
    WISCONSIN GAS COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. ANR PIPELINE COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. GREAT LAKES GAS TRANSMISSION COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. TRANSWESTERN PIPELINE COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. MIDWESTERN GAS TRANSMISSION COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. TENNESSEE GAS PIPELINE COMPANY, a DIVISION OF TENNECO INC., Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. CITY GAS COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. MADISON GAS & ELECTRIC COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. WISCONSIN POWER & LIGHT COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. WISCONSIN NATURAL GAS COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. WISCONSIN POWER & LIGHT COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. WISCONSIN PUBLIC SERVICE CORPORATION, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. PANHANDLE EASTERN PIPE LINE COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Gas Utilities Company, et al., Intervenors. TRUNKLINE GAS COMPANY, Petitioner, FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Gas Utilities Company, et al., Intervenors. MIGC, INC., Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. TEXAS EASTERN TRANSMISSION CORPORATION, Petitioner, FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Michigan Consolidated Gas Company, et al., Intervenors. ARKANSAS LOUISIANA GAS COMPANY, a DIVISION OF ARKLA, INC., Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Pan-Alberta Gas Ltd., et al., Intervenors. TRANSCONTINENTAL GAS PIPE LINE CORPORATION, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Pan-Alberta Gas Ltd., et al., Intervenors. ALGONQUIN GAS TRANSMISSION COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Pan-Alberta Gas Ltd., et al., Intervenors. TEXAS GAS TRANSMISSION CORPORATION, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Consumers Power Company, et al., Intervenors. PACIFIC INTERSTATE OFFSHORE COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Consumers Power Company, et al., Intervenors. CASCADE NATURAL GAS CORPORATION, Northwest Natural Gas Company, Washington Natural Gas Company, Petitioners, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Consumers Power Company, et al., Intervenors. ARKANSAS LOUISIANA GAS COMPANY, a DIVISION OF ARKLA, INC., Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Pacific Gas and Electric Company, et al., Intervenors. TRANSWESTERN PIPELINE COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Pan-Alberta Gas Ltd., et al., Intervenors. MIGC, INC., Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent. ARKANSAS LOUISIANA GAS COMPANY, a DIVISION OF ARKLA, INC., Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent.
    Nos. 84-1358 to 84-1360, 84-1364, 84-1407, 84-1408, 84-1413 to 84-1418, 84-1433, 84-1434, 84-1441, 84-1446, 84-1463, 84-1470, 84-1474, 84-1487, 84-1489, 84-1490, 84-1556, 84-1580, 84-1623 and 85-1015.
    United States Court of Appeals, District of Columbia Circuit.
    Argued April 2, 1985.
    Decided August 20, 1985.
    
      Raymond N. Shibley, Washington, D.C., with whom Patrick J. Whittle, Washington, D.C., was on brief, for Panhandle Eastern Pipe Line Co. and Trunkline Gas Co., petitioners in Nos. 84-1433 & 84-1434, and intervenors in Nos. 84-1358 to 84-1360, 84-1364, 84-1407, 84-1408, 84-1413 to 84-1418.
    Platt W. Davis, III, Washington, D.C., for Ark. La. Gas Co., petitioner in Nos. 84-1463, 84-1556, and 85-1015.
    Bruce F. Kiely, Washington, D.C., with whom Catherine C. Wakelyn, was on brief, for Wis. Gas Co., et al., petitioners in Nos. 84-1358, 84-1413 to 84-1418.
    James T. McManus, Washington, D.C., with whom Dale A. Wright, Harold L. Talisman, Washington, D.C., Michael R. Waller, Houston, Tex., and Terence J. Collins, Washington, D.C., were on brief, for Midwestern Gas Transmission Co. and Tenn. Gas Pipeline Co., petitioners in Nos. 84-1407 and 84-1408. Gregory Grady, Washington, D.C., also entered an appearance for Midwestern Gas Transmission Co. in No. 84-1407. ■
    James D. McKinney, Jr., Washington, D.C., with whom William R. Mapes, Jr., Washington, D.C., and Narinder J.S. Kathuria, were on brief, for Great Lakes Gas Transmission Co., petitioner in No. 84-1360.
    James W. McCartney, Houston, Tex., and Judy M. Johnson, Houston, Tex., were on briefs, for Transwestern Pipeline Co., petitioner in Nos. 84-1364 and 84-1580, and Tex. Eastern Transmission Corp., petitioner in No. 84-1446. David T. Andril, Washington, D.C., Carol A. White, Richard C. Alsup, and Cheryl M. Foley, Houston, Tex., were also on brief, for petitioner Transwestern Pipeline Co., and Bolivar C. Andrews, Houston, Tex., was on brief, for petitioner Tex. Eastern Transmission Corp.
    Thomas D. Clarke and Glen J. Sullivan, Los Angeles, Cal., were on brief, for Pacific Interstate Offshore Co., petitioner in No. 84-1489.
    Michael B. Silva, Robert W. Best, Christopher T. Boland, John F. Harrington, and William A. Williams, Houston, Tex., were on brief for Tex. Gas Transmission Corp., petitioner in No. 84-1487. Robert W. Per-due, Washington, D.C., also entered an appearance for Tex. Gas Transmission Corp.
    Thomas F. Ryan, Jr., Robert G. Hardy, and Michael J. Fremuth, Washington, D.C., were on brief, for Transcontinental Gas Pipe Line Corp., petitioner in No. 84-1470, and intervenor in Nos. 84-1358 to 84-1360, 84-1364, 84-1407, 84-1408, 84-1413 to 84-1418.
    David L. Huard, Norman A. Pedersen, Roger B. Coven, and Rachelle B. Chong, Washington, D.C., were on brief, for MIGC, Inc., petitioner in Nos. 84-1441 and 84-1623.
    John T. Ketcham and Joseph O. Fryxell, Washington, D.C., were on briefs, for Algonquin Gas Transmission Co., petitioner in No. 84-1474, and Cascade Nat. Gas Corp., et al., petitioners in No. 84-1490. Robert A. Nelson, Jr., Portland, Or., was also on joint brief, for petitioners in No. 84-1490. Ted P. Gerarden, Washington, D.C., also entered an appearance for Algonquin Gas Transmission Co. in No. 84-1474.
    William W. Brackett, Daniel F. Collins, Terry 0. Vogel, and Richard W. Miller, Jr., Washington, D.C., were on brief, for ANR Pipeline Co., petitioner in No. 84-1359.
    Ernest C. Baynard, III, Deputy Gen. Counsel, F.E.R.C., Washington, D.C., with whom Jerome M. Feit, Sol., F.E.R.C., and A. Karen Hill, Counsel, F.E.R.C., Washington, D.C., were on brief, for respondent. Barbara J. Weller, Counsel, F.E.R.C., Washington, D.C., also entered an appearance for respondent.
    Richard A. Solomon, Washington, D.C., for joint intervenors in Nos. 84-1358, et al. David E. Blabey, David D’Alessandro, and Richard Solomon, Washington, D.C., also entered appearances for intervenor Public Service Com’n of the State of N.Y.
    Michael B. Day, San Francisco, Cal., with whom J. Calvin Simpson, San Francisco, Cal., was on brief, for intervenor Public Utilities Com’n of the State of Cal. in Nos. 84-1358 to 84-1360, 84-1364, 84-1407, 84-1408, 84-1413 to 84-1418.
    Jeffrey M. Petrash, Detroit, Mich., with whom James H. Holt, Paul W. Mallory, and Mary Baluss, Washington, D.C., were on joint brief, for intervenors Inter-City Gas Corp., Mich. Consol. Gas Co., and Nat. Gas Pipeline Co., Jeffrey M. Petrash, James H. Holt, Paul W. Mallory, William Warfield Ross, and Daniel L. Koffsky, Washington, D.C., were also on brief, for intervenors American Iron & Steel Institute, et al. Toni K. Allen, William Warfield Ross, and Daniel L. Koffsky, Washington, D.C., entered appearances for intervenor Consumers Power Co. Paul E. Goldstein, Chicago, 111., also entered an appearance for intervenor Nat. Gas Pipeline Co. George B. Mickum, III, Washington, D.C., also entered an appearance for intervenor Inter-City Gas Corp.
    Thomas M. Patrick, Chicago, 111., with whom James Hinchliff and Karen Cargill, Chicago, 111., were on brief, for intervenor Peoples Gas Light & Coke Co. Richard E. Terry, Chicago, 111., also entered an appearance for Peoples Gas Light & Coke Co.
    George W. McHenry, Jr., and John R. Staffer, Washington, D.C., were on brief, for intervenors Pan-Alberta Gas, Ltd. and Foothills Pipe Lines (Yukon) Ltd. John H. Burnes, Jr., Washington, D.C., also entered an appearance for Pan-Alberta Gas, Ltd.
    William M. Lange and Jeffrey M. Goldsmith, Colorado Springs, Colo., were on brief, for intervenor Colo. Interstate Gas Co. Nancy A. White, Colorado Springs, Colo., also entered an appearance for Colo. Interstate Gas Co.
    E.R. Island and Michael D. Gayda, Los Angeles, Cal., were on brief, for intervenors Pacific Lighting Gas Supply Co. and Southern Cal. Gas Co.
    Steven M. Schur, Madison, Wis., was on brief, for intervenor Public Service Com’n of Wis.
    Joseph C. Bell, Washington, D.C., and Jeffrey Spring, were on brief, for Citizens Energy Corp., amicus curiae, urging affirmance in No. 84-1358.
    David I. Bloom, Washington, D.C., Lynn G. Kamarck, Washington, D.C., and Wendell H. Adair, Jr., Chicago, 111., entered appearances for intervenor Northern 111. Gas Co.
    Philip J. Mause, Washington, D.C., entered an appearance for intervenor Public Service Com’n of Wisconsin.
    Stephen J. Small and Richard L. Gottlieb, Charleston, W.Va., entered appearances for intervenor Columbia Gas Transmission Corp.
    Donald J. Maclver, Jr., Richard Owen Baish, Scott D. Fobes, C. Frank Reifsnyder, and Richard C. Green, El Paso, Tex., entered appearances for intervenor El Paso Nat. Gas Co.
    Edward J. Grenier, Jr., and Glen S. Howard, Washington, D.C., entered appearanees for intervenor Process Gas Consumers Group, et al.
    Richard M. Merriman, Washington, D.C., John R. Schaefgen, Jr., and Stephen L. Huntoon, entered appearances for intervenor Mich. Gas Utilities Co.
    Peter W. Hanschen, Steven F. Greenwald, and J. Michael Reidenbach, San Francisco, Cal., entered appearances for intervenor Pacific Gas and Elec. Co., et al.
    Michael W. Hall and Gary E. Guy, Washington, D.C., entered appearances for intervenor Brooklyn Union Gas Co.
    Thomas F. Ryan, Jr., Robert G. Hardy, and Michael J. Fremuth, Washington, D.C., entered appearances for intervenor Transcontinental Gas Pipe Line Corp.
    Louis J. Caruso, R. Philip Brown, Don L. Keskey, Ronald D. Eastman, and Lynda S. Mounts, Washington, D.C., entered appearances for intervenors State of Mich., et al.
    John B. Rudolph, Washington, D.C., entered an appearance for intervenor Northwest Energy Co.
    Paul H. Keck and Douglas L. Beresford, Washington, D.C., entered appearances for intervenor Transcanada Pipelines, Ltd.
    C. Edward Peterson, Topeka, Kan., entered an appearance for intervenor Kan. State Corp. Com’n.
    James R. Lacey, Newark, N.J., entered an appearance for intervenor Public Service Elec, and Gas Co.
    Lewis Carroll, Birmingham, Ala., entered an appearance for intervenor Wash. Gas Light Co.
    James L. Blasiak, Camillus, N.Y., entered an appearance for intervenor Consol. Gas Transmission Corp.
    Glenn W. Letham entered an appearance for intervenor Chattanooga Gas Co.
    Before TAMM, MIKVA, and STARR, Circuit Judges.
   TAMM, Circuit Judge.

Petitioners sell natural gas under contracts, tariffs, and certificates approved by the Federal Energy Regulatory Commission (the Commission). These contracts and tariffs often contain minimum commodity bills (or minimum bills) and minimum take provisions. A minimum commodity bill requires a pipeline customer to pay for a minimum volume of gas, whether or not the customer purchases that amount of gas. A minimum take provision requires a pipeline customer to take physically a certain amount of gas and does not give the customer the option to pay for gas not taken. Petitioners in these consolidated cases challenge Commission Order No. 380, which declares inoperative minimum bills to the extent such provisions enable pipelines to recover variable costs for gas not purchased by its customer, and Commission Order No. 380-C, which affirms the application of Order No. 380 to minimum take provisions. For the reasons given below, we affirm the Commission’s orders in all respects, except one. We find that the Commission’s decision, articulated in Order 380-A, that downstream pipelines cannot include in their minimum commodity bills certain fixed costs that their respective pipeline suppliers are permitted to include in their minimum bills is not based on reasoned decisionmaking, and we therefore remand that issue to the Commission for proceedings consistent with this opinion.

I. Background

Interstate pipelines ordinarily use a two-part rate consisting of a “commodity charge” and a “demand charge.” All customers pay a commodity charge, which is levied upon each unit of gas sold. Through the commodity charge, pipelines recover all the variable costs of providing service and between one-half and seventy-five percent of the fixed costs. Pipelines recover the remainder of the fixed costs through the “demand charge,” which is levied upon those customers who have a contractual entitlement to receive a specified amount of gas. The demand charge is not levied upon each unit of gas sold, but rather is a fixed sum, assessed in proportion to the maximum quantity of gas the customer is entitled to demand under the contract. The demand charge thus recoups some portion of fixed costs incurred by the pipeline in providing a transmission mechanism of sufficient capacity to meet the customer’s peak-load minimum entitlement.

Minimum commodity bills (or minimum bills) developed as an exception to the general rule that a commodity charge is levied only upon gas actually taken by the customer. The minimum bill requires a customer to pay the pipeline for a minimum volume of gas each month — typically from sixty-six to ninety percent of the amount of gas the customer is entitled to demand under the contract — whether or not the customer actually takes that amount of gas. Minimum take provisions do not allow customers to pay for gas not taken, but instead require customers to physically take the specified amount of gas.

Minimum bills are generally imposed upon “partial requirements” customers, that is, customers who have more than one pipeline supplier. Unlike so-called “full requirements” or “captive” customers, partial requirements customers’ geographic locations enable them to “swing” from one supplier to another to purchase the cheapest available gas. By requiring partial requirements customers to take or pay for a specified amount of gas, minimum bills limit the partial requirements customers’ ability to swing from one pipeline supplier to another pipeline supplier.

The Commission traditionally has given three justifications for minimum bills. First, minimum bills operate like the demand charge to recover fixed costs in proportion to a customer’s peak needs, rather than the customer’s actual take of gas. Second, minimum bills allocate fixed costs equitably among partial requirements and full requirements customers. Partial requirements customers take gas from more than one pipeline and can therefore drastically reduce their takes to capitalize on a cheaper source of gas. Full requirements customers take all of their gas from a single pipeline and are therefore unable to “swing” their purchases to other suppliers. Without a minimum bill, the full requirements customer could pay a disproportionate share of the fixed costs. Although the partial requirements customer pays for some fixed costs under the demand charge — computed on the basis of the customer’s entitlement and not on what the customer takes — the partial requirements customer can avoid that portion of the fixed costs collected through the commodity charge by swinging to an alternative source.

Finally, minimum bills enable pipelines to cover their own “take-or-pay” obligations to gas producers. Take-or-pay contracts govern wellhead sales between producers and pipelines. Like minimum bills, under take-or-pay contracts a pipeline must take or, if not take, pay for, a minimum amount of gas. The pipeline must contract with the producer for a quantity of gas sufficient to fulfill the pipeline’s obligation to deliver to its customers the contract demand amount. If a partial requirements customer makes an unexpected swing off of the system, the pipeline may be unable to sell the gas it is obligated to purchase from the producer. Associated take-or-pay liabilities, if “prudently” incurred, become a fixed cost on the system and can be passed on to remaining customers in the form of increased rates. By requiring partial requirements customers to purchase a minimum amount of gas, the minimum bill reduces a pipeline’s exposure to take-or-pay liabilities and hence protects full requirements customers from bearing a disproportionate share of the pipeline’s fixed costs.

Significantly, the justifications traditionally given for the minimum bill focus upon the allocation of fixed costs among pipeline customers. Since variable costs traditionally represented a relatively small proportion of the total minimum commodity bill, recovery of variable costs through the minimum bill was generally incidental to the recovery of fixed costs. Moreover, until the late 1970’s, demand for natural gas exceeded supply; consequently, pipeline customers seldom paid for gas that they would not have taken in the absence of a minimum bill provision.

Because of radical changes in the natural gas industry over the past several years, minimum bills have had an increasingly severe impact upon the price of natural gas and the allocation of variable costs among pipeline consumers. In 1978, Congress passed the Natural Gas Policy Act (NGPA), 15 U.S.C. §§ 3301 et seq. (1982), which removed regulations that had kept wellhead prices below market value. The statute had the intended effect of encouraging production. The simultaneous drop in oil prices and a severe recession, however, drastically reduced demand for natural gas. The net result of these converging factors was to convert the gas supply shortage of 1977-78 to the gas supply surplus of 1982-85.

Natural gas prices, however, did not fall during this nationwide glut. Instead, the price of gas remained high because minimum bills forced customers to purchase gas from particular pipelines even if cheaper supplies were available elsewhere. At the same time, the minimum bill’s salutory effect upon the distribution of fixed costs among partial and full requirements customers diminished as fixed costs became an increasingly smaller percentage of minimum bills. Purchased gas cost — the primary variable cost — steadily rose from forty percent to over seventy-five percent of the pipeline’s delivered cost. See Order No. 380 at 11, Joint Appendix (J.A.) at 802.

In response to concerns raised by parties regarding the role of minimum bills in this anomalous situation, the Commission announced in 1983 its intention to eliminate minimum bills from a pipeline’s tariff to the extent that these provisions permitted the recovery of variable costs. Notice of Proposed Rulemaking, J.A. at 1. After receiving comments from over ninety-five interested parties, the Commission determined that minimum bills had two negative effects upon the natural gas market:

First, minimum commodity bills have become a vehicle by which enormous purchased gas “costs” can be collected even if the pipeline never actually incurs such costs. Second, minimum commodity bills have become a major obstacle to the transmittal of clear market signals from the burner tip back to the well-head.

Order No. 380 at 14, J.A. at 805. Accordingly, the Commission held that the collection of variable costs through a minimum bill represented an “unjust and unreasonable” rate under sections 4 and 5 of the Natural Gas Act (NGA). After taking additional comments, the Commission in Order No. 380-C extended this prohibition to minimum take provisions.

Order No. 380 is limited in two critical respects. First, the order does not affect the recovery of fixed costs through the minimum bill. Partial requirements customers, therefore, remain obligated to pay the fixed costs attributable to their contract entitlement amount: under the Commission’s decision, these costs can be recovered through the demand charge (unrelated to the minimum bill) and through the fixed-cost component of the minimum bill. Second, although take-or-pay contracts between pipelines and gas producers superficially resemble the minimum bills between pipelines and their purchasers, the Commission has chosen not to prohibit variable-cost components in take-or-pay clauses at this time. Thus, while gas customers are relieved of the burden of purchasing minimum amounts of gas, pipelines must still honor commitments to gas producers to take, or pay for, a specified amount of gas.

Few elements of the Commission’s rule-making have escaped the collective challenge of the many parties before this court. Rather than discuss the challenges separately, we group the arguments around three aspects of the Commission’s decision. First, we address the Commission’s statutory authority to eliminate variable cost recovery through minimum bills. We then consider the substantive validity of the rule, that is, whether it is based on substantial evidence and is otherwise a reasonable exercise of agency authority. Finally, we address petitioners’ various challenges to the procedures employed by the Commission.

II. Statutory Authority

A. Statutory Framework

Sections 4 and 5 of the Natural Gas Act empower the Commission to regulate rates, charges, and practices of natural gas companies under its jurisdiction. Section 4(a) provides that rates charged by natural gas companies “shall be just and reasonable, and any such rate or charge that is not just and reasonable is declared to be unlawful.” 15 U.S.C. § 717c(a). Section 5(a), the primary basis for the Commission’s authority to promulgate the challenged orders, empowers the Commission to examine rates to determine whether they comply with the section 4 standard:

Whenever the Commission, after a hearing had upon its own motion or upon complaint of any State, municipality, State commission, or gas distributing company, shall find that any rate, charge, or classification demanded, observed, charged, or collected by any natural-gas company in connection with any transportation or sale of natural gas, subject to the jurisdiction of the Commission, or that any rule, regulation, practice, or contract affecting such rate, charge, or classification is unjust, unreasonable, unduly discriminatory, or preferential, the Commission shall determine the just and reasonable rate, charge, classification, rule, regulation, practice, or contract to be thereafter observed and in force, and shall fix the same by order____

15 U.S.C. § 717d(a). As this court held in American Public Gas Association v. FPC, 567 F.2d 1016, 1064-67 (D.C.Cir.1977), the Commission is empowered to exercise its section 5(a) authority by rule. Finally, section 16 of the Natural Gas Act, 15 U.S.C. § 717o, authorizes the Commission to “perform any and all acts, and to prescribe, issue, make, amend, and rescind such orders, rules, and regulations as it may find necessary or appropriate to carry out the provisions of the [Act].”

B. Challenges to the Commission’s Statutory Authority

Although petitioners launch a barrage of attacks upon the Commission’s authority to issue Order No. 380, only two claims warrant textual discussion. First, petitioners Transcontinental Gas Pipe Line Corporation (Transco) and ANR Pipeline Company (ANR) contend that the Commission has unlawfully abrogated settlement agreements to which the Commission is a party. Second, petitioner Great Lakes Gas Transmission Company argues that Order No. 380 is in excess of the Commission’s authority because it is inconsistent with its import authorization approved by the Economic Regulatory Commission pursuant to section 3 of the Natural Gas Act.

1. Abrogation of Settlement Agreements

Transco and ANR each contend that the Commission exceeded its statutory authority by abrogating settlement agreements to which the Commission was a party. The Commission contends in response that it cannot limit by settlement either its statutory authority under section 5 to investigate the reasonableness of tariffs or its statutory obligation to change prospectively tariffs it finds unjust or unreasonable.

We find that Order No. 380 does not violate any terms of either Transco’s or ANR’s settlement. We therefore do not reach the issue of whether the Commission has the statutory authority to abrogate settlement agreements to which it is a party through a generic section 5 rulemaking.

a. Transco

Prior to the initiation of the Order No. 380 rulemaking, Transco, its customers, and the Commission staff agreed in a settlement of Transco’s rate proceeding to reserve for determination at an adjudicative hearing the issue of the design and cost components of Transco’s minimum bill charge. After the adjudicative hearing, but before the Administrative Law Judge (AU) rendered his final decision, the Commission issued Order No. 380 nullifying minimum bills to the extent that they recover variable costs in the commodity charge. The AU found that Order No. 380 governed disposition of the issue and held that Transco could not recover variable costs in its minimum bill. Transco contends that the Commission abrogated the settlement agreement by taking from the AU the power to render a decision based upon Transco’s particular need for a minimum bill.

We disagree. The settlement agreement reserved the minimum bill issue for determination but did not mandate any particular resolution. Transco received what the settlement promised — a hearing before an AU. The AU’s conclusion, based on Order No. 380, that Transco could not recover variable costs in its minimum bill does not violate any of Transco’s rights under the settlement agreement. Had the parties intended to immunize Transco’s minimum bill from the general impact of an industry-wide rulemaking, they could have easily so provided in the terms of the agreement. We refuse to read any such broad-ranging intent into the simple agreement to defer resolution of the dispute and, therefore, conclude that Order No. 380 does not abrogate the terms of the settlement agreement.

b. ANR and WDG

In 1982 Michigan Consolidated Gas Company (MichCon) advised ANR that it would fall roughly $200 million short of the minimum bill level prescribed in the tariff between ANR and MichCon. In the spring and summer of 1982, MichCon’s minimum bill became an issue in ANR’s general rate increase application proceeding pending before the Commission. After extensive negotiations, the parties (MichCon, ANR, and Wisconsin Distributors Group (WDG)) agreed to some changes in the minimum bill but concluded that further proceedings were necessary to finally resolve other contested minimum bill issues. Accordingly, the parties entered into the following agreement:

All issues relating to cost allocation, classification and rate design will be set for hearing in Docket No. RP82-80. The Commission’s decision therein pursuant to such hearings relative to such issues will be effective, prospectively only, on the first November 1 following the date of a Final Commission Order issued in such case; provided, however, that if a Final Commission Order is issued between October 1 and November 1 of the same year, it shall be implemented on November 1 of the next succeeding year.

Brief for ANR at 28 (emphasis added). The Commission approved this agreement on February 10, 1983. After thirteen months of further negotiations, the parties still had not settled the minimum bill issues, and, on January 19, 1984, the Commission approved another settlement agreement which, like the agreement quoted above, deferred resolution of the minimum bill issues.

Meanwhile, on August 25, 1983, the Commission issued its notice of proposed rule-making for Order No. 380. ANR and WDG filed comments in opposition, stating their belief that the Commission did not have the statutory authority to determine by rulemaking the minimum bill issues subject to the settlement agreement. In Order No. 380, the Commission addressed these comments but concluded that the settlement agreement could not be binding insofar as it “reflects a provision found to be unjust and unreasonable.” J.A. at 841.

MichCon contends that even if the Commission lacks the statutory authority to abrogate the settlement agreement, Order No. 380 does not, in fact, violate the terms of the settlement agreement. We agree. The reservation in the settlement agreement does not, as ANR and WDG contend, mandate that the minimum bill issue be resolved only in ANR’s individual rate case. The settlement merely provides that the issue “be set for hearing in Docket No. RP82-80”; it does not say, as petitioners believe, that “the parties ... expressly agreed that no change in ANR’s minimum bill would be allowed until after hearing and final Commission order.” Brief for WDG at 8. The settlement merely defers resolution of the minimum bill issue. Again, had the parties to the settlement agreement intended to exempt ANR’s minimum bill from the ongoing general rule-making, they could have easily so provided. As it is written, however, the agreement neither binds the Commission to resolve the issues in ANR’s ratemaking proceeding nor exempts ANR’s minimum bill provisions from the general rulemaking in progress. We conclude, therefore, that by issuing Order No. 380 the Commission did not violate the terms of the settlement agreement.

2. Authority to Regulate Imported Gas

Originally, the Federal Power Commission regulated the import and export of natural gas pursuant to section 3 of the NGA. Congress in 1977 transferred the functions of the Federal Power Commission to the Department of Energy (DOE) but did not specify which entity within DOE would be responsible for regulating the import and export of natural gas. The Secretary of Energy issued an order delegating shared regulatory authority over imported gas to the Economic Regulatory Administration (ERA) and the Commission. The Secretary granted ERA authority to determine in what instances the importation of natural gas is in the public interest. The Secretary gave the Corn-mission authority, however, to regulate imported gas as it moves through interstate commerce. Confusion over the respective authority of the two agencies led the Secretary to issue new policy guidelines on February 17, 1984. These new regulations provide:

The FERC ... maintains its responsibilities for exercising sections 4, 5, and 7 authority under the Natural Gas Act over gas authorized for import by the Administrator. Gas authorized for importation is subject to the FERC’s review of issues pertaining to siting, construction, and operation of pipeline facilities, and to the rates proposed to be charged for the interstate transportation and sale of the gas. The FERC review, in effect, will address the regulatory matters relevant to the imported gas upon its entry into the United States and as it flows through domestic gas transportation systems. In its regulatory decisions on a gas supply authorized for importation, the Commission will adopt the terms and conditions attached by the ERA Administrator to the import authorization, thus acting consistently with the determinations made by the Administrator and the policy considerations reflected in the authorization.

New Policy Guidelines and Delegation Orders on the Regulation of Imported Natural Gas, 49 Fed.Reg. 6684, 6689 (1984) (emphasis added) (hereinafter “Delegation Orders”). In sum, the Commission is statutorily obligated under sections 4 and 5 of the Act to declare unlawful rates it finds unjust and unreasonable. Pursuant to the section 3 power delegated to it by the Secretary, the Commission is empowered to exercise its sections 4 and 5 powers over imported gas. The only limit placed upon this authority is that the Commission cannot, consistent with the Delegation Orders, take actions inconsistent with the terms, conditions, or policy considerations reflected in the ERA’s section 3 import authorization.

Petitioner Great Lakes imports natural gas purchased from its sole supplier, TransCanada Pipelines Ltd., pursuant to a section 3 import authorization. The authorization approves a contract between Great Lakes and TransCanada, which contains take-or-pay provisions. Great Lakes contends that Order No. 380 is inconsistent with the approved take-or-pay clauses because, without variable cost recovery through minimum bills, Great Lakes will be unable to recoup any take-or-pay liability from its partial requirements customers. This claim is without merit. First, Order No. 380 expressly does not alter the terms or conditions of the contracts between Great Lakes and its Canadian supplier. Similarly, the import authorization is unrelated to the object of Order No. 380 — the contractual relationship between Great Lakes and its customers.

Second, that Order No. 380 may render the contractual provisions approved by the ERA more burdensome does not mean that the Order is inconsistent with the terms of the import authorization. Any action taken by the Commission pursuant to its delegated authority under section 3 is bound to have an impact upon the pipeline selling imported gas, which, in turn, will have an impact upon the pipeline’s relationship with its foreign supplier. For the Commission’s power under section 3 to have any meaning, however, it must extend to actions such as those taken here, which may indirectly affect the import authorization. Here, the impact upon the authorization is trivial; the Commission’s action in no way intrudes upon the responsibilities delegated to the ERA. As such, the Commission’s decision cannot be deemed inconsistent with the terms or conditions of the authorization, or with any policy considerations underlying the authorization. We therefore hold that by eliminating the minimum bill in Great Lakes’ tariff, the Commission has not exceeded its authority to regulate importers of natural gas.

III. Substantial Evidence

A. The Standard of Review

The parties devote a substantial part of their briefs to the issue of the proper standard of review of this informal rulemaking under the Natural Gas Act. Some petitioners submit that the court must apply the “substantial evidence” test, which is, in their view, less deferential than the “arbitrary and capricious” test. Some intervenors and the Commission insist that while the Commission’s factual determinations must be based on substantial evidence, the Commission’s policy decisions should be accorded greater deference under the “arbitrary and capricious” standard.

There is much less to this dispute than meets the eye. Under section 19(b) of the Natural Gas Act, the Commission’s findings of fact, if supported by “substantial evidence,” shall be conclusive. As we held in Public Systems v. FERC, 606 F.2d 973, 979 (D.C.Cir.1979), the “substantial evidence” standard of section 19 applies to notice and comment rulemaking. When applied to such proceedings, however, the substantial evidence test is identical to the familiar arbitrary and capricious standard. See American Public Gas Association v. FPC, 567 F.2d 1016, 1029 (D.C.Cir.1977), cert. denied, 435 U.S. 907, 98 S.Ct. 1456, 55 L.Ed.2d 499 (1978). Under this standard, the court requires “the Commission to specify the evidence on which it relied and to explain how that evidence supports the conclusion it reached.” City of Charlottesville v. FERC, 661 F.2d 945, 950 (D.C.Cir.1981).

B. Discussion

We divide the various challenges to the reasonability of the Commission’s rule into two broad groups. First, we consider the evidentiary support for the rule as a whole. Second, we address particular claims unique to several petitioners.

1. Evidentiary Basis for the Rule

Three essential findings underlie the Commission’s rule. First, minimum bills allow pipelines to recover for variable costs that they do not incur. Second, minimum bills prevent gas purchasers from purchasing the lowest priced gas and hence artificially maintain high gas prices. Third, the benefit of eliminating variable cost recovery through minimum bills outweighs the negative impact such action will have upon pipelines and upon full requirements customers.

a. Prevention of Overrecovery of Variable Costs

The Commission found that to the extent minimum commodity bills permit the recovery of variable costs not incurred, they are unjust and unreasonable under the Natural Gas Act. Order No. 380 at 19, J.A. at 810. Although challenged by a surprising number of petitioners, the factual support for the overrecovery rationale is unassailable. Minimum bills allow pipelines to charge for gas that its customer does not take; if the customer pays for gas not taken, the pipeline recovers for variable costs that it does not incur.

Many pipelines contend that the overrecovery rationale does not apply to their particular circumstances because their customers have never actually paid for gas not taken. Petitioner ANR contends, for example, that the evidence does not support the overrecovery rationale because, in decades of operations, it has never actually collected for gas not taken. This fact is as unastonishing as it is irrelevant. ANR’s contention merely reflects the rational choice of its partial requirements customers to take gas that they must pay for rather than pay for gas not taken. The lynchpin of the Commission’s rationale, however, is the potential for overreeovery. ANR’s challenge, typical of many petitioners’ arguments, does nothing to refute the Commission’s finding that the rule will be beneficial to the extent that it will prevent even the possibility that pipelines like ANR will recover variable costs for gas not taken.

b. Promotion of Competition

Properly understood, the Commission’s overrecovery rationale is inextricably linked to the second purpose of eliminating variable cost recovery through minimum bills — to promote price competition among pipelines. With respect to gas purchasing decisions, partial requirements customers who operate pursuant to a minimum bill have only two options. First, if the gas is either not needed or if less expensive gas is available elsewhere, the customer can pay for the minimum requirement of gas but not take it. For obvious reasons, this rarely happens; but when it does, it can lead to overrecovery by the pipeline. Second, the customer can pay for and take the gas, and, in some instances, either forego a cheaper alternative elsewhere or take gas that it does not need and cannot market. When this second option is chosen, the Commission found, minimum bills operate to artificially maintain high gas prices. The Commission reasoned that if variable cost components in minimum bills are eliminated, partial requirements customers will purchase gas from the cheapest supplier, rather than be forced, under the minimum bill, to purchase the gas regardless of cost. The prospect of losing partial requirements customers to cheaper alternatives will, therefore, force pipelines to become more price competitive.

Petitioners do not seriously challenge the plausibility of the Commission’s thesis concerning the anti-competitive effects of minimum bills. Rather, petitioners insist that “mere reliance on an economic theory cannot substitute for substantial record evidence and the articulation of a rational basis for an agency’s decision.” Electricity Consumers Resource Council v. FERC, 747 F.2d 1511, 1514 (D.C.Cir.1984).

As we have repeatedly held, unsupported or abstract allegations of the benefits that will accrue from increased competition cannot substitute for “a conscientious effort to take into account what is known as to past experience and what is reasonably predictable about the future.” American Public Gas Association v. FPC, 567 F.2d 1016, 1037 (D.C.Cir.1977). Thus, while an agency “is not required to make specific findings of tangible benefit,” there must be “ground for reasonable expectation that competition may have some beneficial impact.” FCC v. RCA Communications, Inc., 346 U.S. 86, 96, 97, 73 S.Ct. 998, 1004, 1005, 97 L.Ed. 1470 (1953).

The Commission has provided abundant evidence that the recovery of variable costs through minimum bill and minimum take clauses prevents customers from shopping for low-cost gas, thereby insulating pipelines from market forces that would otherwise drive gas prices down. The record is replete with comments from customers who have been unable to purchase lower cost gas because of minimum bills and minimum take provisions. Furthermore, the arguments made by petitioners themselves support the Commission’s findings. Petitioner ANR, for example, complains that Order No. 380 will allow its largest partial requirements customer, MichCon, to swing to a cheaper supplier. It will indeed — and consequently will save MichCon hundreds of millions of dollars.

The best argument petitioners can muster is that, while the elimination of minimum bills will increase competition, other market imperfections will prevent the Commission’s rule from having the intended beneficial impact upon the natural gas market. Petitioners MIGC, Inc. and Arkansas Louisiana Gas Company (ARKLA) contend, for example, that because their large partial requirements customers also purchase gas directly from producers, these customers may swing to purchase higher priced gas to avoid additional take-or-pay liability. Yet, it is far from clear that this swing will not result in cheaper gas prices at the “burner tip” — the consumer level of the gas transmission system. Presumably, these customers are obligated to take or pay for the higher priced gas regardless of whether minimum bills are in force. Further, any take-or-pay penalties can be included in the pipeline customer’s rates. It would seem, therefore, that elimination of minimum bills will enable the pipeline’s customers to avoid take-or-pay penalties and to pass these savings on to the ultimate consumers. More significantly, however, the issue is not whether a particular pipeline will pursue a least-cost purchasing strategy but is instead whether the customer will have the ability to do so. Even if some customers do not pursue such a strategy, the Commission has presented evidence that many customers will, and thus the elimination of minimum bills can reasonably be expected to lower gas costs and spur competition among pipelines. We therefore conclude that the Commission has not merely assumed that competition will have a beneficial impact upon the natural gas market but instead has presented a sensible theory supported by substantial evidence.

c. The Detrimental Impact of Rule 380

Unable to assail the Commission’s conclusions that the elimination of minimum bills will remove barriers to competition, petitioners contend that the general benefits of competition do not outweigh the harm that will be visited (1) upon pipelines subject to take-or-pay liabilities with gas producers and (2) upon the full requirements customers of higher priced pipelines.

(1) Harm to Pipelines — The Take-Or-Pay Issue

As explained above, contracts between producers and pipelines often contain take- or-pay clauses, which, like the minimum bill, require a pipeline to take or pay for a specified amount of gas. The petitioners assert that the problems created by take- or-pay contracts with producers are inextricably linked to minimum bills because if their partial requirements customers shift to lower cost suppliers, they will be unable to meet their take-or-pay obligations. Petitioners contend that by failing to simultaneously prohibit take-or-pay clauses, the Commission has engaged in irrational “piecemeal reform” and unduly discriminated against pipelines in favor of producers and purchasers.

The Commission gave considerable attention to the difficult take-or-pay issue but concluded that “there is no clear nexus between a pipeline’s annual take-or-pay obligations and its minimum commodity bills to its customers.” Order No. 380 at 41, J.A. at 832. As the Commission explained in Order No. 380-A, “[t]his does not mean, however, that the Commission necessarily supports high take-or-pay levels in producer-pipeline contracts. It is simply not essential that the take-or-pay issues be resolved here.” Order No. 380-A at 31, J.A. at 1486.

The issue for this court, then, is not whether take-or-pay clauses should be prohibited but is whether the take-or-pay clauses are so inextricably related to minimum bills that simultaneous resolution of the issues is required. We held in ITT World Communications, Inc. v. FCC, 725 F.2d 732, 754 (D.C.Cir.1984), that “an agency does not act rationally when it chooses and implements one policy and decides to consider the merits of a potentially inconsistent policy in the very near future.” We have also held, however, that review of an agency decision to defer issues must be “pragmatic so as to ensure reasoned decisionmaking while allowing the Commission to cope with rapidly changing circumstances.” Neighborhood TV Co. v. FCC, 742 F.2d 629, 642 (D.C.Cir.1984). An agency should not be paralyzed by having to decide all relevant issues at the same time. The agency’s decision should be upheld unless the agency “abuse[s] this flexibility by failing to consider, in a rulemaking, an issue whose resolution might seriously undercut the ... rationale for its final action in that rulemaking.” Id. (citations omitted).

The Commission advanced several reasons for its conclusion that the minimum bill and take-or-pay issues are not inextricably linked. First, petitioners’ attempt to characterize the minimum bill as the pipeline’s protection against take-or-pay liability is simply incorrect. Possible reductions in purchases by partial requirements customers will not necessarily result in increased pipeline liability under take-or-pay clauses. Unlike typical minimum bills, most take-or-pay clauses allow pipelines to credit penalty payments to subsequent gas purchases that exceed the take-or-pay requirement. Because of this make-up period, take-or-pay clauses rarely, if ever, result in a pipeline paying for gas that it never receives. Second, even if reductions in gas purchases increase pipelines’ take-or-pay liabilities, this possibility does not undercut the Commission’s rationale for Order No. 380; the elimination of minimum bills still encourages pipelines to institute market-responsive pricing of natural gas, and pipelines will not recover for variable costs they do not incur. Further, by lowering prices, which is a primary goal of the Commission’s rule, pipelines can maintain sales to partial requirements customers and thus prevent take-or-pay exposure. Moreover, as the Commission found, this increased price competition may spur renegotiation of take-or-pay clauses with gas producers.

It is true that many of the policy considerations that support the elimination of variable cost recovery for the minimum bill might support the elimination of take-or-pay clauses. As Commissioner Sousa expressed in his concurring opinion, take-or-pay provisions, like minimum bills, tend to discourage competition and keep natural gas prices artificially high. Order No. 380 (concurring opinion), J.A. at 862. Yet for the reviewing court to maintain its proper function, it cannot require agencies to solve all problems that may be related to a particular decision at the same time. That which we can require, the Commission has here provided: an explicit assessment of the relationship between the action taken and the issue deferred, and a reasonable conclusion that the public interest can best be advanced by the measured step taken.

(2) Impact Upon Full Requirements Customers

Perhaps the most serious consequence of Rule 380 is its impact upon the “captive” or full requirements customer. As explained above, full requirements customers purchase their entire natural gas supply from one pipeline and, because of their geographic location, are unable to swing off the system to obtain cheaper supplies of gas. Traditionally, minimum bills protected these captive customers from being forced to bear a disproportionate share of fixed costs. If partial requirements customers are permitted to swing off the system, remaining full requirements customers may be harmed in several ways. First, as the Commission explained, decreases in sales may increase a pipeline’s take-or-pay payments, and these payments, if unrecovered, could then be passed on to full requirements customers in the form of increased fixed costs in their commodity charge. Second, pipelines might decrease purchased gas commitments (and thereby reduce take-or-pay exposure) and expose full requirements customers to curtailment of their contract entitlement.

The Commission found that the rule would benefit full requirements customers of lower priced pipelines because increased sales to new partial requirements customers would decrease each customers’ share of fixed costs. “Thus, viewed from a national perspective, the rule may create offsetting benefits and detriments to captive customers, depending on whether they are served by a high-cost or a low-cost pipeline.” Order No. 380 at 33, J.A. at 824. “This national perspective,” the Commission candidly recognized, “is small comfort to customers of a high-cost pipeline.” Id.

The Commission concluded, however, that the harm to captive customers of higher priced pipelines would be isolated, of short duration, and outweighed by the overall long-term benefits to these customers that would result from increased competition. First, the Commission found that the pipelines themselves would initially absorb the costs associated with the loss of partial requirements customers because the pipeline must file a new rate case (a process that usually lasts six months) before passing such costs on to its remaining customers. Moreover, in its rate filing, the take-or-pay costs may be disallowed as imprudently incurred, or these costs may be allocated specially to the swinging partial requirements customers. Second, “to the extent a pipeline loses sales as a result of its inability to meet competition,” the Commission found, “its allowed return on equity may have to be adjusted,” thereby reducing fixed costs to all customers. Order No. 380 at 35, J.A. at 826. Third, the Commission predicted that the increased incentive to compete vigorously in the market would eventually lead to lower prices for all customers. Finally, emergency procedures are available to assure that captive customers will not experience shortages in supply.

Petitioners advance no specific objection to the Commission’s analysis but, rather, vaguely assert that the balance struck by the Commission is unwise. Had the Commission either failed to address the problems faced by captive customers or engaged in a less than candid balancing of the costs, its determinations perhaps would be vulnerable on review. The Commission, however, exhaustively considered these problems, recognized that some harm would result from the elimination of minimum bills, indicated it would consider in individual cases whether particularly costly swings warrant special allotment of costs, and, finally, concluded that the benefit of increased competition would eventually inure to even the captive customer of a high-priced pipeline. These are the hard choices agencies are empowered — indeed required — to make. We therefore conclude that the Commission adequately addressed the concerns of captive customers.

d. Conclusion

In sum, we find that each of the order’s essential elements is supported by substantial evidence. Since we have assured ourselves “that the Commission has given reasoned consideration to each of the pertinent factors,” it is not our province “to supplant the Commission’s balance of these interests with one more nearly to [our] liking.” Permian Basin, 390 U.S. at 792, 88 S.Ct. at 1373.

2. Unique Claims

Most of the petitioners in this case assert that even if the rule generally is founded upon substantial evidence, unique circumstances render the rule inapplicable to them. Only two specific claims, however, warrant textual discussion. First, several petitioners challenge as discriminatory the exemption granted to Northwest Alaskan Gas Company. Second, Midwestern Gas Transmission Company challenges the Commission’s decision in Order No. 380-A that fixed costs charged by its pipeline supplier cannot be included in Midwestern’s minimum bill.

a. Northwest Alaskan Pipeline Company’s Exemption and the Alaskan Natural Gas Transportation System

In Order No. 380-A, the Commission held that the rule eliminating minimum bills would not apply to Northwest Alaskan Pipeline Company’s sales tariff. Northwest Alaskan’s exemption from the rule is based upon its participation in the Alaskan Natural Gas Transportation System (AN GTS). Petitioners Trans western, Algonquin, and Great Lakes contend in variously articulated arguments that because they purchase gas from Canadian suppliers, there is no rational basis for the Commission’s decision to apply the rule to their respective tariffs, while exempting Northwest Alaskan’s tariff.

Pursuant to the Alaska Natural Gas Transportation Act (ANGTA), 15 U.S.C. § 719 (1982), and an agreement between Canada and the United States, President Carter in 1977 issued a decision approving the construction of a 5,000-mile pipeline, which will eventually connect Alaskan gas reserves, through Canada, with markets in the contiguous United States. In 1980, prior to the commencement of Alaskan gas deliveries, the Commission in a series of orders authorized the “prebuilding” of the Southern Canadian and United States segments of the system. To secure Canadian participation in the project and to assure Canadian investors that the construction of this segment could be properly financed, the Commission authorized the importation by Northwest Alaskan of approximately 1.04 Bcf per day of Canadian natural gas from Pan-Alberta Gas Ltd. After extensive negotiations, the Commission in its decision approving Northwest Alaskan’s contract with its Canadian supplier, also crafted a contract formula that guaranteed the Canadian suppliers an adequate revenue stream generated from United States sales. In this regard, the Commission specifically recognized the importance of assuring a minimum stream of revenue to support the financing of the ANGTS and promised that it “would not change the principles upon which the revenue stream is calculated during the authorization of the imports.” After receiving requested assurances from the President and Congress of the United States’ commitment to the project, the Canadian government in 1980 permitted the project to go forward.

Due to ambiguities in the Commission’s May 1984 Order No. 380, it was not possible to determine whether the ban on variable cost recovery through minimum bills extended to Northwest’s minimum take provisions. The uncertainty generated comments from the Canadian government, the Economic Regulatory Administration, and the Undersecretary of State, urging the Commission to reconsider the impact of Order No. 380 upon the prebuilt segments of the ANGTS. On July 30, 1984, the Commission issued Order No. 380-A, stating explicitly that the Rule did not apply to Northwest’s sales tariff. The Commission exempted Northwest because “ANGTS is a unique international project whose ultimate success has always rested on a framework of mutual trust and cooperation between the governments of the U.S. and Canada.” Order No. 380-A at 95, J.A. at 1550. Furthermore, “any subsequent action that could adversely affect [the] stream of revenue [underpinning the financing of the Canadian segment of the ANGTS] would constitute a breach of our nation’s relationship with Canada.” Id. at 96, J.A. at 1551. In Order No. 380-B, the Commission denied Transwestern’s application for rehearing on the Northwest exemption and reaffirmed the uniqueness of the ANGTS project.

Petitioners Great Lakes, Algonquin, and Transwestern argue that by exempting Northwest the Commission has unlawfully discriminated against them and other similarly situated pipelines because, they contend, there is no substantial difference between their positions with respect to their Canadian suppliers and Northwest’s position with respect to its Canadian supplier. This contention is wholly without merit. The only similarity between petitioners and Northwest is that they all import Canadian gas. None of the petitioners participate in the ANGTS but instead merely purchase gas supplies from Canadian producers. Thus, although their Canadian producers rely on the revenue stream generated by petitioners’ domestic operations, such reliance is not based upon explicit assurance

from the Commission that it would not change the principles upon which the revenue stream is calculated during the authorization of the imports. Northwest’s operations, unlike petitioners’, involve a matrix of agreements entered into by the regulatory bodies of the United States and Canada necessary to ensure the successful completion of the massive trans-Canada pipeline. Application of the rule to Northwest’s tariff would have placed the United States in breach of its explicit commitments to Canada. Moreover, ANGTS has received on more than one occasion the special attention of the President and Congress. Thus, the diplomatic considerations cited by the Commission apply only to Northwest and are not relevant to petitioners’ contracts. Therefore, the Commission has provided sufficient evidence of the differences between these tariffs, see St. Michaels Utilities Commission v. FPC, 377 F.2d 912, 915 (4th Cir.1967) (“where there exists a difference in rates which is attacked as illegally discriminatory, judicial inquiry devolves on the question of whether the record exhibits factual differences to justify classifications among customers and differences among the rates charged them”), and we cannot conclude that the distinction drawn by the Commission on the basis of this unique situation is an unreasonable one. See Metropolitan Edison Co. v. FERC, 595 F.2d 851, 857 (D.C.Cir. 1979) (“A difference in rate treatment is not unduly discriminatory when the difference is amply justified____”). We therefore conclude that the Commission has not unreasonably discriminated against petitioners by exempting Northwest from the rule.

b. Downstream Pipeline Issue

Most pipelines subject to the Commission’s jurisdiction purchase their gas supplies directly from producers in gas producing areas. The pipeline then transports the gas to market areas and sells the gas to its customers in those areas. Some pipelines, however, do not purchase gas directly from a producer, but instead purchase gas “downstream” from another pipeline. Under this system of transmission, the upstream pipeline purchases the gas from the producer and then transports the gas from the gas producing area to the location of its facilities. The downstream pipeline then purchases the gas from the upstream pipeline and transports the gas to the market areas.

Petitioner Midwestern is a downstream pipeline that purchases most of its gas supply from an affiliate pipeline, Tennessee Gas Pipeline, Inc. Tennessee sells gas to Midwestern pursuant to a minimum bill. The commodity charge in Tennessee’s minimum bill includes charges for both fixed and variable costs incurred by Tennessee. Midwestern then transports the gas from Tennessee’s facilities to its market area and sells the gas pursuant to a minimum bill which contains a commodity charge reflecting Midwestern’s fixed and variable costs.

In response to the Commission’s statement that the objective of Order No. 380 is “the elimination from natural gas pipeline sales tariffs of any minimum commodity bill provisions that operate to recover variable costs,” Order No. 380 at 1, J.A. at 792, Midwestern requested that the Commission clarify its decision by stating that “only the variable cost portion of the upstream pipeline’s commodity charge be considered variable for purposes of the downstream pipeline’s commodity charge.” Order No. 380-A at 33, J.A. at 1488. The requested clarification would have permitted Midwestern to include both the fixed-cost component of Tennessee’s commodity rates and the fixed-cost component of Midwestern’s commodity rates in Midwestern’s minimum bill.

In Order No. 380-A, the Commission denied Midwestern’s request and held instead that Midwestern could recover any minimum bill charges for fixed costs by debiting these charges to its unrecovered purchased gas cost account. Midwestern could then recover the charges in its semiannual purchased gas cost adjustment filing through higher commodity rates for all of its customers. Thus, under the Commission’s decision, Tennessee’s fixed costs cannot be included in Midwestern’s minimum bill but instead will be charged to each of Midwestern’s customers in proportion to the amount of gas taken by that customer.

In its decision, the Commission agreed that the “desire to collect for these costs is entirely reasonable, since the downstream pipelines do actually incur the upstream pipeline’s fixed costs,” Order No. 380-A at 33-34, J.A. at 1488-89, but concluded:

The Commission considers the cost a downstream pipeline pays an upstream pipeline for gas to be a “purchased gas cost” regardless of what types of costs make up the total charge for the gas. As a “purchased gas cost,” the entire amount paid for the gas is considered variable and is recovered through the purchasing pipeline’s commodity charge. To treat purchased gas costs in any other manner would constitute a departure from consistent Commission rate design practice.

Id. at 33, J.A. at 1488. This statement, quoted in its entirety, is the Commission’s sole justification for its decision.

In its petition to this court, Midwestern argues that the Commission’s decision is discriminatory because its effect will misallocate costs among Midwestern’s customers by forcing other customers to bear those fixed costs of the system that cannot be charged to minimum bill customers. Midwestern also argues that those increased commodity rates that will result from the Commission’s decision will impair its ability to compete with pipelines who purchase gas directly from producers, and is thus discriminatory and contrary to the asserted pro-competitive rationale of the rule. Finally, Midwestern argues that the decision is directly contrary to the Commission’s “as-billed” principle, which governs the allocation of upstream pipeline charges in downstream pipeline rates. This principle provides that “the cost classification, allocation, and rate design methodology specified by the Commission for that pipeline supplier governs the classification of these costs by the recipient interstate pipeline.” Northwest Alaskan Pipeline Co., 11 FERC If 61,088 at 61,182, reh’g denied, 11 FERC U 61,302 (1980).

The Commission’s sole response to these arguments is that it considers all of the upstream pipeline’s charges to be purchased gas costs and “[t]o treat purchased gas costs in any other manner would constitute a departure from consistent rate design practice.” Order No. 380-A at 33, J.A. at 1488. The Commission has provided no explanation regarding the apparent inconsistency between the “as-billed” principle and this undefined “consistent rate design practice.” The Commission has given no rational explanation for its departure from the clear objective stated in Order No. 380 to exempt fixed cost recovery through minimum bills from that decision. The Commission does not discuss Midwestern’s facially valid argument that it will be placed at a competitive disadvantage if the upstream fixed costs are recovered from all of its customers through increased commodity rates. The Commission has not explained its apparent conclusion that Midwestern’s minimum bill customers should be relieved of their obligation to pay their share of the fixed costs of the upstream segment of the system while other pipelines’ minimum bill customers must pay their share of the fixed costs of the entire

system. In short, the Commission has not given a reasoned explanation for its decision but has merely stated its conclusion. Under these circumstances, we are unable to reach a decision as to the validity of the Commission’s decision, and we certainly cannot conclude from the record that the Commission has “examine[d] the relevant data and articulate[d] a satisfactory explanation for its action, including a ‘rational connection between the facts found and the choice made.’ ” Motor Vehicle Manufacturer’s Association v. State Farm Mutual Automobile Insurance Co., 463 U.S. 29, 43, 103 S.Ct. 2856, 2866, 77 L.Ed.2d 443 (1983) (quoting Burlington Truck Lines, Inc. v. United States, 371 U.S. 156, 168, 83 S.Ct. 239, 245, 9 L.Ed.2d 207 (1962)). Therefore, we remand this issue to the Commission for reconsideration. On remand, the Commission is directed to address any issues raised here, and any other arguments that may be advanced, and to provide a rational and reasoned explanation for the ultimate disposition of this issue.

IV. Procedural Objections

Petitioners contend the Commission abused its discretion by engaging in informal notice and comment rulemaking because (1) the unique factual circumstances advanced by each pipeline merited individualized case-by-case adjudication; and (2) notice and comment rulemaking cannot produce the “substantial evidence” required by section 19 of the NGA.

A. Choice Between Rulemaking and Adjudication

It is a well-settled principle of administrative law that the decision whether to proceed by rulemaking or adjudication lies within the broad discretion of the agency. See SEC v. Chenery Corp., 332 U.S. 194, 202-03, 67 S.Ct. 1575, 1580-81, 91 L.Ed. 1995 (1947) (“[A]n administrative agency must be equipped to act either by general rule or individual order. To insist upon one form of action to the exclusion of the other is to exalt form over necessity____ [T]he choice made between proceeding by general rule or by individual, ad hoc litigation is one that lies primarily in the informed discretion of the administrative agency.”). This deference is particularly appropriate in this case, where “the breadth and complexity of the Commission’s responsibilities demand that it be given every reasonable opportunity to formulate methods of regulation appropriate for the solution of its intensely practical difficulties.” Permian Basin Area Rate Cases, 390 U.S. 747, 790, 88 S.Ct. 1344, 1372, 20 L.Ed.2d 312 (1968).

The decision by the Commission to proceed by rulemaking rather than through case-by-case adjudication clearly passes muster under our deferential standard of review. The petitioners’ vague and condusory assertions that each of their peculiar circumstances render a generic rulemaking inappropriate merely echo their substantive quarrel with the reasonability of the Commission’s decision. As we have established, substantial evidence supports the Commission’s conclusion that minimum bills and minimum take provisions have two industry-wide effects; minimum bills can result in the recovery of unincurred costs and are anticompetitive. The generalized nature of the problems addressed, therefore, did not require trial-type procedures appropriate for retrospective determination of specific facts about individual parties. Rather, notice and comment rulemaking, particularly appropriate for determination of legislative facts and policy of general, prospective applicability, was a manifestly reasonable method of addressing the systemic problems of the natural gas market. See National Small Shipments Traffic Conference, Inc. v. ICC, 725 F.2d 1442, 1447-48 (D.C.Cir.1984). See also Trans-Pacific Freight Conference of Japan/Korea v. Federal Maritime Commission, 650 F.2d 1235, 1245 (D.C.Cir.1980) (“Rulemaking permits more precise definition of statutory standards than would otherwise arise through protracted piecemeal litigation of particular issues.”), cert. denied, 451 U.S. 984, 101 S.Ct. 2315, 68 L.Ed.2d 840 (1981).

B. Informal Rulemaking and the Substantial Evidence Requirement of Section 5 of the Natural Gas Act

Relying on Mobil Oil Corp. v. FPC, 483 F.2d 1238 (D.C.Cir.1973), several petitioners contend that the “substantial evidence” standard of review mandated by section 19 of the NGA cannot be satisfied through informal notice and comment rule-making. In Mobil Oil, this court stated that informal notice and comment rulemaking “cannot create a record that satisfies the substantial evidence test.” Id. at 1260. The court held:

In the type of proceeding on which the Commission eventually embarked, the standard of evidence which a reviewing court must have before it to sustain the agency’s action is “substantial evidence” as called for by the basic statute here involved, the Natural Gas Act. The procedures required to develop this “substantial evidence” are not necessarily the strict adversary procedures of sections 556 and 557 of the Administrative Procedure Act, but, considering the ultimate decision which the Commission issued, should have embraced considerably more in the way of adversary procedures than those simple requisites of section 553 which were assumed sufficient here.

Id. at 1264.

There are two possible readings of the Mobil Oil case. First, the holding of the case could be limited to the facts presented: because interested parties were not provided with adequate notice, the written submissions did not provide substantial evidence in the record for the ultimate decision which the Commission issued. Second, the case could be read to mandate, in all rulemakings in which “substantial evidence” is required, something more than section 553 informal proceedings. It is for this latter proposition that the petitioners here cite the case.

The petitioners’ reading of Mobil Oil is a fair one. The case, however, is no longer good law. Mobil Oil proceeds from an assumption, long held by this court, that “ ‘procedural requirements deemed inherent in the very concept of fair hearing’ ” could be fashioned by the court “ ‘even though no such requirements had been specified by Congress.’ ” Id. at 1252 (quoting American Airlines Inc. v. CAB, 359 F.2d 624, 632 (D.C.Cir.), cert. denied, 385 U.S. 843, 87 S.Ct. 73, 17 L.Ed.2d 75 (1966)). A unanimous Supreme Court, however, rejected this principle with great force and clarity in Vermont Yankee Nuclear Power Corp. v. NRDC, 435 U.S. 519, 98 S.Ct. 1197, 55 L.Ed.2d 460 (1978). In Vermont Yankee, the Court found that nothing “permitted the court to review and overturn the rulemaking proceeding on the basis of the procedural devices employed (or not employed) by the Commission so long as the Commission employed at least the statutory minima.” Id. at 548, 98 S.Ct. at 1214.

Although the Mobil Oil case has been cited without disapproval by this court in recent cases, to the extent that it imposes procedural requirements not required by the Natural Gas Act or the Administrative Procedure Act it cannot survive Vermont Yankee. Furthermore, as we specifically held in American Public Gas Association v. FPC, 567 F.2d 1016 (D.C.Cir.1977), the “substantial evidence” provision in the Natural Gas Act does not affect the procedure the Commission is required to follow:

We have not overlooked the contention that the provision of the Natural Gas Act requiring substantial evidence to support an essential element of the Commission’s order, Permian, 390 U.S. at 792, 88 S.Ct. 1344 [at 1373], calls for a trial-type hearing. Section 19(b) of the Natural Gas Act, 15 U.S.C. § 717r(b). In our view, however, this requirement, found in the judicial review provision of the Act, does not dictate the procedure to be followed, or the nature of the hearing to be held. It has to do with a court’s review of the adequacy vel non of the evidence relied upon to support a finding, whatever the kind of hearing. True it may be that when rulemaking is based on written submissions the weight to be accorded the evidence may be affected by that method of presentation, but the standard of substantial evidence may be satisfied by written submissions.

Id. at 1067. The notice and comment rule-making employed by the Commission, therefore, satisfies the procedural requirements of both the Natural Gas Act and the Administrative Procedure Act.

V. Conclusion

For the foregoing reasons, Orders No. 380, 380-A-D, are affirmed. The “Downstream Pipeline Issue” is remanded to the Commission for proceedings consistent with this opinion.

So ordered. 
      
      . Elimination of Variable Costs from Certain Natural Gas Pipeline Minimum Commodity Bill Provisions, Order No. 380, 27 FERC ¶ 61,318; Order No. 380-A, 28 FERC ¶ 61,175; Order No. 380-C, 29 FERC 61,077; and Order No. 380-D, 29 FERC ¶ 61,332 (1984).
      In Order No. 380-A, the Commission addressed arguments raised on rehearing and stayed the effect of the rule on minimum take tariff provisions pending further comments. In Order No. 380-B, the Commission denied rehearing of Order No. 380-A. In Order No. 380-C, the Commission discussed comments on the minimum take issue and decided that its rule should also nullify those tariff provisions. In Order No. 380-D, the Commission denied rehearing of Order No. 380-C.
     
      
      . One reason for including some of the fixed costs in the "commodity" charge is that some customers, called "interruptible customers,” do not pay a "demand” charge. These customers, unlike so-called “firm customers,” are not contractually entitled to demand specific amounts of natural gas. Interruptible customers may purchase only the gas not demanded by firm customers and typically pay only a commodity charge for amounts actually taken.
     
      
      . Unless otherwise specified, the term "minimum bill" refers to both minimum commodity bills and minimum take provisions.
     
      
      . See generally Atlantic Seaboard Corp. v. FPC, 404 F.2d 1268 (D.C.Cir.1968); Lynchburg Gas Co. v. FPC, 336 F.2d 942 (D.C.Cir.1964).
     
      
      . The significant differences between take-or-pay contracts and minimum bills are discussed infra p. 1159 (“Harm to Pipelines — The Take-or-Pay Issue”).
     
      
      . A simple example may illustrate the impact of the regulation upon a pipeline’s tariff. Suppose a customer’s demand charge, set in ratemaking, is a flat $1,000,000 a month. Pursuant to the commodity charge, the pipeline charges $4.00 per million cubic feet (mcf) of gas taken. Of the $4.00, $3.50 is for purchased gas costs, $.47 is for fixed costs, and $.03 is for non-gas variable costs. In a given month, the customer takes 2.5 million mcf, but the tariff provides for a minimum bill requirement of 3 million mcf. Before the implementation of the Commission’s rule, the customer's bill would be computed in the following fashion:
      Demand charge: $ 1,000,000
      Commodity charge:
      $4.00 x 3 million mcf 12,000,000
      Total $13,000,000
      Under the Commission’s rule, the minimum bill could not be used to recover variable costs, and the tariff would be computed in the following fashion:
      Demand charge: $ 1,000,000
      Commodity charge:
      $3.50 (purchase gas costs)
      X 2.5 million mcf 8,750,000
      .03 (non-gas variable costs)
      X 2.5 million mcf 75,000
      .47 (fixed costs)
      X 3.0 million mcf 1,410,000
      $10,235,000
      Total: $11,235,000
     
      
      . Arguments raised in this appeal that are not expressly addressed have been considered and determined to be without merit.
     
      
      . Congress ratified this holding in the Department of Energy Organization Act, 42 U.S.C. § 7173(c) (1982): “Any function ... which relates to the establishment of rates and charges under the ... Natural Gas Act .... may be conducted by rulemaking procedures." Petitioners’ claims that the Commission is without the power to exercise section 5 authority by generic rulemaking are therefore completely without merit. Petitioners’ claims that the Commission has abused its discretion by proceeding by rule and not through case-by-case adjudication are discussed infra p. 1166 ("Choice Between Rulemaking and Adjudication”).
     
      
      . We reject petitioners’ contentions that the elimination of minimum bills effects an unlawful revocation of certificated service authorized under section 7 of the NGA. Section 7, which vests in the Commission control over the conditions under which gas may initially be dedicated to public use, does not guarantee that the initial terms of that service will never change. See Atlantic Refining Co. v. Public Service Commission of New York, 360 U.S. 378, 389, 79 S.Ct. 1246, 1253, 3 L.Ed.2d 1312 (1959). Even assuming arguendo that the Commission has no authority to amend or revoke certificated service in a section 5 proceeding, the elimination of minimum bills has no effect on the pipeline’s authorized service. The Order merely addresses the rates the pipeline may charge its customers and therefore was properly issued pursuant to section 5.
      Petitioners also contend that the Order unlawfully alters the terms of existing contracts by destroying the mutuality of obligations between the pipeline and the partial requirements customer. This claim is frivolous. Fixed costs are still recoverable from partial requirements customers through the demand charges and through the fixed cost portions of the minimum bill. At any rate, section 5 gives the Commission authority to alter terms of any existing contract found to be "unjust” or “unreasonable.” 15 U.S.C. § 717d(a). See also Permian Basin Area Rate Cases, 390 U.S. 747, 783-84, 88 S.Ct. 1344, 1368-69, 20 L.Ed.2d 312 (1968) (rejecting gas producers' argument that Commission action might destroy the contracts in which unjust price escalator clauses were found, holding that “the Commission has plenary authority to limit or to proscribe contractual arrangements that contravene the relevant public interests").
     
      
      . Wisconsin Distributors Group consists of a number of ANR’s pipeline customers.
     
      
      . 15 U.S.C. § 717b provides in relevant part: "[N]o person shall export ... or import any natural gas ... without first having secured an order of the Commission authorizing it to do so.”
     
      
      . See Pub.L. No. 95-91, 91 Stat. 565 (Aug. 4, 1977), codified at 42 U.S.C. §§ 7151, 7172.
     
      
      . Delegation Order No. 0204-54, 44 Fed.Reg. 56,735.
     
      
      . Id.
      
     
      
      . For a detailed discussion of the substantial evidence and arbitrary and capricious tests, see Association of Data Processing Service Organizations, Inc. v. Board of Governors of the Federal Reserve System, 745 F.2d 677 (D.C.Cir.1984).
     
      
      . For more elaborate discussion of the standard of review of agency actions under the Act, 
        see generally Permian Basin Area Rate Cases, 390 U.S. 747, 791-92, 88 S.Ct. 1344, 1372-73, 20 L.Ed.2d 312 (1968); West Virginia Public Services Commission v. United States Department of Energy, 681 F.2d 847, 852-53 (D.C.Cir.1982).
     
      
      . Several petitioners argued that if the Commission’s concern is the possibility of windfall profits, a more finely tailored remedy would be to require pipelines to credit those sums not actually incurred back to customers through a purchased gas cost adjustment filing. The Commission reasonably found, however, that such an accounting is an unacceptable alternative because it would benefit all customers equally, thus overcompensating those who do not incur minimum bill liability and undercompensating those who do. Order No. 380 at 17, J.A. at 808.
     
      
      . Several petitioners argue that even if the Commission's rationale supports its decision with respect to minimum bills, it cannot support application of the rule to minimum take provisions because "in contrast to minimum bills, there is no amount paid for gas not taken, no receipt of money for costs not incurred, and no argument that the purchaser is paying more than a just and reasonable rate for the gas it purchases." Brief for Arkansas Louisiana Gas Co. (ARKLA) at 24. This argument is without merit. As a practical matter, there is no difference between the two contract provisions because in the case of the minimum bill, customers rarely pay for gas not taken. More importantly, there is no difference between the two types of clauses with respect to the Commission’s rationale for the rule; both provisions have the same negative impacts on the natural gas market. Although minimum take provisions do not require customers to pay for gas that they never receive, the provisions, perhaps more so than minimum bills, impede price competition among pipelines. A minimum take customer must physically take a minimum quantity of gas, thereby foregoing a cheaper alternative. Thus, the anti-competitive effects of the minimum take provisions are the same as those of minimum bills, and the Commission’s rationale properly applies to both.
     
      
      . See J.A. at 23, 35-36, 95-97, 164-65, 189-90, 193-94, 212, 299-300, 309-11, 814 n. 28.
     
      
      . Similarly, petitioner Algonquin Gas Transmission Co. asserts that minimum bills should be allowed because they insulate pipelines from competition. Brief for Algonquin at 35. Algonquin, like other pipelines, essentially concedes that the rule will have its intended impact of forcing it and other pipelines to be more responsive to market conditions.
     
      
      . The Commission, therefore, reasonably denied ARKLA’s request for a waiver from Rule 380. See Order No. 380-A at 60-62, J.A. at 1515-17.
     
      
      . The Commission recognized, however, that pipelines incur carrying costs during this makeup period and that these costs may be recovered in the pipelines’ rates. The Commission reasonably determined, however, that the concern that full requirements customers would bear a disproportionate share of these costs could best be addressed in individual rate cases. Given the deference appropriate to the Commission’s choice of procedures, we cannot conclude that the deferral of "whether and under what circumstances take-or-pay carrying costs should be allocated separately from other costs,” Order No. 380 at 44, J.A. at 835, was an abuse of discretion.
     
      
      . See supra note 22 (discussing Commission’s intention to determine, on a case-by-case basis, the allocation of take-or-pay liabilities among partial and full requirements customers).
     
      
      . We also conclude that the Commission properly denied waiver requests from petitioners Great Lakes and Transwestern Pipeline Co. in Order No. 380-A. The concerns raised by Great Lakes and Transwestern — exposure to take-or-pay liability, for example — were shared by most pipelines and adequately addressed in Order No. 380. See Order No. 380-A at 15-21, J.A. at 1470-76 (rejecting Great Lakes’ request for a waiver); Order No. 380-A at 49-60, J.A. at 1504-1515 (rejecting Transwestern’s request for a waiver).
      We emphasize that we affirm only the waiver denials made in the Commission’s Order No. 380 series. Other waiver applications made subsequent to the Order No. 380 series, despite protestations to the contrary, are not included in the present petitions for review and therefore are not properly before this court. See, e.g., Great Lakes Transmission Co., 29 FERC ¶ 61,-135 (1984), reh’g denied, 30 FERC ¶ 61,263 (1985) (denying waiver requests filed by Great Lakes, MIGC, and Midwestern).
      Similarly, petitioner Pacific Interstate Offshore Co. (PIOC) currently has a waiver application pending before the Commission. Should PIOC be dissatisfied with the Commission’s resolution of the issue, it can appeal the denial of the exemption. We find it inappropriate to determine the issue raised by PIOC until the Commission in the first instance has had an opportunity to rule on whether PIOC's unique circumstances warrant exemption.
     
      
      . Algonquin claims that the orders under review are unlawfully discriminatory under sections 4 and 5 of the Act, Brief for Algonquin at 52, while Transwestern and Great Lakes contend that the exemption is arbitrary and capricious. Brief for Transwestern at 47-49; Brief for Great Lakes at 49-52.
     
      
      . Agreement Between the United States of America and Canada on Principles Applicable to the Northern Natural Gas Pipeline, 29 U.S.T. 3581, T.I.A.S. No. 9030.
     
      
      . Decision and Report by Congress on the Alaska Natural Gas Transportation System (Sept. 22, 1977), ratified H.J.Res. 621, Pub.L. No. 95-158, 91 Stat. 1268, 95th Cong., 1st Sess. (Nov. 8, 1977).
     
      
      . Northwest Alaskan Pipeline Co., 11 FERC ¶ 61,302 at 61,605 (June 20, 1980).
     
      
      . Brief for Algonquin at 50-52; Brief for Great Lakes at 49-52; Brief for Transwestern at 47-49.
     
      
      . See supra note 28.
     
      
      . The Commission did not address the downstream pipeline issue in its brief to this court.
     
      
      . On August 14, 1984, Midwestern filed with the Commission a petition for a limited waiver of Order No. 380. In this petition, Midwestern sought permission to include a provision in its tariff directly assigning the fixed costs in Tennessee’s commodity rates to the appropriate customers. The Commission denied the petition as prematurely raised and concluded that if a misallocation of costs does actually occur, the affected customers could file a complaint under section 5 alleging undue preference or discrimination, or alternatively, Midwestern could submit a proposed allocation of costs in its next rate filing. Order on Petitions to Permit Waiver of Commission Rule, 29 FERC If 61,135 at 61,-277 (1984). Again, we wish to emphasize that this petition is not properly before this court, see supra note 24, and is in no way affected by our decision here. We address only Midwestern’s challenge to the Commission’s decision in Order No. 380-A that upstream fixed costs cannot be included in Midwestern's minimum bill. This argument is not premature because the Commission’s decision presently precludes any upstream fixed-cost component in Midwestern's minimum bill. See 15 U.S.C. § 717r (1982).
     
      
      . Petitioner Great Lakes also contends the Notice of Proposed Rulemaking did not give "a description of the subjects or issues involved,” 5 U.S.C. § 553(b)(3), sufficient to afford "interested parties a reasonable opportunity to participate in the rulemaking.” Trans-Pacific Freight Conference of Japan/Korea v. Federal Maritime Comm’n, 650 F.2d 1235, 1248 (D.C.Cir.1980), cert. denied, 451 U.S. 984, 101 S.Ct. 2315, 68 L.Ed.2d 840 (1981). Brief for Great Lakes at 35-36. This claim is frivolous. Although Great Lakes initially seemed to be under the impression that the proposed rule covered only situations in which pipelines incurred take-or-pay liability, see J.A. at 116, an impression not shared by the other 94 interested parties, it exercised its opportunity to participate in the rulemaking by submitting extensive initial and reply comments. See J.A. at 112-35, 722-30, 998-1027, 1648-69.
     
      
      . MIGC, for example, states that the overrecovery rationale does not apply to it because any payments under its minimum bill "would reflect, at least in part, costs that are incurred under the take-or-pay or take-and-pay clauses in MIGC’s contracts with its suppliers.” Brief for MIGC, Inc. at 31. Take-or-pay clauses, however, are hardly unique; the Commission received substantial comments on and devoted a considerable amount of attention to the take-or-pay issue. See discussion supra p. 1159 ("Harm to Pipelines — The Take-Or-Pay Issue”).
     
      
      . Great Lakes’ contentions that the Commission has violated its due process rights, Brief for Great Lakes at 45-46, therefore, are completely without merit. Compare Londoner v. Denver, 210 U.S. 373, 28 S.Ct. 708, 52 L.Ed. 1103 (1908) (individualized public works assessments require individual hearings), with Bi-Metallic Investment Co. v. State Board of Equalization, 239 U.S. 441, 36 S.Ct. 141, 60 L.Ed. 372 (1915) (general community-wide tax increases do not).
     
      
      . Indeed, case-by-case adjudication of the minimum bill issue may have been entirely inappropriate. First, if the Commission determined in a particular case that a pipeline’s minimum bill was "unjust” and "unreasonable,” that pipeline would be subjected to competition from other pipelines whose minimum bills had not yet been prohibited by the Commission. Second, the Commission would be open to the objection that it was unfairly effectuating a general policy change without the necessary, industry-wide data and commentary. See United States v. Florida East Coast Ry. Co., 410 U.S. 224, 245, 93 S.Ct. 810, 821, 35 L.Ed.2d 223 (1973) (rulemaking is generally the appropriate method for promulgating policy-type rules and standards).
     
      
      . 15 U.S.C. § 717r (1982) ("The finding of the Commission as to the facts, if supported by substantial evidence, shall be conclusive.”).
     
      
      . In American Public Gas Ass’n v. FPC, 498 F.2d 718, 723 (D.C.Cir.1974), for example, we distinguished Mobil Oil on these grounds: "In the Mobil Oil case there was no adequate notice, and much of the data relied upon by the Commission was provided in an informal and to some extent ex parte conference, as distinguished from an adversary setting." As we later recognized, the American Public Gas case is "otherwise in conflict with the hearing discussion in Mobil." American Public Gas Ass’n v. FPC, 567 F.2d 1016, 1066 (D.C.Cir. 1977).
     
      
      . See City of Ukiah v. FERC, 729 F.2d 793, 799 (D.C.Cir.1984); Iowa State Commerce Comm'n v. Office of Federal Inspector, 730 F.2d 1566, 1574 (D.C.Cir.1984).
     
      
      . See also Public Systems v. FERC, 606 F.2d 973, 979 n. 32 (D.C.Cir.1979) (substantial evidence requirement in the Natural Gas Act "carries no implications for procedures to be followed by the Commission in compiling the record”). The Supreme Court in United States v. Florida East Cowrt Ry. Co., 410 U.S. 224, 93 S.Ct. 810, 35 L.Ed.2d 223 (1973), made a similar observation concerning an amendment to the Interstate Commerce Act: “Congress ... specified necessary components of the ultimate decision, but it did not specify the method by which the Commission should acquire information about those components.” Id. at 235, 93 S.Ct. at 816.
     
      
      . The American Public Gas case also disposes of petitioners' related contention that the "after a hearing” requirement found in § 5 of the NGA, 15 U.S.C. § 717d (1982), cannot be satisfied through less than formal, trial-type hearings. In American Public Gas, the Commission gave interested parties an opportunity to participate through appropriate submissions but did not provide an opportunity to cross-examine or examine under oath other parties who had made submissions. 567 F.2d at 1064. This procedure, the court held, satisfied the hearing requirement of the Natural Gas Act. Id. at 1067.
     