers broadly:

The General Partner shall have full, exclusive, and complete control of the management and operations of the Partnership, including but not limited to all phases of the drilling and completion programs and drilling arrangements with other parties which in Amoco’s sole judgment provides the most practical method of developing gas reserves for the Partnership.

The limited partner in the Agreements was CSG. CSG was formed on March 9, 1972 as a wholly-owned subsidiary of Pipeline to serve as a vehicle for acquiring and developing gas reserves for Pipeline. CSG’s primary obligation under the Agreements was to fund Amoco’s drilling activities. Pursuant to the Agreements, CSG was entitled to 80% of the net proceeds of the Partnerships’ gas revenues until it recovered its contribution of exploration and development funds. Thereafter, CSG received from 5% to 25% of the net proceeds. See Joint Appendix (J.A.) at 180-83, 221-22. Attached to each of the Agreements were certain documents entitled “Principles of Gas Purchase Contracts” (Principles). These Principles were the foundation for subsequent gas purchase contracts between the Partnerships and Pipeline. In these Principles, the Partnerships and Pipeline agreed that the gas price for the first year would be no less than the highest competitive price then being paid or offered for similar-quality gas in Wyoming, but in no event less than $1.75 per thousand cubic feet. Prices for each succeeding year were to increase 5% per thousand cubic feet above the preceding year’s price. The Principles provided, inter alia, that if FERC exercised pricing authority over the gas produced in Wyoming, Pipeline would pay either the applicable area or national rate approved by the Commission or a higher price, as agreed upon by the parties and approved by FERC.

On August 26, 1976, after execution of the Wamsutter and Moxa Agreements, Pipeline filed an application with the Commission for authorization to construct and operate a 611-mile pipeline from Wyoming to a point of interconnection with Pipeline’s existing pipeline system in Kansas. Pipeline proposed to use the new pipeline to obtain gas from southern Wyoming fields to offset declining production in its traditional supply areas of Kansas, Oklahoma and Texas. By orders dated September 1, 1978 and October 18, 1978, the Commission issued certificates of public convenience and necessity authorizing the construction and operation of the new pipeline. See J.A. at 116-19.

Between 1977 and 1981, Pipeline entered into more than 50 contracts with the Wam-sutter and Moxa Partnerships and Amoco individually for the purchase of gas to be transported through the new pipeline. Following enactment of the NGPA in November 1978, all contracts executed between Pipeline and the Partnerships explicitly provided that the price to be paid for the gas would be the maximum lawful price established by the NGPA. The contracts, however, also provided that if the Commission were subsequently to prescribe a higher rate applicable to the gas being sold, the Partnerships could collect the higher rate. See J.A. at 120.

2. The March 17, 1981 Contract Amendments

After the Commission issued its interim regulations stating the geological criteria for tight formation designation, Amoco applied for such designation for the formations underlying the Wamsutter and Moxa areas. The state jurisdictional agency, the Wyoming Oil and Gas Conservation Commission (Wyoming Commission), recommended in accordance with 18 C.F.R. § 271.708 that the Wamsutter and Moxa formations be designated as tight formations. After reviewing the Wyoming Commission’s recommendation and the comments received, the Commission approved the local agency’s recommendations. See FERC Order Nos. 109,110, “High-Cost Gas Produced From Tight Formations” (Nov. 14, 1980); 18 C.F.R. §§ 271.103(d)(3) & (4) (1987).

On March 17, 1981, after Order No. 99 was issued, Pipeline agreed to amend 38 of its existing Wyoming gas purchase contracts with the Partnerships and Amoco, by adding the “negotiated contract price” language called for by Order No. 99. The amendments specified that the premium tight formation price would be paid retroactively to July 16, 1979. See J.A. at 347-57.

When the contract amendments were executed, both Pipeline and CSG were wholly owned by Cities Service Company. All of the officers and directors of CSG were also officers, directors and/or employees of Pipeline. In addition, the person who signed the March 17, 1981 amendments on behalf of Pipeline as its Vice-President was at the same time Vice-President of CSG. See J.A. at 289, 754.

As a result of the March 1981 amendments, the Partnerships have charged Pipeline the maximum incentive price permitted for tight formation gas under NGPA § 107(c)(5), rather than the substantially lower prices under NGPA § 102 and § 103. The contract amendments increased gas costs to Pipeline’s customers by an estimated $100 million between March 1981 and November 1983. This cost to customers continues to increase as Pipeline continues to purchase tight formation gas from the Partnerships. See J.A. at 653-54, 768.

3. Commission Proceedings

In November 1983, Midwest filed an amended complaint with FERC against Pipeline, seeking to resist collection by the producers of the NGPA § 107(c)(5) incentive price. Under Order No. 99, tight formation gas qualifies for the § 107(c)(5) price if the underlying contract for the purchase of the gas contains a negotiated contract price clause. Midwest alleged that the higher prices established in the 1981 amendments did not satisfy the negotiated contract price requirement and therefore exceeded the maximum lawful price permitted by the NGPA.

While Midwest’s complaint was pending, Pipeline requested the Commission to issue an order declaring that the 1981 amendments constituted a negotiated contract price. The parties agreed that Pipeline’s petition would be consolidated with Midwest’s complaint.

On September 30, 1985, the Commission issued its declaratory order. The Commission saw Midwest as raising three issues: (1) whether the March 17, 1981 contract amendments qualified as a negotiated contract price; (2) whether the amendments allowed retroactive collection of a negotiated contract price under § 107(c)(5); and (3) whether the NGPA affiliated entities and fraud/abuse limitations barred the effectiveness of the amendments.

With respect to the first issue, Midwest argued that the purpose of the negotiated contract price was to create incentives for the production of additional new tight formation gas; the March 17, 1981 amendments in this case were not necessary to elicit any increased production of natural gas but were simply a windfall to the sellers, because, at the time they were executed, the Partnerships had already completed the best part of their drilling. The Commission rejected these contentions. It ruled that any gas designated as tight formation gas qualifies automatically for incentive pricing, as long as the contract contains a negotiated contract price clause, regardless of whether drilling is substantially completed. The Commission emphasized that the negotiated contract price requirement is simply “a part of the definition of gas entitled to the special incentive price.” Declaratory Order at 8 (Sept. 30, 1985) (quoting Pennzoil, 671 F.2d at 125). The Commission also stated that “[pjarties may, of course, add the qualifying language to their contracts by amendment.” Id.

The Commission turned next to the issue of whether the negotiated contract price could be made effective retroactively to July 16, 1979. The Commission found that Arkansas Louisiana Gas Co., 24 F.E.R.C. § 61,201 (1983), and United Gas Pipeline Co., 27 F.E.R.C. § 61,197 (1984), “support the proposition that parties can make a ‘negotiated contract price’ retroactive and that to hold the reverse would abrogate the parties’ rights under their original contracts.” Relying on a letter of the Commission’s former General Counsel Charles Moore, the Commission also concluded that the “filed rate doctrine” did not apply; it explained that § 107(c)(5) gas also qualified as gas under §§ 102 and 103 of the NGPA and that such gas had been deregulated and removed from FERC’s NGPA jurisdiction through NGPA § 601(a)(1)(B).

Third, the Commission addressed Midwest’s claim that Pipeline and the Partnerships were affiliates with overlapping economic interests and consequently the higher prices established in the contract amendments were not negotiated at arm’s-length but rather were excessive due to “fraud, abuse or similar grounds.” Midwest’s Amended Complaint at 2. As its test for whether arm’s-length bargaining occurred in negotiating the first sale of gas, the Commission formulated an “affiliated entities” test which borrows the definition of “affiliates” in NGPA § 2(27). Under the affiliated entities limitation as applied to Title I, a producer would not be entitled to charge an incentive price on its wellhead sales to an affiliated buyer pipeline. The Commission reasoned that, for purposes of Title I as well as Title VI, the affiliated entities limitation “only applies if ‘affiliates’ are involved.” Similarly, the Commission stated that the fraud and abuse provisions of the NGPA “would only apply in this particular case if ‘affiliates’ were involved, because the allegations of fraud and abuse are all premised on accusations of self-dealing between the pipeline and the partnerships.” The Commission then concluded that although it was “an extremely close question,” Pipeline and the Partnerships were not affiliated entities under NGPA § 2(27), because “it cannot be said that the partnerships ... controlled, were controlled by, or were under common control with [Pipeline].”

Finally, the Commission noted in its declaratory order that a related lawsuit by Gas Service Company and Kansas Power and Light Company against Pipeline and Amoco was pending in the District Court for the Western District of Missouri; the plaintiffs in that case had charged that the March 17, 1981 amendments were part of a conspiracy to inflate the price of natural gas and to monopolize certain markets in violation of federal antitrust laws. The Gas Serv. Co. v. Amoco Prod. Co., No. 84-0999-CV-W-0 (W.D.Mo.) (subsequently transferred to the District of Kansas and consolidated with other cases as In re Wyoming Tight Sands Antitrust Cases, No. 85-2849 (D.Kan.)). The Commission decided to defer final resolution of whether the partnership “entity” should be disregarded for purposes of resolving the issue of affiliation, until “after the conclusion of the related court proceedings rather than institute a duplicative hearing at the Commission.” The Commission, for the same reasons, deferred addressing the Title VI fraud and abuse allegations, because those allegations were grounded solely in charges of affiliate self-dealing.

The Commission denied all requests for rehearing but granted a clarification of its original declaratory order. FERC stated that if the district court determined “either directly, or inferentially, by finding common law fraud, or an antitrust conspiracy,” that CSG was actually a co-equal general partner with Amoco in the Partnerships, then the affiliated entities test would apply to CSG’s share of the proceeds. The Commission stated that it could still find that the contracting parties met the test if the price paid for the gas was not higher than the price established by nonaffiliated parties. If, however, the price was excessive, the Commission concluded that it could require refunds of CSG’s share of the partnership proceeds. The Commission further stated that whatever share of the proceeds Amoco took in its own right, whether individually or as a general partner in the Partnerships, would not be subject to reassessment. The Commission held that only if Amoco were held by a court to be a limited partner and CSG the only general partner would the entire partnership proceeds be subject to application of the affiliated entities test. See Order Denying Rehearing and Granting Clarification at 18 (Feb. 28, 1986).

II. The Jurisdictional Challenge

Amoco/CSG challenge this court’s jurisdiction to review the Commission’s determination that the producers’ gas qualified for § 107(c)(5) incentive pricing. Amoco/CSG rely primarily on our recent decision in Williston Basin Interstate Pipeline Co. v. FERC, 816 F.2d 777 (D.C.Cir.1987). We conclude, however, that Wil liston Basin does not control this case. Williston Basin involved the issue of whether specific natural gas reserves were properly designated as tight formation gas. Under NGPA § 503, 15 U.S.C. § 3413, a state or federal “jurisdictional agency” is to make the initial determination of this issue, and FERC is authorized to review the local agency’s determination. Section 503 further provides for limited judicial review of that FERC determination. Willi-ston Basin held that such judicial review is available only if FERC reverses rather than upholds the local agency’s determination that the gas is of the sort that qualifies for incentive pricing. See id. at 780; see also Mesa Petroleum Co. v. FERC, 688 F.2d 1014, 1015-16 (5th Cir.1982).

This case does not involve § 503 judicial review of any determination as to the propriety of a designation of tight formation gas. The issue here is not whether the Wyoming Commission properly designated the producers’ reserves as tight formation gas: no one contests that designation. Rather, the issue is whether the parties satisfied the additional and distinct requirement for special incentive prices, imposed by Order No. 99, of a negotiated contract price. “[Ajseertainment of compliance with [the negotiated contract price] requirement was not delegated to the jurisdictional agencies.” Pennzoil, 671 F.2d at 125 n. 15. Pursuant to Order No. 99, the Commission is to make an independent determination, in the first instance, of whether the parties satisfied the negotiated contract price requirement. Therefore, § 503, which governs administrative and judicial review of local agency determinations, does not apply here.

III. The Negotiated Contract Price Requirement

A. The Need for a Case-Specific Economic Justification

It is undisputed that the 1981 contract amendments in this case incorporate by reference the negotiated contract price language required by Order No. 99. The Commission claims that, assuming arm’s-length bargaining, any price established by a contract that specifically refers to this language is, by definition, a negotiated contract price. Midwest argues, however, that the Commission erred by failing to look beyond the semantics of a negotiated contract price clause in the contract amendments to determine the economic motives of the parties who agreed to insert the clause. Had the Commission done so, Midwest claims, it would have found that the incentive prices paid by Pipeline did not satisfy NGPA § 107’s mandate that incentive prices be “necessary” to create “reasonable incentives.” When the contract amendments were executed, the Partnerships had already completed the best part of their drilling; moreover, the Partnerships, under the original Principles, were already bound “to maintain the highest rate of production of gas ... consistent with good operating practice.” In response, FERC argues: (1) the higher prices need only enhance production and not necessarily drilling of gas; and (2) § 107 prices need not be cost-justified on a case-by-case basis.

In reviewing FERC’s construction of the negotiated contract price requirement, we start with the language of § 107, the statutory provision under which the negotiated contract requirement was promulgated. See Consumer Product Safety Comm’n v. GTE Sylvania, Inc., 447 U.S. 102, 108, 100 S.Ct. 2051, 2056, 64 L.Ed.2d 766 (1980). Section 107 of the NGPA is entitled “Ceiling Price for High-Cost Gas” and provides that the Commission may, by rule or order, prescribe special maximum prices for high-cost gas, which exceed the otherwise applicable maximum prices “to the extent necessary to create reasonable incentives to increase production.” 15 U.S.C. § 3317(b).

Section 107 speaks only in terms of enhancing “production” and not “drilling.” We therefore reject Midwest’s contention that because little drilling was done after the 1981 amendments were executed, the Commission could not reasonably have found that the higher prices in the amendments were “necessary” to elicit production. In the proceedings below, the Commission found that the incentive prices established in the contract amendments permitted continued funding of operation and maintenance expenses for wells already drilled. If the higher prices were in fact necessary to create reasonable incentives to extend the productive life of the wells— as Pipeline contends — then the Commission could properly conclude, again assuming arm’s-length bargaining, that the higher prices in the 1981 amendments were permissible under NGPA § 107.

We also conclude that the Commission acted within its authority in ruling that § 107 incentive prices do not require case-by-case economic justification. It is true that the words “necessary” and “reasonable” in § 107 reveal Congress’ concern that special incentive prices be grounded in some economic basis. However, Congress in § 107(b) explicitly gave the Commission the authority to establish the incentive prices “by rule or order” rather than by individualized adjudication, indicating that Congress did not intend to require FERC to inquire into the economic justification for special incentive prices on a case-by-case basis. The legislative history of § 107 confirms this: the NGPA Conference Report states that the § 107 “special ceiling prices are not intended by the conferees to be cost-based in nature, and do not require cost justification.” S.Rep. No. 1126, 95th Cong., 2d Sess. 88 (1978).

To say that FERC need not inquire into cost justification on a case-by-case basis, however, does not mean that FERC can avoid all individualized analysis. Congress cannot have intended the Commission to turn a blind eye to specific circumstances, such as those in this case, which suggest that the sellers were in a position to charge above-market prices that were not in fact necessary to elicit production of high-cost gas. On the issue of whether arm’s-length bargaining occurred, case-by-case inquiry will in certain circumstances be inevitable. Accordingly, we turn now to the core issue of whether FERC properly determined that the incentive prices “negotiated” by Pipeline and the Partnerships were the result of an arm’s length bargaining process.

B. FERC’s Arm’s-Length Bargaining Test Contravenes the Purpose of the NGPA

The purpose of federal gas regulation has always been “to protect consumers against exploitation at the hands of natural gas companies.” FPC v. Hope Natural Gas Co., 320 U.S. 591, 610, 64 S.Ct. 281, 291, 88 L.Ed. 333 (1944). Although the NGPA, enacted in 1978, dramatically altered the pricing method of natural gas in the United States, its aim is still to ensure adequate supplies of gas at fair prices. See Transcontinental Gas, 106 S.Ct. at 716. Accordingly, with a view to protecting consumers, Congress in §§ 101-123 of the NGPA set ceiling prices for “first sales” of numerous categories of natural gas. 15 U.S.C. §§ 3311-3333. To ensure that market forces operate effectively even within the price ranges it defined, Congress established the affiliated entities limitation, NGPA § 601(b)(1)(E), which prevents pipelines that are affiliated with a producer from passing through to customers first sale prices that “exceed the amount paid in comparable first sales between [nonaffili-ates].” 15 U.S.C. § 3431(b)(1)(E). Congress also, in NGPA § 601(c)(2), prohibited pipelines from passing through to customers prices they have paid producers that are “excessive due to fraud, abuse, or similar grounds.” 15 U.S.C. § 3431(c)(2). It was apparently Congress’ judgment that first sale prices bargained for between producers and pipelines that fell below the explicit ceilings in §§ 101-123 would sufficiently protect customers if the affiliated entities and fraud/abuse limitations were met.

In § 107 of the NGPA, however, Congress enacted a special pricing provision for natural gas recoverable only at particularly high cost: in order to encourage production of such high-cost gas, it gave FERC the authority to prescribe special incentive prices that transcended the maximum prices for other first sales. But to prevent NGPA § 107 from becoming a loophole for natural gas companies, Congress specifically provided that the Commission may only prescribe incentive prices that exceed the otherwise applicable maximum prices “to the extent necessary to create reasonable incentives” to produce high-cost gas.

In accordance with § 107’s statutory mandate, the Commission in Order No. 99 promulgated regulations creating an incentive pricing scheme for high-cost gas produced from tight formations. The regulations provide in pertinent part:

The maximum lawful price, per MMBtu, for the first sale of tight formation gas for which there is a negotiated contract price or a pipeline production price shall be the lesser of:
(1) the negotiated contract price or the pipeline production price, as applicable; or
(2) 200 percent of the maximum lawful price specified [in NGPA section 103(b)(1)].

18 C.F.R. § 271.703. In addition, the Commission in Order 99 established the negotiated contract price requirement. FERC made clear that in order to satisfy that requirement, parties to a gas purchase contract must have bargained at arm’s-length; the stated purpose of the negotiated contract price requirement is:

to insure that a purchaser is given an opportunity to bargain for increased production of tight formation gas before he agrees to pay a price higher than the otherwise applicable maximum lawful price.

Order No. 99 (Final Rule), 45 Fed.Reg. 56,034, 56,041 (Aug. 22, 1980) (emphasis added). The Commission now contends that the affiliated entities test — set out in the statute to determine whether ordinary first sale prices paid by pipelines that are affiliated with a producer are in conformity with comparable first sale prices paid by nonaffiliates — is sufficient to ensure that arm’s-length bargaining has taken place in the present case. We disagree.

Although Congress determined that the affiliated entities test was a sufficient impediment to the passthrough of excessive prices stemming from self-dealing in the case of first sales of § 102 and § 103 new gas, that does not mean that the same test is adequate to ensure that arm’s-length bargaining occurs in the context of § 107 tight formation gas. For one thing, in § 102 and § 103 first sales, Congress itself set criteria both for what kind of gas is eligible for pricing under that section and the upper limits on what prices the parties may bargain for. The possibilities for consumer abuse stemming from self-dealing are thus limited. In the case of § 107(a)(5) gas, however, Congress left it entirely to FERC to determine both the qualifications for eligibility and the prices that could be charged. But it also mandated that these above-ceiling prices for § 107 high-cost gas must only be allowed where “necessary to create reasonable incentives” for increasing production. Thus, FERC was specifically tasked with setting criteria and prices for high-cost gas that would motivate production but not allow exploitation of consumers. It is in that context that its selection of the affiliated entities test as an adequate protection against consumer exploitation must be evaluated.

Having stated our reasons for concluding that the affiliated entities test, although sufficient to protect consumers in the context of passthrough, may not be adequate to ensure that § 107 high-cost sale prices are really “necessary” to create reasonable incentives, we turn now to the particular shortcoming of the Commission’s analysis of the arm’s-length bargaining issue in the proceedings below. We find the Commission’s analysis to be too formalistic to satisfy the goal of protecting consumers from self-dealing. First, the Commission made the affiliated entities limitation on ordinary first sales the exclusive test for whether negotiated contract prices actually reflect arm’s-length bargaining. The Commission asserted that it did not have to deal separately with the fraud and abuse provisions of Title VI in this case, because “the allegations of fraud and abuse are all premised on accusations of self-dealing,” and a prerequisite to a finding of self-dealing is that the affiliated entities test is satisfied. Then, the Commission found that while it was “an extremely close question,” the Partnerships here were not affiliated within the definition of § 2(27) with Pipeline. Focusing on “the concept of the partnership as an entity,” the Commission reasoned that the general partner Amoco had control over most of the Partnerships’ critical decisions and that CSG merely contributed funds to the Partnerships in exchange for a share of the profits. Therefore, because the contract price had been negotiated between an entity controlled by Amoco, on the one hand, and Pipeline, which was controlled by Cities Service, on the other hand, the buyer and seller were not “affiliated entities.” Thus, the Commission, in two quick steps, concluded that Pipeline and the sellers had bargained at arm’s-length, without making any inquiry into the independence or peculiar interests of the parties involved.

In sum, we conclude that the Commission’s test for arm’s-length bargaining in this case is inconsistent with the consumer-protective purposes of the NGPA as well as the specific mandate of NGPA § 107: FERC’s test fails to deal with transactions between technically nonaffiliated parties that nevertheless defy market forces and that could permit natural gas companies to charge exploitative prices.

Specifically, we believe that the focus of the Commission’s test for arm’s-length bargaining was misplaced. By relying solely on the common control test of the affiliated entities limitation — as defined in § 2(27) — as its test for arm’s-length bargaining, FERC effectively reduced the entire issue of whether the 1981 contract amendments satisfied the negotiated price requirement to one formalistic (and somewhat metaphysical) question: whether the Partnerships as “entities” controlled, were controlled by, or under common control with Pipeline. The Commission’s inquiry thus artificially reduced itself to the single issue of whether Amoco, the general partner, or CSG, the limited partner, had the greater “control” over the Partnerships.

The answer to that question, however, cannot be determinative of the existence of arm’s-length bargaining in this case. It is obvious that the interests of all the parties in the Partnerships coalesced here; whether the seller was Amoco, CSG or the Partnerships makes little difference: each would gain by charging Pipeline the higher “incentive” price. Under those circumstances, the competitive interests of the various sellers in the Partnership cannot be decisive in a decision as to whether arm’s-length bargaining occurred. Rather, in considering whether the extremely high price increases established in the contract amendments were actually dictated by market forces, the Commission should have directed its inquiries into the motivations of, and alliances between, the sellers and the buyer that would have determined whether an arm’s-length negotiation took place. As the buyer of the gas, Pipeline would ordinarily be expected to resist payment of prices that were not "necessary” to obtain the gas. If, however, the economic interests of Pipeline itself coincided with the sellers’ interests in getting the highest price possible for the gas, then arm’s-length bargaining could not have occurred in any meaningful sense. The Commission refused to consider any such information as relevant to its determination whether a true negotiated price contract had taken place.

The Commission’s formalistic approach to arm’s-length bargaining prevented it from looking beyond the form and the ownership of the “entities” involved in the sales to the “significant and determinative economic fact[s],” United Gas Improvement Co. v. Continental Oil Co., 381 U.S. 392, 400-01, 85 S.Ct. 1517, 1522, 14 L.Ed.2d 466 (1965). Thus, FERC never synthesized the facts that Pipeline and CSG were owned and controlled by the same parent; that the person who “negotiated” and signed the 1981 amendments for Pipeline was simultaneously a Vice-President of CSG; that CSG under the Partnership agreement was entitled initially to 80% (subsequently to be reduced to between 5% and 25%) of the proceeds resulting from the higher prices paid by Pipeline; and that, if no affiliation was found, nothing prevented Pipeline from passing on to its customers the entirety of the incentive price increase. In short, by focusing on the technical definition of affiliation in the statute, a definition designed for another purpose, the Commission never confronted the clear implication of the totality of facts in this case: that Pipeline’s owner stood to benefit directly from the higher prices charged Pipeline, and that Pipeline’s disincentives to pay whatever prices the Partnership asked were slim indeed.

An arm’s-length bargaining test that allows technically nonaffiliated entities to escape market controls contravenes the stated purpose of the negotiated contract price requirement, which is:

[to] insure that the incentive maximum lawful price is extended as an incentive for the production of additional tight formation gas rather than as a windfall to the sellers.

We note that the Commission has in analogous contexts recognized that transactions between nonaffiliated entities may still be structured in such a way that distorts market forces. For example, in Colorado Oil & Gas Conservation Comm’n, 26 F.E.R.C. ¶ 61,267 (1984) (vacating its prior determination that certain gas qualified as “production enhancement gas” for incentive pricing), the Commission ruled that the arm’s-length bargaining requirement was not satisfied in “a situation in which the purchaser would have every economic incentive to pay the highest price allowable rather than to bargain for the lowest possible price at which the producer/seller would perform the enhancement work.” Id. at ¶ 61,616.

We conclude, therefore, that given the particular economic relationships and incentives in this case militating against arm’s-length bargaining, there could be no reasonable assurance that the prices “negotiated” by Pipeline and the Partnerships would reflect only market forces. Acknowledging, however, that it is not the role of the reviewing court to prescribe the particular test the Commission should use to determine whether arm’s-length bargaining occurred, we reverse and remand to the Commission to redefine the specific elements and parameters of the arm’s-length bargaining requirement in this case. In light of the consumer-protective goals of federal gas regulation in general, and of NGPA § 107’s specific mandate that special incentive prices be “necessary” to elicit production, a reasonable test for arm’s-length bargaining must be broad enough to take into account the special features of transactions like the one here, which, although they involve technically nonaffiliat-ed parties, nonetheless have the potential to distort market forces and permit the exploitation of consumers in contravention of the declared purposes of the NGPA.

C. The Retroactive Applicability of § 107(c)(5) Prices

The 1981 amendments provide that the collection of the § 107(c)(5) price shall be retroactive to July 16, 1979, the date the Commission established as the initial date for the collection of the incentive price for tight formation gas. 18 C.F.R. § 273.204(a)(l)(ii). Midwest contends that the Commission’s decision to uphold the retroactive effectiveness of the parties' negotiated contract price was improper on two basic grounds: (1) retroactive application of the § 107 incentive price violates § 107’s explicit requirement of “necessity”; and (2) the filed rate doctrine set forth in NGA § 4 bars retroactive price increases in this case. We reject Midwest’s first contention and remand to FERC the issue of whether the filed rate doctrine prohibits the retroactive application of § 107(c)(5) prices.

Midwest’s first contention is that retroactive application of the § 107(c)(5) incentive price would violate § 107’s explicit requirement that special incentive prices be available only to the extent “necessary to provide reasonable incentives.” Midwest argues that a higher price cannot be an incentive to obtain gas that already has been produced and sold. We believe that although Midwest’s argument may be logically attractive, it is inapplicable to the present situation. Midwest fails to realize that in considering whether a particular factor — such as a higher price — might have served as a “reasonable incentive” for the producers in this case to increase production, the relevant time period is 1979, when the parties actually sat down at the bargaining table and negotiated the gas purchase contracts. At that time, one of the various risks and benefits considered and allocated might well have been the possibility that FERC would allow a higher price for tight formation gas. (This was a very real possibility, given that President Carter had recommended to Congress that incentive prices be established for the development of tight formation gas.) This possibility of a higher incentive price could certainly have served as part of the reasonable incentive that induced the producers to enter into agreements that would require them to continue producing tight formation gas.

Midwest’s second contention is that the filed rate doctrine bars retroactive price increases for natural gas, such as § 107(c)(5) gas, that is subject to the Commission’s NGA jurisdiction. The Commission’s position is that because NGPA § 107(c)(5) tight formation gas also qualifies under § 102 and § 103 of the NGPA as new natural gas, such volumes were removed from FERC’s jurisdiction pursuant to NGPA § 601(a)(1)(B). We believe that the wording and legislative history of § 601(a)(1)(B) as well as the substance and purpose of § 107(c)(5) point to one conclusion: that § 107(c)(5) high-cost natural gas remains subject to NGA jurisdiction.

The issue of whether NGPA § 107(c)(5) gas has been deregulated from the NGA is one of first impression. We start our review with the language of the statute itself. Section 107 itself does not address the precise issue of whether high-cost natural gas prices may be effective retroactively. However, the explicit wording of other relevant provisions of the NGPA indicates that Congress did not intend to exclude § 107(c)(5) natural gas from the Commission’s NGA jurisdiction. Section 601(a)(1)(B) of the NGPA removes from NGA jurisdiction committed or dedicated natural gas that is “high-cost natural gas (as defined in section 3317 [§ 107] (c)(1), (2), (3), or (4) of this title).” Congress did not in § 601(a)(1)(B) explicitly remove from FERC’s jurisdiction natural gas sold as § 107(c)(5) gas; § 107(c)(5) gas was not identified as one of the specific categories of § 107(c) high-cost gas that would be NGA-deregulated. Moreover, we believe that in enacting the NGPA’s comprehensive scheme for natural gas pricing and regulation, Congress was well aware that certain gas might qualify for more than one category. We find it significant that Congress did not expressly specify that for gas qualifying under more than one provision of the NGPA, one section of the statute would control for purposes of deregulation even if another section of the NGPA controlled the pricing of the gas.

The legislative history of § 601(a)(1)(B) confirms that Congress intended § 107(c)(5) gas to remain subject to FERC’s NGA jurisdiction. Then-Chairman of FERC Charles Curtis stated in a letter to Senator H.M. Jackson, which was presented at the Senate hearings on NGA deregulation, that “Natural Gas Act jurisdiction would be retained over categories of gas, persons, and facilities not specifically exempted,....” Letter from Commission Chairman Charles Curtis to Senator H.M. Jackson, 126 Cong. Rec. H13127 (Sept. 8, 1978), reprinted in 8 Natural Gas Policy Act Information Service 11601.220, p. 3 (1979) (emphasis added). In 1982 the Commission itself acknowledged Congress’ intent to keep § 107(c)(5) gas NGA-regulated when it corrected an administrative law judge as follows:

We observe that the judge stated in the body of the order that gas that falls under section 107(c)(5) of the NGPA is removed from Commission jurisdiction. We note that NGPA section 601(a)(l)(B)(i) removes from our jurisdiction only gas that falls under paragraphs (l)-(4) of section 107(c).

Northern Natural Gas Co., 20 F.E.R.C. ¶ 61,329 at 61, 683 (1982).

The substance and purpose of NGPA § 107(c)(5) corroborates what the wording and legislative background of NGPA § 601(a)(1)(B) suggest. Section 107(c)(5) creates a category of high-cost natural gas that is very different from the natural gas falling into the § 107(c)(l)-(4) categories. In § 107(c)(l)-(4) Congress specifically identified four technical categories of high-cost gas — gas produced at a depth of over 15,000 feet, gas produced from geopres-sured brine, occluded natural gas produced from coal seams, and gas produced from Devonian shale — which would qualify for § 107 incentive prices. By contrast, § 107(c)(5) creates a special undefined category of high-cost gas that leaves it to the Commission, in its discretion, to determine whether certain gas qualifies for special incentive pricing; § 107(c)(5) gas is defined as gas “produced under such other conditions as the Commission determines to present extraordinary risks or costs.” We believe that the fact that § 107(c)(5) gas creates a category of gas fundamentally different from the other categories of § 107 high cost gas, coupled with the omission of § 107(e)(5) gas from § 601(a)(l)(B)’s deregulation provision and § 601(a)(l)(B)’s legislative history, indicate that Congress intended the Commission to have continuing NGA jurisdiction over § 107(c)(5) gas.

Thus, if § 107(c)(5) and § 601(a)(1)(B) were the only provisions we had to apply, we would hold that even if the parties had satisfied the negotiated contract price requirement, § 107(c)(5) gas could not be subject to retroactive prices. However, NGPA § 4(d) provides that FERC may “for good cause shown” waive the usual filing requirements for an alteration in rate. 15 U.S.C. § 717c(d). This court and others have allowed § 4(d) waiver by the Commission when (1) the parties agreed to the collection of a higher rate than the one on file, and (2) the waiver was in the public interest. See City of Girard, Kansas v. FERC, 790 F.2d 919, 923-25 (D.C.Cir.1986); Hall v. FERC, 691 F.2d 1184, 1191-92 (5th Cir.1982); City of Piqua v. FERC, 610 F.2d 950, 954-55 (D.C.Cir.1979) (decided under the comparable waiver provisions of the Federal Power Act). It is, however, not clear whether waiver of the filed rate doctrine is appropriate in this case. Our limited precedent involves the situation where the parties agreed to the rate change before it was to go into effect — that is, where the rate change was prospective from the date of the agreement. See City of Piqua, 610 F.2d 950. By contrast, the parties here contracted in March 1981 for an increase to be effective retroactively to July 1979, for gas already sold and delivered under lower contract price provisions. Since, however, we are remanding the case to the Commission on other grounds, we will permit it an opportunity to rule on whether a waiver of the filed rate doctrine is appropriate in the public interest in this case as well.

D. The Status of FERC’s Title I Determination

At oral argument, we perceived some confusion over whether a remand by this court of the Commission’s Title I findings would be inconsistent with a previous ruling by this court that FERC’s Title I determinations were final. On November 7, 1986, a panel of this court considered a motion, filed by Pipeline, requesting that the court refrain from reviewing FERC’s Title I determination. See Pipeline’s Motion to Dismiss, in Part, or to Alternatively Limit the Issues, and the Responses and Reply Thereto (May 21, 1986). Pipeline argued that because the Commission had left the Title I issue open to reconsideration pending the district court antitrust proceedings, FERC had not rendered a final decision, and therefore there was no final agency action under § 10(c) of the APA, 5 U.S. C. § 704 for this court to review. This court found that the Commission’s Title I determination clearly met the standard for final agency action. Stating that there was “not the slightest support for [FERC’s] strained contention,” we denied Pipeline’s motion.

At oral argument, both counsel for Midwest and counsel for FERC expressed concern that a holding by this court that would require the Commission to revisit its Title I determinations would be inconsistent with our previous ruling that the Commission’s determination constituted final agency action. We believe that such concern is unwarranted. Our earlier ruling on Pipeline’s motion to dismiss was not a ruling on the merits: we did not in that proceeding address the actual substance of any of Midwest's Title I claims. Rather, our holding on the motion meant only that FERC’s determination constituted final agency action for purposes of judicial review under the APA despite the Commission’s stated willingness to reconsider its Title I determinations under certain circumstances, at the end of the antitrust proceedings. We perceive no inconsistency whatsoever between that ruling and our present holding, on the merits, that FERC must reconsider its Title I determination that Pipeline and the Partnerships had negotiated at arm’s-length and that the Partnerships were entitled to collect the § 107 special incentive price.

IV. The Commission’s Deferral of the Title VI Issues

In the proceedings below, the Commission found that there was no affiliate relationship between Pipeline and the Partnerships that would indicate an absence of arm’s-length bargaining and render the price negotiated by the parties ineffective. With respect to the Title VI issues of improper affiliation, FERC stated:

The ongoing related court proceedings would appear to provide a suitable forum for determining whether common law fraud or other improprieties existed so as to justify considering the partnership entities as affiliated with the pipeline. Accordingly, we reserve the right to reassess the issue of whether the partnership “entity” should be disregarded after the conclusion of the related court proceedings rather than institute a duplicative hearing at the Commission at this time.

The Commission similarly declined to address the Title VI fraud/abuse issues “since [those] too are grounded in allegations of partnership ‘affiliate’ self-dealing.” In support of its deferral, the Commission claims that it is “entitled to the highest deference in deciding priorities among issues” and matters concerning its own calendar. Associated Gas Distributors v. FERC, 824 F.2d 981, 1039 (D.C.Cir.1987). In this case, the Commission claims, it was well within its discretion to defer final resolution of the Title VI issues in order to avoid “an extensive evidentiary hearing which might be duplicative of the court proceeding.”

Midwest and Pipeline, however, raise a number of objections to FERC’s decision to defer final resolution of the Title VI fraud and self-dealing issues. Midwest’s basic contention is that the pending federal litigation involves Sherman Act and Clayton Act claims and not claims grounded in the NGPA or NGA; Midwest argues that it was unreasonable for the Commission to make the final resolution of the Title VI issues, and the possible reopening of Title I issues, contingent upon a distantly-related antitrust case. Midwest’s claim that the deferred-to proceeding involves a number of different parties as well as antitrust and fraud issues is not by itself conclusive; the transactions out of which the district court litigation arose are essentially the same as those at issue here. This being the case, we believe the Commission could, in certain circumstances, reasonably have determined that additional proceedings by the Commission would have resulted in “an unneeded allocation of agency resources.” Order Denying Rehearing at 17 n. 57.

Pipeline further contends that the Commission’s deferral to the district court is arbitrary, because the legal and factual issues in this case are within FERC's exclusive jurisdiction and thus for the Commission and not courts to decide. The Commission, in response, states only that in issuing its declaratory order, it had “already exercised its primary jurisdiction on matters within its special expertise.” Id. at 17. In determining whether FERC has exclusive jurisdiction over the Title VI issues in this case, we look to the relevant provisions in the NGPA. Section 601(c)(2) is the statutory basis for Midwest’s Title VI claims of fraud and self-dealing. That section provides that passthrough of costs is lawful “except to the extent the Commission determines that the amount paid was excessive due to fraud, abuse, or similar grounds” (emphasis added). Similarly, the legislative history of § 601(c)(2) indicates that “[t]he conferees [did] not intend to guarantee passthrough of costs of natural gas purchases in cases of fraud or abuse as determined by the Commission.” H.Rep. No. 1752, 95th Cong., 2nd Sess., p. 124 (1978) (joint explanatory statement of conferees) (emphasis added).

Based on the wording and legislative history of § 601(c)(2), we cannot go so far as to say that Congress intended FERC to have exclusive jurisdiction over the determination of the facts necessary to decide the Title VI issues in this case. In spite of the wording and legislative background of § 601(c)(2), it is not clear to us that Congress meant to insist that no one but the Commission should be allowed to find these facts initially. The Commission here would merely use facts found elsewhere to determine whether Title Vi’s prohibition applied.

In addition, Pipeline and Midwest contend that the Commission’s deferral to the district court would lead to unreasonable delay in the resolution of this case. In evaluating whether agency delay constitutes an abuse of discretion, this court has applied a “rule of reason” analysis. See Telecommunication Research & Action Center v. FCC, 750 F.2d 70, 80 (D.C.Cir.1984). Although the issue of whether delay is unreasonable necessarily turns on the facts of each particular case, this court has stated generally that a reasonable time for an agency decision could encompass “months, occasionally a year or two, but not several years or a decade.” MCI Telecommunications Corp. v. FCC, 627 F.2d 322, 340 (D.C.Cir.1980).

In the present case, four years have elapsed since Midwest filed its amended complaint in November 1983. Furthermore, if we uphold the Commission’s decision to defer, final resolution of the fraud and self-dealing issues is still nowhere in sight. The district court proceeding is currently in an early stage of discovery; the litigation, including appeals, may not be completed for a number of years. In addition, even if, under the Commission’s scenario, the district court ultimately finds that CSG was actually a co-equal partner with Amoco in the Partnerships, then the Commission would still have to apply the affiliated entities test to determine if the price Pipeline paid for the gas was higher than the market price established by nonaf-filiated parties. See Order Denying Rehearing at 18. In sum, if FERC is allowed to defer reconsideration until the district court completes its work, it is possible that the fraud and self-dealing issues raised by Midwest’s complaint will not be finally settled for several years to come. Given that Pipeline continues to purchase § 107 high-cost gas from the Partnerships and to pass the higher costs through to its customers, we suspect that the Commission’s deferral would result in delay of the sort that “saps the public confidence in an agency’s ability to discharge its responsibilities and creates uncertainty for the parties.” Potomac Electric Power Co. v. ICC, 702 F.2d 1026, 1034 (D.C.Cir.1983). This substantial likelihood of indefinite delay bolsters our conclusion, based on the new identity of Title I and Title VI issues which we discuss below, that the Commission should reconsider its deferral position.

Under the new Title I test for arm’s-length bargaining that we have instructed the Commission to formulate, transactions involving collusion or other distortion of market forces will no longer be excluded from consideration by FERC. Thus, the Title I test for a negotiated contract price will likely be virtually coextensive with the Title VI test for fraud/abuse and improper affiliation. Under this kind of broadened test for Title I arm’s-length bargaining, it is hard to see why the Commission would want to decide the Title I and Title VI issues separately. In these circumstances, we think the better course is to remand for the Commission to reconsider its decision to defer resolution of the Title YI issues in light of the new Title I test for arm’s-length bargaining.

Having decided that (1) the Commission evaluated Midwest’s Title I issue of whether there was a true negotiated contract price on the basis of an improper test for arm’s-length bargaining and (2) the Commission’s decision to defer resolution of the Title VI fraud and self-dealing issues until after completion of the district court proceedings should be reconsidered, we remand both the Title I and Title VI issues for reevaluation by FERC.

V. FERC’s Decision to Leave Open the Issue of CSG’s Liability

In the proceedings below, FERC concluded that if the district court considering the antitrust litigation finds that the 1981 amendments resulted from fraud or self-dealing, the Commission would apply the affiliated entities test to the transactions between Pipeline and the Partnerships. Under that test — as set forth in NGPA § 601(b)(1)(E) — the Commission would have to determine whether the amount paid in the first sale to Pipeline “exceeded the amount paid in comparable first sales between persons not affiliated with such interstate pipeline.” The Commission held that if it were ultimately found that the 1981 amendments did not meet the affiliated entities test, refunds could be ordered which would include CSG’s share of the proceeds. CSG, however, claims that the refund provisions of Title VI apply only to pipelines and their customers and that CSG, a producer of natural gas, could not be subjected to refunds based on the affiliated entities test. Accordingly, CSG argues that it was an abuse of discretion for the Commission to leave open the possibility that it may in the future require the refund of CSG’s share of the Partnerships’ profits. In response, FERC and Midwest raise procedural arguments. They assert that there is no basis for judicial review of CSG’s refund liability under Title VI at this stage, because CSG is not yet “aggrieved” by the Commission’s decision to impose a contingent liability upon CSG.

In light of the particular facts and procedural posture of this case, we believe that the issue of CSG’s refund liability is not ripe for judicial review.

As we have previously stated:
[T]he primary focus of the ripeness doctrine as it concerns judicial review of agency action has been a prudential attempt to time review in a way that balances the petitioner’s interest in prompt consideration of allegedly unlawful agency action against the agency's interest in crystallizing its policy before that policy is subjected to judicial review and the court’s interests in avoiding unnecessary adjudication and in deciding issues in a concrete setting.

Eagle-Picher Industries, Inc. v. EPA, 769 F.2d 905, 915 (D.C.Cir.1985). Here, CSG’s interest in prompt consideration of its potential refund liability is very low. Because the Commission stopped not one but several steps short of ordering refunds from CSG, no immediate response to FERC’s imposition of contingent refund liability is required of CSG. Nor would any “irremediable adverse consequences flow” from deferring judicial review until refunds have specifically been ordered by the Commission and refused by CSG. Abbott Laboratories v. Gardner, 387 U.S. 136, 87 S.Ct. 1507, 18 L.Ed.2d 681 (1967). On the other hand, FERC has a significant interest in being able to “crystallize” its policy on the applicability of Title Vi’s affiliated entities test to former producer affiliates before that policy is subjected to judicial review. At this point, the Commission is not inescapably bound by the statement in its declaratory order that it could impose refund liability upon CSG in the event that improper affiliation is found. Rather, the Commission’s ultimate decision down the line as to the legality, the appropriateness and the dimensions of CSG’s refund liability may well turn on several determinations FERC has yet to make: (1) whether the 1981 amendments were the product of self-dealing between Pipeline and the Partnerships rather than arm’s-length bargaining; (2) whether the higher prices in the 1981 amendments exceed those paid by nonaffili-ated parties and therefore do not meet the affiliated entities test; and (3) whether a refund obligation may be imposed on CSG, although it is a producer and not a pipeline.

We therefore refrain from ruling on the issue of CSG’s liability until after FERC decides the issue of self-dealing and until it has actually required CSG to refund its share of the partnership proceeds. At that juncture, CSG will have ample opportunity to seek judicial review of the Commission’s determination.

Conclusion

We agree with the Commission that NGPA Title I special incentive prices do not require case-by-case cost justification. In the context of tight formation gas, however, FERC effectively chose the market, embodied in the negotiated contract price requirement, as its principal device for ensuring that, in accordance with NGPA § 107’s explicit mandate, incentive prices are permitted only when necessary to elicit high-cost gas production. By relying on an arm’s-length bargaining standard that turns on technical corporate affiliation, the Commission has in this case reduced the negotiated contract price requirement to an empty formalism. Therefore, we reverse FERC’s interpretation of the negotiated contract price requirement and remand for reformulation of the arm’s-length bargaining test. We also remand the issue of whether § 107(c)(5) prices may be given retroactive effect, for the Commission to determine whether good cause justified waiver of the filed rate doctrine. On remand, the Commission will also be required to reconsider its decision to defer the Title VI issues of fraud and self-dealing, in light of the broader test for arm’s-length bargaining that we are instructing it to formulate.

So ordered. 
      
      . A "tight formation” is a sedimentary layer of rock cemented together in a manner that greatly hinders the flow of any gas through the rock. Because such a formation is characterized by low permeability, wells drilled into gas-bearing formations of this kind usually produce at very low rates. To stimulate production from these formations, producers must use expensive enhanced recovery techniques. See Order No. 99, "Regulations Covering High-Cost Natural Gas Produced From Tight Formations,” 45 Fed.Reg. 56,034 (Aug. 22, 1980), FERC Stats, and Regs. [Reg. Preambles 1977-1981] ¶ 30,183.
     
      
      . In its rule, the Commission defined "tight formation gas” as natural gas that had been determined to be either “new tight formation gas” or "recompletion tight formation gas.” 18 C.F.R. § 271.703(b). New tight formation gas included: (1) new natural gas, which under NGPA § 102(c) had to be produced in commercial quantities before April 20,1977; (2) certain Outer Continental Shelf gas, which under NGPA § 102(d) had to be produced from a reservoir discovered after July 27, 1976; or (3) gas produced through a new onshore production well, which under NGPA § 103(c) could not have been subject to surface drilling before February 16, 1979.
     
      
      . Pipeline was at that time named Cities Service Gas Company and was a subsidiary of Cities Service Company. In November 1982, Cities Service Company sold Pipeline to Northwest Energy Company and it was renamed Northwest Central Pipeline Corporation. In 1983, Pipeline was acquired by The Williams Companies and is now named Williams Natural Gas Company.
     
      
      . On June 1, 1980, Pipeline transferred 100% of its interest in CSG to its then-parent, Cities Service Company. CSG remained an affiliate of Pipeline until November 12, 1982, when CSG and its parent company were acquired by Occidental Petroleum Corporation. See J.A. at 754.
     
      
      . The Partnership Agreements set forth an “Initial Drilling Program" and an "Additional Drilling Program.” The Initial Drilling Program under the Wamsutter Agreement was divided into three phases and required Amoco to drill a maximum of 32 lease-earning wells under the first phase, 17 lease-earning wells under the second and 14 lease-earning wells under the third. Pipeline’s maximum funding obligations under each of these phases was $32 million, $17 million and $14 million, respectively. The Initial Drilling Program under the Moxa Agreement required Amoco to drill 9 lease-earning wells under phases I and II and 8 such wells under phase III, with CSG's maximum contribution in the first two phases limited to $9 million and $8 million in phase III. The Additional Drilling program was to begin upon completion of the Initial Drilling Program. Under the later program, the funding limitation was $35 million per year under the Wamsutter Agreement and $20 million per year under the Moxa Agreement. See J.A. at 158, 198.
     
      
      . See 4 F.E.R.C. ¶ 16,268 (1978); 5 F.E.R.C. ¶ 61,049 (1978).
     
      
      . The effective maximum price in March 1981 was $2.729 per MMBtu for § 102 natural gas and $4.812 per MMBtu for § 107 tight formation gas. Moreover, all incentive prices established under the NGPA escalate monthly. Thus, in March 1987 the maximum price was $4.497 per MMBtu for § 102 gas and $6.334 per MMBtu for § 107 gas. See 18 C.F.R. § 271.101 (1986).
     
      
      .On January 23, 1983, Midwest had filed a complaint alleging that certain "take-or-pay" liabilities incurred by Pipeline pursuant to its gas purchase agreements with Amoco and the Partnerships were the result of “improvidently and recklessly negotiated contracts." The take-or-pay provisions obligated Pipeline to pay for substantial quantities of gas whether or not Pipeline had a market for that gas. J.A. at 724.
     
      
      . The filed rate doctrine "forbids a regulated entity to charge rates for its service other than those properly filed with the appropriate federal regulatory authority.” Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571, 577, 101 S.Ct. 2925, 2930, 69 L.Ed.2d 856 (1981).
     
      
      . NGPA § 2(27) provides that:
      [t]he term ‘affiliate,’ when used in relation to any person, means another person which controls, is controlled by, or is under common control with, such person. 15 U.S.C. § 3301(27). Section 2(27) defines affiliates for purposes of pipeline passthrough under Title VI. The Title VI affiliated entities limitation allows pipelines to pass on to consumers the extra cost of certain categories of high-price gas unless the pipeline pays a price for gas to its affiliated suppliers that exceeds the amount paid in comparable first sales between unaffiliated parties. See NGPA § 601(b)(1)(E), 15 U.S.C. § 3431(b)(1)(E).
     
      
      . The state or federal agency, however, may waive its authority to make this determination under § 503(c), 15 U.S.C. § 3413(c).
     
      
      . See NGPA § 503(b)(1)(A), 15 U.S.C. § 3413(b)(1)(A).
     
      
      . The only state agency determinations pertinent to this case were accepted by the Commission in August 1980 — six months before the negotiated contract price language was even inserted into the contracts. See FERC Orders No. 109, 110 (Nov. 14, 1980).
     
      
      . A "pipeline production price” is basically a negotiated contract price paid by a pipeline to a producer, which is a part of the same entity. Specifically:
      Pipeline production price means any price which is paid by the transmission divisional unit of a pipeline in a first sale to the production divisional unit of that pipeline and which does not exceed the amount paid in comparable first sales between persons not affiliated with such pipeline.
      18 C.F.R. § 271.702(a)(4).
      Section 103(b)(1) provides:
      (b) Maximum lawful price
      
      (1) General rule
      
      The maximum lawful price under this section for any month shall be—
      (A) ? 1.75 per million Btu’s, in the case of April 1977; and
      (B) in the case of any month thereafter, the maximum lawful price, per million Btu's, prescribed under this paragraph for the preceding month multiplied by the monthly equivalent of the annual inflation adjustment factor applicable for such month.
     
      
      . In the rulemaking proceedings that followed the Supreme Court's decision in Public Service Comm’n v. Mid-Louisiana Gas Co., 463 U.S. 319, 103 S.Ct. 3024, 77 L.Ed.2d 668 (1983), the Commission elaborated on the origins of the negotiated contract price requirement. It stated that in establishing incentive prices for tight formation gas:
      The Commission ... presumed that the parties negotiate a contract for high-cost gas in an arm’s length transaction, and from this presumption came the negotiated contract price requirement. The Commission realizes that the parties involved in an intracorporate transfer are essentially the same and cannot therefore meet the negotiated contract requirement. ...
      
      First Sales of Pipeline Production Under Section 2(21) of the Natural Gas Policy Act of 1978, Notice of Proposed Rulemaking, 49 Fed.Reg. 33,849, 33,854 (1983) (emphasis added). In the Final Rule implementing Mid-Louisiana, the Commission again made plain that an "arm’s-length transaction [is] required to meet the negotiated contract price requirement.” Production Under Section 2(21) of the Natural Gas Policy Act of 1978, 49 Fed.Reg. 33,849, 33,854-33,855 (Aug. 27, 1984) (emphasis added).
     
      
      . That Pipeline’s interests were not independent of the sellers is also suggested by the fact that, when it agreed to the higher prices in the 1981 amendments, Pipeline had more than adequate gas reserves to meet current and future demands: at the time of the amendments, it projected gas surpluses of over 140 billion cubic feet for the next four years. See J.A. at 765.
     
      
      . Colorado Oil did not deal with the negotiated contract price requirement but with the closely analogous "renegotiated price” requirement, which also requires arm's-length bargaining. Pursuant to FERC regulations, "production enhancement gas,” like tight formation gas, is enti-tied to a special incentive price if the underlying contract establishes a renegotiated price.
      In Colorado Oil, the buyer had agreed to a contract amendment to establish a "renegotiated price” which would qualify the production for special incentive ceiling price. However, under the amendment agreement, the buyer would have received, as a "payback,” 50% of the increase. Because the buyer had a direct financial incentive to pay the highest price allowable, the "renegotiated price” was not the result of an arm’s-length transaction and the Commission vacated its prior determination that the gas qualified for incentive pricing.
     
      
      . Of the 38 amended contracts, 28 were between Pipeline and one of the two Partnerships, and 10 were between Pipeline and Amoco as an individual corporation. In the case of the 10 Amoco contracts, the Cities Service group was only on one side of the bargaining table. Because, however, the record does not indicate whether or how intimately the Amoco contracts were related to those between Pipeline and the Partnerships, we leave it to the Commission to decide on remand whether they too suffer from any form of self-dealing or lack of arm's-length bargaining, and therefore similarly fail to satisfy the negotiated contract price requirement.
     
      
      . July 16, 1979 was the date of President Carter's speech to Congress recommending that tight formation gas be eligible for special incentive prices.
     
      
      . Section 601(a)(1)(B) of the NGPA provides:
      Effective beginning on the first day of the first month beginning after November 9, 1978, for purposes of section 1(b) of the Natural Gas Act [15 U.S.C. 717(b) ], the provisions of such Act [15 U.S.C. 717 et seq.] and the jurisdiction of the Commission under such Act shall not apply solely by reason of any first sale of natural gas which is committed or dedicated to interstate commerce as of November 8, 1978, and which is—
      (i) high-cost natural gas (as defined in section 3317(c)(1), (2), (3), or (4) of this title);
      (ii) new natural gas (as defined in section 3312(c) of this title); or
      (iii)natural gas produced from any new, onshore production well (as defined in section 3133(c) of this title.)
      It is quite possible, however, that § 601(a)(1)(B) may not govern some of the tight formation gas at issue. Section 601(a)(1)(A), 15 U.S.C. § 3431 (a)(1)(A), removes from NGA jurisdiction natural gas that was not "committed or dedicated to interstate commerce” on the day before enactment of the NGPA (i.e., November 8, 1978). To the extent that the gas in question is covered by § 601(a)(1)(A) rather than § 601(a)(1)(B), the NGA does not apply, and such gas may be subject to retroactive prices.
     
      
      . The court further ordered, on its own motion, that Pipeline "show cause why sanctions should not be imposed for the filing of the Motion.” The order to show cause was later discharged in a per curiam order dated December 23, 1986.
     
      
      . The Commission’s delay in resolving the Title VI issues may also contravene relevant provisions of the NGA. Before passthrough of higher costs can occur, pipelines, pursuant to NGA § 4(e), must submit a special "purchased gas adjustment” filing biannually, in order to adjust their roles for increases (or decreases) in the cost of gas they purchase from suppliers. In NGA § 4(e), Congress expressly provided that “the Commission shall give to the hearing and decision of such questions preference over other questions pending before it and decide the same as speedily as possible" (emphasis added). 15 U.S.C. § 717c(e). Thus, Congress has directed FERC to decide expeditiously questions like those in this case. The Commission's deferral may well be inconsistent with that congressional directive.
     
      
      . After Cities Service Company sold Pipeline to Northwest Energy Company in 1982, the Wam-sutter and Moxa Partnerships were dissolved effective April 1, 1983. Amoco bought out CSG’s interest in the partnership assets. If the Commission orders the refund of CSG’s share of proceeds, and if Amoco were determined to be the successor to CSG’s interests in the Partnerships, then Amoco would be liable for that share.
     