author:
Mr. Justice Harlan
      MR. Justice Douglas,

text:
    PERMIAN BASIN AREA RATE CASES.
    Argued December 5-7, 1967.
    Decided May 1, 1968.

      Richard A. Solomon argued the cause for the Federal Power Commission. With him on the brief were Solicitor General Marshall, Ralph S. Spritzer, Richard A. Posner, Peter H. Schiff, Leo E. Forquer, David J. Bardin and Alan J. Roth.

      J. Calvin Simpson argued the cause for the Public Utilities Commission of California; Malcolm H. Furbush argued the cause for the Pacific Gas & Electric Co.; John Ormasa argued the cause for the Pacific Lighting Gas Supply Co. et al., and C. Hayden Ames argued the cause for the San Diego Gas & Electric Co., all in support of the order of the Federal Power Commission. With Mr. Simpson on the brief for the Public Utilities Commission of California was Mary Moran Pajalich. With Messrs. Furbush, Ormasa and Ames on the brief for Pacific Gas & Electric Co. et al. was Frederick T. Searls. Roger Arnebergh filed a brief for the City of Los Angeles, and Edward T. Butler and Thomas M. O’Connor filed a brief for the City of San Diego and the City and County of San Francisco, in support of the order of the Federal Power Commission.

      Bruce R. Merrill argued the cause for the Continental Oil Co.; Crawford C. Martin, Attorney General, argued the cause for the State of Texas; Boston E. Witt, Attorney General, argued the cause for the State of New Mexico; Herbert W. Varner argued the cause for the Superior Oil Co.; Robert W. Henderson argued the cause for the Hunt Oil Co. et al.; J. Evans Attwell argued the cause for Bass et al.; Justin R. Wolf argued the cause for the Standard Oil Co. of Texas; James L. Armour argued the cause for the Mobil Oil Corp.; Louis Flax argued the cause for the Sun Oil Co., and Carroll L. Gilliam and Oliver L. Stone argued the cause for the Amerada Petroleum Corp. et al., all in opposition to the order of the Federal Power Commission. With Mr. Merrill on the brief for the Continental Oil Co. et al. were Thomas H. Burton, Cecil N. Cook, Neal Powers, Jr., and Lloyd F. Thcmhouser. With Messrs. Martin and Witt on the brief for the State of Texas et al. were George M. Cowden, First Assistant Attorney General of Texas, Houghton Brownlee, Jr., Linward Shivers and C. Daniel Jones, Jr., Assistant Attorneys General of Texas, A. J. Carubbi, Jr., and William J. Cooley, Special Assistant Attorney General of New Mexico. With Mr. Varner on the brief for the Superior Oil Co. were Homer J. Penn and Murray Christian. With Mr. Henderson on the brief for the Hunt Oil Co. et al. were Paul W. Hicks and Donald K. Young. With Mr. Attwell on the brief for Bass et al. was W. H. Drushel, Jr. With Mr. Wolf on the brief for the Standard Oil Co. of Texas was Francis R. Kirkham. With Mr. Armour on the brief for Mobil Oil Corp. et al. were Thomas P. Hamill, Robert D. Haworth and William H. Tabb. With Mr. Flax on the brief for the Sun Oil Co. were Phillip D. Endom and Robert E. May. With Messrs. Gilliam and Stone on the brief for the Amerada Petroleum Corp. et al. were Joseph W. Morris, Edwin S. Nail, Edward J. Kremer, Jr., Robert E. Wade, Bernard A. Foster, Jr., Graydon D. Luthey, Warren M. Sparks, Martin E. Erck, Clayton L. Orn, Joseph F. Diver, H. Y. Rowe, W. W. Heard, J. P. Hammond, T. C. McCorkle, William H. Emerson, Kenneth Heady, John R. Rebman, Jerome M. Alper, Thomas G. Johnson, Charles E. McGee, Sherman S. Poland, Richard F. Remmers, Homer E. McEwen, Jr., William K. Tell, Jr., William R. Slye and John C. Snodgrass. John Davenport filed a brief for Texas Independent Producers & Royalty Owners Association et al., in opposition to the order of the Federal Power Commission.
    Briefs of amici curiae were filed by Louis J. Lefkowitz, Attorney General of New York, Kent H. Brown and
      Morton L. Simons for the Public Service Commission of the State of New York; by J. David Mann, Jr., John E. Holtsinger, Jr., Bertram D. Moll, William T. Coleman, Jr., Robert W. Maris, C. William Cooper, Edward S. Kirby, James R. Lacey, Edwin F. Russell, Jr., Barbara M. Suchow, John W. Glendening, Jr., John S. Schmid and Dale A. Wright for the Associated Gas Distributors Group, and by Vincent P. McDevitt and Samuel Graff Miller for the Philadelphia Electric Co.

      No. 90, Continental Oil Co. et al. v. Federal Power Commission; No. 95, Superior Oil Co. v. Federal Power Commission; No. 98, New Mexico et al. v. Federal Power Commission; No. 99, Sun Oil Co. v. Federal Power Commission et al.; No. 100, California et al. v. Skelly Oil Co. et al.; No. 101, Hunt Oil Co. et al. v. Federal Power Commission; No. 102, Pacific Gas & Electric Co. et al. v. Skelly Oil Co. et al.; No. 105, Bass et al. v. Federal Power Commission; No. 117, Federal Power Commission v. Skelly Oil Co. et al.; No. 181, City of Los Angeles v. Skelly Oil Co. et al.; No. 261, City and County of San Francisco v. Skelly Oil Co. et al.; No. 262, City of San Diego v. Skelly Oil Co. et al.; No. 266, Standard Oil Co. of Texas, a Division of Chevron Oil Co. v. Federal Power Commission; and No. 388, Mobil Oil Corp. et al. v. Federal Power Commission.

   Mr. Justice Harlan

delivered the opinion of the Court.

These cases stem from proceedings commenced in 1960 by the Federal Power Commission under § 5 (a) of the Natural Gas Act, 52 Stat. 823, 15 TJ. S. C. § 717d (a), to determine maximum just and reasonable rates for sales in interstate commerce of natural gas produced in the Permian Basin. 24 F. P. C. 1121. The Commission conducted extended hearings, and in 1965 issued a decision that both prescribed such rates and provided various ancillary requirements. 34 F. P. C. 159 and 1068. On petitions for review, the Court of Appeals for the Tenth Circuit sustained in part and set aside in part the Commission's orders. 375 F. 2d 6 and 35. Because these proceedings began a new era in the regulation of natural gas producers, we granted certiorari and consolidated the cases for briefing and extended oral argument. 387 U. S. 902, 388 U. S. 906, 389 U. S. 817. For reasons that follow, we reverse in part and affirm in part the judgments of the Court of Appeals, and sustain in their entirety the Commission's orders.

I.

The circumstances that led ultimately to these proceedings should first be recalled. The Commission’s authority to regulate interstate sales of natural gas is derived entirely from the Natural Gas Act of 1938. 52 Stat. 821. The Act’s provisions do not specifically extend to producers or to wellhead sales of natural gas, and the Commission declined until 1954 to regulate sales by independent producers to interstate pipelines. Its efforts to regulate such sales began only after this Court held in 1954 that independent producers are “natural-gas compan [ies]” within the meaning of § 2 (6) of the Act. 15 U. S. C. § 717a (6); Phillips Petroleum Co. v. Wisconsin, 347 U. S. 672. The Commission has since labored with obvious difficulty to regulate a diverse and growing industry under the terms of an ill-suited statute.

The Commission initially sought to determine whether producers’ rates were just and reasonable within the meaning of §§ 4 (a) and 5 (a) by examination of each producer’s costs of service. Although this method has been widely employed in various rate-making situations, it ultimately proved inappropriate for the regulation of independent producers. Producers of natural gas cannot usefully be classed as public utilities. They enjoy no franchises or guaranteed areas of service. They are intensely competitive vendors of a wasting commodity they have acquired only by costly and often unrewarded search. Their unit costs may rise or decline with the vagaries of fortune. The value to the public of the services they perform is measured by the quantity and character of the natural gas they produce, and not by -the resources they have expended in its search; the Commission and the consumer alike are concerned principally with “what [the producer] gets out of the ground, not . . . what he puts into it . . . .” FPC v. Hope Natural Gas Co., 320 U. S. 591, 649 (separate opinion). The exploration for and the production of natural gas are thus “more erratic and irregular and unpredictable in relation to investment than any phase of any other utility business.” Id., at 647. Moreover, the number both of independent producers and of jurisdictional sales is large, and the administrative burdens placed upon the Commission by an individual company costs-of-service standard were therefore extremely heavy.

In consequence, the Commission’s regulation of producers’ sales became increasingly laborious, until, in 1960, it was described as the “outstanding example in the federal government of the breakdown of the administrative process.” The Commission in 1960 acknowledged the gravity of its difficulties, and announced that it would commence a series of proceedings under § 5 (a) in which it would determine maximum producers’ rates for each of the major producing areas. One member of the Commission has subsequently described these efforts as “admittedly . . . experimental . . . .” These cases place in question the validity of the first such proceeding.

The perimeter of this proceeding was drawn by the Commission in its second Phillips decision and in its Statement of General Policy No. 61-1. The Commission in Phillips asserted that it possesses statutory authority both to determine and to require the application throughout a producing area of maximum rates for producers’ interstate sales. It averred that the adoption of area maximum rates would appreciably reduce its administrative difficulties, facilitate effective regulation, and ultimately prove better suited to the characteristics of the natural gas industry. Each of these conclusions was reaffirmed in the Commission’s opinion in these proceedings. Its Statement of General Policy tentatively designated various geographical areas as producing units for purposes of rate regulation; in addition, the Commission there provided two series of area guideline prices, which were expected to help to determine “whether proposed initial rates should be certificated without a price condition and whether proposed rate changes should be accepted or suspended.” The Commission consolidated three of the producing areas listed in the Statement of General Policy for purposes of this proceeding.

The rate structure devised by the Commission for the Permian Basin includes two area maximum prices. The Commission provided one area maximum price for natural gas produced from gas wells and dedicated to interstate commerce after January 1, 1961. It created a second, and lower, area maximum price for all other natural gas produced in the Permian Basin. The Commission reasoned that it may employ price functionally, as a tool to encourage discovery and production of appropriate supplies of natural gas. It found that price could serve as a meaningful incentive to exploration and production only for gas-well gas committed to interstate commerce since I960; the supplies of associated and dissolved gas, and of previously committed reserves of gas-well gas, were, in contrast, found to be relatively unresponsive to variations in price. The Commission expected that its adoption of separate maximum prices would both provide a suitable incentive to exploration and prevent excessive producer profits.

The Commission declined to calculate area rates from prevailing field prices. Instead, it derived the maximum just and reasonable rate for new gas-well gas from composite cost data, obtained from published sources and from producers through a series of cost questionnaires. This information was intended in combination to establish the national costs in 1960 of finding and producing gas-well gas; it was understood not to reflect any variations in cost peculiar either to the Permian Basin or to periods prior to 1960. The maximum just and reasonable rate for all other gas was derived chiefly from the historical costs of gas-well gas produced in the Permian Basin in 1960; the emphasis was here entirely local and historical. The Commission believed that the uncertainties of joint cost allocation made it difficult to compute accurately the cost of gas produced in association with oil. It held, however, that the costs of such gas could not be greater, and must surely be smaller, than those incurred in the production of flowing gas-well gas. In addition, the Commission stated that the exigencies of administration demanded the smallest possible number of separate area rates.

Each of the area maximum rates adopted for the Permian Basin includes a return to the producer of 12% on average production investment, calculated from the Commission’s two series of cost computations. The Commission assumed for this purpose that production commences one year after investment, that gas wells deplete uniformly, and that they are totally depleted in 20 years. The rate of return was selected after study of the returns recently permitted to interstate pipelines, but, in addition, was intended to take fully into account the greater financial risks of exploration and production. The Commission recognized that producers are hostages to good fortune; they must expect that their programs of exploration will frequently prove unsuccessful, or that only gas of substandard quality will be found.

The allowances included in the return for the uncertainties of exploration were, however, paralleled by a system of quality and Btu adjustments. The Commission held that gas of less than pipeline quality must be sold at reduced prices, and it provided for this purpose a system of quality standards. The price reduction appropriate in each sale is to be measured by the cost of the processing necessary to raise the gas to pipeline quality; these costs are to be determined by agreement between the parties to the sale, subject to review and approval by the Commission. The Commission ultimately indicated that it would accept any agreement which reflects “a good faith effort to approximate the processing costs involved . . . .” 34 F. P. C. 1068, 1071. In addition, the Commission prescribed that gas with a Btu content of less than 1,000 per cubic foot must be sold at a price proportionately lower than the applicable area maximum, and that gas with a Btu content greater than 1,050 per cubic foot may be sold at a price proportionately higher than the area maximum. The Commission acknowledged that the aggregate revenue consequences of these adjustments could not be precisely calculated, although its opinion denying applications for rehearing provided estimates of the average price reductions that would be necessary. Id., at 1073.

The Commission derived from these calculations the following rates for the Permian Basin. Gas-well gas, including its residue, and gas-cap gas, dedicated to interstate commerce after January 1, 1961, may be sold at 16.5$ per Mcf (including state production taxes) in Texas, and 15.5(4 (excluding state production taxes) in New Mexico. Flowing gas, including oil-well gas and gas-well gas dedicated to interstate commerce before January 1, 1961, may be sold at 14.5(4 per Mcf (including taxes) in Texas, and 13.5(4 per Mcf (excluding taxes) in New Mexico. Further, the Commission created a minimum just and reasonable rate of 9(4 per Mcf for all gas of pipeline quality sold under its jurisdiction within the Permian Basin. It found that existing contracts that included lower rates would “adversely affect the public interest.” FPC v. Sierra Pacific Power Co., 350 U. S. 348, 355. The Commission permitted producers to file under § 4 (d), 15 U. S. C. § 717c (d), for the area minimum rate despite existing contractual limitations, and without the consent of the purchaser.

The Commission acknowledged that area maximum rates derived from composite cost data might in individual cases produce hardship, and declared that it would, in such cases, provide special relief. It emphasized that exceptions to the area rates would not be readily or frequently permitted, but declined to indicate in detail in what circumstances relief would be given.

This rate structure is supplemented by a series of ancillary requirements. First, the Commission provided various special exemptions for producers whose annual jurisdictional sales throughout the United States do not exceed 10,000,000 Mcf. The prices in sales by these relatively small producers need not be adjusted for quality and Btu deficiencies. Moreover, the Commission by separate order commenced a rule-making proceeding to reduce the small producers’ reporting and filing obligations under §§ 4 and 7, 15 U. S. C. §§ 717c, f. 34 F. P. C. 434.

Second, the Commission imposed a moratorium until January 1, 1968, upon filings under § 4 (d) for prices in excess of the applicable area maximum rate. The Commission concluded that such a moratorium was imperative if the administrative benefits of an area proceeding were to be preserved. Further, it permanently prohibited the use of indefinite escalation clauses to increase prevailing contract prices above the applicable area maximum rate.

Finally, the Commission announced that, by further order, it would require refunds of the difference between amounts that individual producers had actually collected in periods subject to refund, and the amounts that would have been permissible under the applicable area rate, including any necessary quality adjustments. Small producers, although obliged to make refunds, are not required to take into account price reductions for quality deficiencies, unless they wish to take advantage of upward adjustments in price because of high Btu content. The Commission rejected the examiner’s conclusion that refunds were appropriate only if the aggregate area revenue actually collected exceeds the aggregate area revenue permissible under the applicable area rates. It held that such a formula would prove both inequitable to purchasers and difficult for the Commission to administer effectively.

On petitions for review, the Court of Appeals for the Tenth Circuit held that the Commission had authority under the Natural Gas Act to impose maximum area rates upon producers’ jurisdictional sales. It sustained, but stayed enforcement of, the Commission’s moratorium upon filings under § 4 (d) in excess of the applicable area maximum rate. It approved both the Commission’s two-price system and its exemptions for small producers. Nonetheless, the court concluded that the Commission failed to satisfy the requirements devised by this Court in FPC v. Hope Natural Gas Co., supra. It held that the Commission had not properly calculated the financial consequences of the quality and Btu adjustments, had not made essential findings as to aggregate revenue, and had not indicated with appropriate precision the circumstances in which relief from the area rates may be obtained by individual producers. 375. F. 2d 6. On rehearing, the court also held that the Commission’s treatment of refunds was erroneous; it concluded that refunds were permissible only if aggregate actual area revenues have exceeded aggregate permissible area revenues, and only to the amount of the excess, apportioned on “some equitable contract-by-contract basis.” The Court of Appeals ordered the cases remanded to the Commission for further proceedings consistent with its opinions. 375 F. 2d 35.

II.

The parties before this Court have together elected to place in question virtually every detail of the Commission’s lengthy proceedings. It must be said at the outset that, in assessing these disparate contentions, this Court’s authority is essentially narrow and circumscribed.

Section 19 (b) of the Natural Gas Act provides without qualification that the “finding of the Commission as to the facts, if supported by substantial evidence, shall be conclusive.” More important, we have heretofore emphasized that Congress has entrusted the regulation of the natural gas industry to the informed judgment of the Commission, and not to the preferences of reviewing courts. A presumption of validity therefore attaches to each exercise of the Commission’s expertise, and those who would overturn the Commission’s judgment undertake “the heavy burden of making a convincing showing that it is invalid because it is unjust and unreasonable in its consequences.” FPC v. Hope Natural Gas Co., supra, at 602. We are not obliged to examine each detail of the Commission’s decision; if the “total effect of the rate order cannot be said to be unjust and unreasonable, judicial inquiry under the Act is at an end.” Ibid.

Moreover, this Court has often acknowledged that the Commission is not required by the Constitution or the Natural Gas Act to adopt as just and reasonable any particular rate level; rather, courts are without authority to set aside any rate selected by the Commission which is within a “zone of reasonableness.” FPC v. Natural Gas Pipeline Co., 315 U. S. 575, 585. No other rule would be consonant with the broad responsibilities given to the Commission by Congress; it must be free, within the limitations imposed by pertinent constitutional and statutory commands, to devise methods of regulation capable of equitably reconciling diverse and conflicting interests. It is on these premises that we proceed to assess the Commission’s orders.

III.

The issues in controversy may conveniently be divided into four categories. In the first are questions of the Commission’s statutory and constitutional authority to employ area regulation and to impose various ancillary requirements. In the second are questions of the validity of the rate structure adopted by the Commission for natural gas produced in the Permian Basin. The third includes questions of the accuracy of the cost and other data from which the Commission derived the two area maximum prices. In the fourth are questions of the validity of the refund obligations imposed by the Commission.

We turn first to questions of the Commission’s constitutional and statutory authority to adopt a system of area regulation and to impose various supplementary requirements. The most fundamental of these is whether the Commission may, consistently with the Constitution and the Natural Gas Act, regulate producers’ interstate sales by the prescription of maximum area rates, rather than by proceedings conducted on an individual producer basis. This question was left unanswered in Wisconsin v. FPC, 373 U. S. 294. Its solution requires consideration of a series of interrelated problems.

It is plain that the Constitution does not forbid the imposition, in appropriate circumstances, of maximum prices upon commercial and other activities. A legislative power to create price ceilings has, in “countries where the common law prevails,” been “customary from time immemorial . . . .” Munn v. Illinois, 94 U. S. 113, 133. Its exercise has regularly been approved by this Court. See, e. g., Tagg Bros. v. United States, 280 U. S. 420; Bowles v. Willingham, 321 U. S. 503. No more does the Constitution prohibit the determination of rates through group or class proceedings. This Court has repeatedly recognized that legislatures and administrative agencies may calculate rates for a regulated class without first evaluating the separate financial position of each member of the class; it has been thought to be sufficient if the agency has before it representative evidence, ample in quantity to measure with appropriate precision the financial and other requirements of the pertinent parties. See Tagg Bros. v. United States, supra; Acker v. United States, 298 U. S. 426; United States v. Corrick, 298 U. S. 435. Compare New England Divisions Case, 261 U. S. 184, 196-199; United States v. Abilene & S. R. Co., 265 U. S. 274, 290-291; New York v. United States, 331 U. S. 284; Chicago & N. W. R. Co. v. A., T. & S. F. R. Co., 387 U. S. 326, 341.

No constitutional objection arises from the imposition of maximum prices merely because “high cost operators may be more seriously affected . . . than others,” Bowles v. Willingham, supra, at 518, or because the value of regulated property is reduced as a consequence of regulation. FPC v. Hope Natural Gas Co., supra, at 601. Regulation may, consistently with the Constitution, limit stringently the return recovered on investment, for investors’ interests provide only one of the variables in the constitutional calculus of reasonableness. Covington & Lexington Turnpike Co. v. Sandford, 164 U. S. 578, 596.

It is, however, plain that the “power to regulate is not a power to destroy,” Stone v. Farmers’ Loan & Trust Co., 116 U. S. 307, 331; Covington Lexington Turnpike Co. v. Sandford, supra, at 593; and that maximum rates must be calculated for a regulated class in conformity with the pertinent constitutional limitations. Price control is “unconstitutional ... if arbitrary, discriminatory, or demonstrably irrelevant to the policy the legislature is free to adopt . . . .” Nebbia v. New York, 291 U. S. 502, 539. Nonetheless, the just and reasonable standard of the Natural Gas Act “coincides” with the applicable constitutional standards, FPC v. Natural Gas Pipeline Co., supra, at 586, and any rate selected by the Commission from the broad zone of reasonableness permitted by the Act cannot properly be attacked as confiscatory. Accordingly, there can be no constitutional objection if the Commission, in its calculation of rates, takes fully into account the various interests which Congress has required it to reconcile. We do not suggest that maximum rates computed for a group or geographical area can never be confiscatory; we hold only that any such rates, determined in conformity with the Natural Gas Act, and intended to “balanc[e] .. . the investor and the consumer interests,” are constitutionally permissible. FPC v. Hope Natural Gas Co., supra, at 603.

One additional constitutional consideration remains. The producers have urged, and certain of this Court’s decisions might be understood to have suggested, that if maximum rates are jointly determined for a group or area, the members of the regulated class must, under the Constitution,- be proffered opportunities either to withdraw from the regulated activity or to seek special relief from the group rates. We need not determine whether this is in every situation constitutionally imperative, for such arrangements have here been provided by the Commission, and we cannot now hold them inadequate.

The Commission declared that a producer should be permitted “appropriate relief” if it establishes that its “out-of-pocket expenses in connection with the operation of a particular well” exceed its revenue from the well under the applicable area price. 34 F. P. C., at 226. It did not indicate which operating expenses would be pertinent for these calculations. The Commission acknowledged that there might be other circumstances in which relief should be given, but declined to enumerate them. It emphasized, however, that a producer’s inability to recover either its unsuccessful exploration costs or the full 12% return on its production investment would not, without more, warrant relief. It announced that in many situations it would authorize abandonment under § 7 (b), 15 U. S. C. § 717f (b), rather than an exception to the area maximum price. Finally, the Commission held that the burden would be upon the producer to establish the propriety of an exception, and that it therefore would not stay enforcement of the area rates pending disposition of individual petitions for special relief.

The Court of Appeals held that these arrangements were inadequate. It found the Commission’s description of its intentions vague. The court would require the Commission to provide “guidelines which if followed by an aggrieved producer will permit it to be heard promptly and to have a stay of the general rate order until its claim for exemption is decided.” 375 F. 2d, at 30. We cannot agree. It would doubtless be desirable if the Commission provided, as quickly as may be prudent, a more precise summary of its conditions for special relief, but it was not obliged to delay area regulation until such guidelines could be properly drawn. The Commission quite reasonably believed that the terms of any exceptional relief should be developed as its experience with area regulation lengthens. Moreover, area regulation of producer prices is avowedly still experimental in its terms and uncertain in its ultimate consequences; it is entirely possible that the Commission may later find that its area rate structure for the Permian Basin requires significant modification. We cannot now hold that, in these circumstances, the Commission’s broad guarantees of special relief were inadequate or excessively imprecise.

Nor is there reason now to suppose that petitions for relief will not be expeditiously evaluated; for the Commission has given assurance that they will be “disposed of as promptly as possible.” If it subsequently appears that the Commission’s provisions for special relief are for any reason impermissibly dilatory, this question may then be reconsidered.

Furthermore, it is pertinent that the Commission may supplement its provisions for special relief by permitting abandonment of unprofitable activities. The producers urge that this source of relief must be disregarded, since it is entirely conditional upon the Commission’s assent. It is enough for present purposes that the Commission has in other circumstances allowed abandonment, and that it has indicated that it will, in appropriate cases, authorize it here. Indeed, the Commission has already acknowledged that only in “exceptional situations” would the abandonment of unprofitable facilities prove detrimental to consumers, and thus impermissible under § 7 (b). 34 F. P. C., at 226.

Finally, we cannot agree that the Commission abused its discretion by its refusal to stay, pro tanto, enforcement of the area rates pending disposition of producers’ petitions for special relief. The Court of Appeals would evidently require the Commission automatically to issue such a stay each time a producer seeks relief. This is plainly inconsistent with the established rule that a party is not ordinarily granted a stay of an administrative order' without an appropriate showing of irreparable injury. See, e. g., Virginia Petroleum Jobbers Assn. v. FPC, 259 F. 2d 921, 925. Moreover, the issuance of a stay of an administrative order pending disposition by the Commission of a motion to “modify or set aside, in whole or in part” the order is a matter committed by the Natural Gas Act to the Commission’s discretion. §§19 (a), (c), 15 U. S. C. §§ 717r (a), (c). We have no reason now to believe that it would in all cases prove an abuse of discretion for the Commission to deny a stay of the area rate order. There might be many situations in which a stay would be inappropriate; at a minimum, the Commission is entitled to give careful consideration to the substantiality of the claim for relief, and to the consequences of any delay in the full administration of the area rate structure. We therefore decline to bind the Commission to any inflexible obligation; we shall assume that it will, in situations in which stays prove appropriate, properly exercise its statutory authority.

For the reasons indicated, we find no constitutional infirmity in the Commission’s adoption of an area maximum rate system for the Permian Basin.

We consider next the claims that the Commission has exceeded the authority given it by the Natural Gas Act. The first and most important of these questions is whether, despite the absence of any constitutional deficiency, area regulation is inconsistent with the terms of the Act. The producers that seek reversal of the judgments below offer three principal contentions on this question. First, they emphasize that the Act uniformly employs the singular to describe those subject to its requirements; § 4 (a), for example, provides that rates received by “any natural-gas company” must be just and reasonable. It is urged that the draftsman’s choice of number indicates that each producer’s rates must be individually computed from evidence of its own financial position. We cannot infer so much from so little; we see no more in the draftsman’s choice of phrase than that the Act’s obligations are imposed severally upon each producer.

Reliance is next placed upon one sentence in the Report of the House Committee on Interstate and Foreign Commerce, which in 1937 recommended passage of the Natural Gas Act. The Committee remarked that the “bill provides for regulation along recognized and more or less standardized lines.” H. R. Rep. No. 709, 76th Cong., 1st Sess., 3. It added that the bill’s provisions included nothing “novel.” Ibid. We find these statements entirely inconclusive, particularly since, as the Committee doubtless was aware, regulation by group or class was a recognized administrative method even in 1937. Compare Tagg Bros. v. United States, supra; New England Divisions Case, supra. See also H. R. Rep. No. 77, 67th Cong., 1st Sess., 10-11; H. R. Rep. No. 456, 66th Cong., 1st Sess., 29-30.

Finally, the producers urge that two opinions of this Court establish the inconsistency of area regulation with the Natural Gas Act. It is asserted that the failure of a majority of the Court to adopt the reasoning of Mr. Justice Jackson’s separate opinion in FPC v. Hope Natural Gas Co., supra, impliedly rejected the system of regulation now selected by the Commission. We find this without force. The Court in Hope emphasized that we may not impose methods of regulation upon the discretion of the Commission; for purposes of judicial review, the validity of a rate order is determined by "the result reached not the method employed.” 320 U. S., at 602; see also FPC v. Natural Gas Pipeline Co., supra, at 586. The Court there did not reject area regulation; it repudiated instead the suggestion that courts may properly require the Commission to employ any particular regulatory formula or combination of formulae.

The producers next rely upon a dictum in the opinion of the Court in Bowles v. Willingham, supra. The Court remarked that “under other price-fixing statutes such as the Natural Gas Act of 1938 . . . Congress has provided for the fixing of rates which are just and reasonable in their application to particular persons or companies.” 321 U. S., at 517. The dictum is imprecise, but even if it were not, we could not agree that it can now be controlling. The construction of the Natural Gas Act was not even obliquely at issue in Bowles, and this Court does not decide important questions of law by cursory dicta inserted in unrelated cases. Whatever the dictum’s meaning, we do not regard it as decisive here. Compare Wisconsin v. FPC, 373 U. S. 294, 310.

There are, moreover, other factors that indicate persuasively that the Natural Gas Act should be understood to permit area regulation. The Act was intended to create, through the exercise of the national power over interstate commerce, “an agency for regulating the wholesale distribution to public service companies of natural gas moving interstate”; Illinois Gas Co. v. Public Service Co., 314 U. S. 498, 506; it was for this purpose expected to “balanc[e] . . . the investor and the consumer interests.” FPC v. Hope Natural Gas Co., supra, at 603. This Court has repeatedly held that the width of administrative authority must be measured in part by the purposes for which it was conferred; see, e. g., Piedmont & Northern R. Co. v. Comm’n, 286 U. S. 299; Phelps Dodge Corp. v. Labor Board, 313 U. S. 177, 193-194; National Broadcasting Co. v. United States, 319 U. S. 190; American Trucking Assns. v. United States, 344 U. S. 298, 311. Surely the Commission’s broad responsibilities therefore demand a generous construction of its statutory authority.

Such a construction is consistent with the view of administrative rate making uniformly taken by this Court. The Court has said that the “legislative discretion implied in the rate making power necessarily extends to the entire legislative process, embracing the method used in reaching the legislative determination as well as that determination itself.” Los Angeles Gas Co. v. Railroad Comm’n, 289 U. S. 287, 304. And see San Diego Land & Town Co. v. Jasper, 189 U. S. 439, 446. It follows that rate-making agencies are not bound to the service of any single regulatory formula; they are permitted, unless their statutory authority otherwise plainly indicates, “to make the pragmatic adjustments which may be called for by particular circumstances.” FPC v. Natural Gas Pipeline Co., supra, at 586.

We are unwilling, in the circumstances now presented, to depart from these principles. The Commission has asserted, and the history of producer regulation has confirmed, that the ultimate achievement of the Commission’s regulatory purposes may easily depend upon the contrivance of more expeditious administrative methods. The Commission believes that the elements of such methods may be found in area proceedings. “[Considerations of feasibility and practicality are certainly germane” to the issues before us. Bowles v. Willingham, supra, at 517. We cannot, in these circumstances, conclude that Congress has given authority inadequate to achieve with reasonable effectiveness the purposes for which it has acted.

We must now consider whether the Commission exceeded its statutory authority by the promulgation of various supplementary requirements. The first of these is its imposition of a moratorium until January 1, 1968, upon filings under § 4 (d) for prices in excess of the applicable area maximum rate. Although the period for which the moratorium was to be effective has expired, the order is not without continuing effect. The Court of Appeals stayed enforcement of the moratorium until final disposition of the petitions for review, and a number of rate increases have therefore become effective subject to invalidation and refund if the moratorium order is now upheld. See Brief for the Federal Power Commission 69, n. 44.

The validity of the moratorium order turns principally upon construction of §§4 and 5 of the Act. Section 4 (d) provides that no modification in existing rate schedules may be made by a natural gas company except after 30 days’ notice to the Commission. When the Commission receives such notice, it is permitted by § 4 (e), upon complaint or on its own motion, to suspend the proposed rate schedule for a period not to exceed five months. The Commission is to employ the period of suspension to conduct hearings upon the lawfulness of the proposed rates. If at the end of the suspension period appropriate orders have not been issued, the proposed rate schedule becomes effective, subject only to a refund obligation. In contrast, § 5 (a) permits the Commission, upon complaint from a public agency or a gas distributing company, or on its own motion, to conduct proceedings to determine whether existing rates are just and reasonable, and to prescribe rates “to be thereafter observed and in force . . . These investigatory powers are not conditional upon the filing by a natural gas company of any proposed change in existing rates.

Certain of the producers urge that §§ 4 and 5 must in combination be understood to preclude moratoria upon filings under § 4 (d). They assert that the period of effectiveness of a rate determination under § 5 (a) is limited by § 4 (e); they reason that § 4 (d) creates an unrestricted right to file rate changes, and that such changes may, under § 4 (e), be suspended for a period no longer than five months. If this construction were accepted, it would follow that area proceedings would terminate in rate limitations that could be disregarded by producers five months after their promulgation. The result, as the Commission observed, would be that “the conclusion of one area proceeding would only signal the beginning of the next, and just and reasonable rates for consumers would always be one area proceeding away.” 34 F. P. C., at 228.

We cannot construe the Commission’s statutory authority so restrictively. Nothing in § 5 (a) imposes limitations of time upon the effectiveness of rate determinations issued under it; rather, the section provides that rates held to be just and reasonable are “to be thereafter observed . . . .” Moreover, this Court has already declined to find in § 4 (d) or § 4 (e) an “invincible right to raise prices subject only to a six-month delay and refund liability.” United Gas v. Callery Properties, 382 U. S. 223, 232 (opinion concurring in part and dissenting in part). Section 4(d) merely requires notice to the Commission as a condition of any modification of existing rates; it provides that a “change cannot be made without the proper notice to the Commission; it does not say under what circumstances a change can be made.” United Gas Co. v. Mobile Gas Corp., 350 U. S. 332, 339. (Emphasis in original.) Nor does § 4 (e) restrict the Commission’s authority under § 6 (a); it permits the Commission to preserve an existing situation pending consideration of a proposed change in rates, and thereafter to issue an order retroactively forbidding the change; but the “scope and purpose of the Commission’s review [under § 5 (a)] remain the same . . . .” Id., at 341.

The deficiencies of the producers’ construction of §§ 4 and 5 are illustrated by United Gas v. Callery Properties, supra. The Court held in Cattery that permanent certifications issued under § 7 may be conditioned, even upon remand, by a moratorium upon filings under § 4 (d) for rates in excess of a specified ceiling. At issue were conditions imposed under § 7 (e) prior to the determination of just and reasonable rates; but nothing in the pertinent statutory provisions suggests that the Commission’s authority under § 5 (a) is more narrow. Indeed, if the producers’ construction of §§4 and 5 were adopted, we should be forced to the uncomfortable result that filings under § 4 (d) may be precluded by the Commission’s relatively summary determination of a provisional in-line price, but not by its formal adjudication, after full deliberation, of a just and reasonable price. The consequences of such a construction would, as the Commission observed, be the enervation of § 5 and the effective destruction of area regulation. We are, in the absence of compelling evidence that such was Congress’ intention, unwilling to prohibit administrative action imperative for the achievement of an agency’s ultimate purposes. We have found no such evidence here, and therefore hold that the Commission may under §§ 5 and 16 restrict filings under § 4 (d) of proposed rates higher than those determined by the Commission to be just and reasonable.

The question remains whether the imposition by the Commission of a moratorium until January 1, 1968, was a permissible exercise of this authority. The Commission found that in 1960 the costs of gas production had recently been, and would foreseeably remain, “remarkably steady”; it reasoned that in these circumstances a moratorium of 2y2 years, subject to “modification of its original decision after appropriate proceedings held in that docket,” would both facilitate orderly administration and satisfactorily assure the protection of producers’ rights. Individual producers would not have been prevented by the moratorium from seeking relief from the maximum area rates; relief would have been possible both through the Commission’s provisions for special exemptions and through motions for modification or termination of the moratorium. This is not a case in which the Commission has sought to bind producers, without recourse and in the face of changing circumstances, to an unchanging rate structure.

We cannot, given the apparent stability of production costs, the Commission’s relative inexperience with area regulation, and the administrative burdens of concurrent area proceedings, hold that this arrangement was impermissible. We need not attempt to prescribe the limitations of the Commission’s authority under §§ 5 and 16 to impose moratoria upon § 4 (d) filings; in particular, we intimate no views on the propriety of moratoria created in circumstances of changing costs. These and other difficult issues may more properly await both clarification of the Commission’s intentions and the necessities of the particular circumstances. We hold only that this relatively brief moratorium did not, in the circumstances here presented, exceed or abuse the Commission’s authority.

A collateral issue of statutory authority must be considered. The Commission supplemented its moratorium by prohibiting price increases that exceed the area maximum rates, if the increases are the products of certain varieties of contractual price escalation clauses. Unlike the more general moratorium upon filings under § 4 (d), this proscription is without limit of time. The Commission’s order is applicable to the most-favored-nation, spiral escalation, and redetermination clauses that in 1961 it entirely forbade in contracts executed on or after April 3, 1961; the additional limitation provided here by the Commission was intended to restrict the use of clauses included in contracts executed before the date of effectiveness of the Commission’s earlier orders. The Commission reasoned, as had the examiner, that to permit producers to breach the area maximum rates by implementation of such clauses would not be “in accordance with the principles upon which a rate structure should be based.” 34 F. P. C., at 236.

Indefinite escalation clauses “cause price increases . . . to occur without reference to the circumstances or economics of the particular operation, but solely because of what happens under another contract.” 34 F. P. C., at 373. There is substantial evidence that in design and function they are “incompatible with the public interest . . . .” Order No. 232, 25 F. P. C. 379, 380. Indeed, this Court has already entirely sustained the Commission’s 1962 order. FPC v. Texaco, 377 U. S. 33.

The producers do not suggest that the Commission and Court were there mistaken; they urge instead that the Commission has acted inconsistently with its decision in Pure Oil Co., 25 F. P. C. 383, and that it has wrongly invalidated existing contracts. The Commission declined in Pure Oil to declare unenforceable escalation clauses included in previously executed contracts. It reasoned that since the contracts lacked severability provisions, to strike the escalation clauses would, under “familiar principles of law,” destroy the contracts; it feared that this would prove “many times” more prejudicial to the public interest than would the escalation clauses. Id., at 388-389. The producers assert that the Commission has now committed the error that it avoided in Pure Oil. The Commission rejoins that it has not stricken the escalation clauses; it has merely limited their application to prices no higher than the area maximum rates. Alternatively, the Commission avers that even if the contracts have been frustrated, neither the public nor the producers can suffer, since producers’ prices may be as high as, but not higher than, the area maximum.

We think that the Commission did not exceed or abuse its authority. Section 5 (a) provides without qualification or exception that the Commission may determine whether “any rule, regulation, practice, or contract affecting . . . [any] rate ... is unjust, unreasonable, unduly discriminatory, or preferential . . . , ” and prescribe the “rule, regulation, practice, or contract to be thereafter observed . . . .” Although the Natural Gas Act is premised upon a continuing system of private contracting, United Gas Co. v. Mobile Gas Corp., supra, the Commission has plenary authority to limit or to proscribe contractual arrangements that contravene the relevant public interests. Compare FPC v. Sierra Pacific Power Co., 350 U. S. 348. Nor may its order properly be set aside merely because the Commission has on an earlier occasion reached another result; administrative authorities must be permitted, consistently with the obligations of due process, to adapt their rules and policies to the demands of changing circumstances. Compare American Trucking v. A., T. & S. F. R. Co., 387 U. S. 397, 416. See 2 K. Davis, Administrative Law Treatise § 18.09, at 610 (1958). We need not, for present purposes, calculate what collateral consequences, if any, the Commission’s order may have for the terms or validity of the contracts it reaches; we hold only that the Commission has here permissibly restricted the application of indefinite escalation clauses.

The next supplementary order to be considered is the Commission’s creation of various exemptions for the smaller producers. The difficulties of the smaller producers differ only in emphasis from those of the larger independent producers and the integrated producer-distributors; but these differences are not without relevant importance. Although the resources of the small producers are ordinarily more limited, their activities are characteristically financially more hazardous. It appears that they drill a disproportionately large number of exploratory wells, and that these are frequently in areas in which relatively little exploration has previously occurred. Their contribution to the search for new gas reserves is therefore significant, but it is made at correspondingly greater financial risks and at higher unit costs. The record before the Commission included evidence that, for this and other reasons, small producers have regularly suffered higher percentages of dry wells, and higher average costs per Mcf of production. At the same time, the Commission found that small producers are the source of only a minor share of the total national gas production, and that the prices they have received have followed closely those obtained by the larger producers.

The Commission reasoned that, in these circumstances, carefully selected special arrangements for small producers would not improperly increase consumer prices. Moreover, it concluded that such exemptions might usefully both streamline the administrative process and strengthen the small producers’ financial position. The Commission provided two forms of special relief: first, it released small producers from the requirement that quality adjustments be made in price; and second, it commenced a rule-making proceeding intended to relieve them from various filing and reporting obligations. See 34 F. P. C. 434. The Commission asserted that the consequences for consumer prices of the first would be de minimis; it expected that the second would measurably reduce the small producers’ regulatory expenses.

We conclude that these arrangements did not exceed the Commission’s statutory authority. We recognize that the language of §§ 5 and 7 is without exception or qualification, but it must also be noted that the Commission is empowered, for purposes of its rules and regulations, to “classify persons and matters within its jurisdiction and prescribe different requirements for different classes of persons or matters.” § 16, 15 U. S. C. § 717o. The problems and public functions of the small producers differ sufficiently to permit their separate classification, and the exemptions created by the Commission for them are fully consistent with the terms and purposes of its statutory responsibilities. It is not without relevance that this Court has previously expressed the belief that similar arrangements would ameliorate the Commission’s administrative difficulties. See FPC v. Hunt, 376 U. S. 515, 527.

Finally, we consider one additional question. Certain of the producers have urged that, having adopted a system of area regulation, the Commission improperly designated the Permian Basin as a regulatory area. It is contended that the Commission failed to provide appropriate opportunities for briefing and argument on questions of the size and composition of the area. We must, before considering the rate structure devised for the Permian Basin by the Commission, examine this contention.

The Commission’s designation of the Permian Basin as a regulatory area stemmed from its Statement of General Policy, issued September 28, 1960. 24 F. P. C. 818. The Commission there announced its intention to regulate producers’ interstate sales through the imposition of maximum area prices; it provided, for this purpose, a provisional system of guideline prices for the principal producing areas. The Commission averred that these areas, although “not necessarily in complete accord with geographical and economic factors,” are “convenient and well known.” Id., at 819. It declared that, as “experience and changing factors” require, it was prepared to alter the areas to eliminate any inequities. Ibid.

On December 23, 1960, the Commission ordered the institution of this proceeding, for which it merged three of the producing areas separately listed by the Statement of General Policy. 24 F. P. C. 1121. It unequivocally announced that “no useful purpose would be served at this time by delaying the discharge of our primary responsibility ... by entertaining issues . . . that the areas we have delineated . . . might be inappropriate for ratemaking purposes.” Id., at 1122. It appears that no hearings were conducted, and no evidence taken, on the propriety of the areas thus designated by the Commission for inclusion in this proceeding.

We do not doubt that significant economic consequences may, in certain situations, result from the definition of boundaries among regulatory areas. The calculation of average costs might, for example, be influenced by the inclusion or omission of a given group of producers; and the loss or retention of a price differen-cial between regulatory areas might prove decisive to the success of marginal producers. Nonetheless, we hold that the Commission did not abuse its statutory authority by its refusal to complicate still further its first area proceeding by inclusion of issues relating to the proper size and composition of the regulatory area.

It must first be emphasized that the regulatory area designated by the Commission was evidently both convenient and familiar. There is no evidence before us, and the producers have not alleged, that the Permian Basin, as it was defined by the Commission, does not fit either with prevailing industry practice or with other programs of state or federal regulation. Moreover, the Commission was already confronted by an extraordinary variety of difficult issues of first impression; it quite reasonably preferred to simplify, so far as possible, its proceedings. Finally, it is not amiss to note that the Commission evidently has more recently permitted consideration of similar questions in area proceedings. Compare Area Rate Proceeding (Hugoton-Anadarko Area), 31 F. P. C. 888, 891. We assume that, consistent with this practice and with the terms of its Statement of General Policy, the Commission now would, upon an adequate request, permit interested parties to offer evidence and argument on the propriety of modification of the Permian Basin regulatory area. We hold only that the Commission was not obliged, in the circumstances of this case, to include among the disputed issues questions of the proper size and composition of the regulatory area.

We therefore conclude that the Commission did not, in these proceedings, violate pertinent constitutional limitations, and that its adoption of a system of area price regulation, supplemented by provisions for a moratorium upon certain price increases and for exceptions for smaller producers, did not abuse or exceed its authority. We accordingly turn to various questions that have been raised respecting the propriety of the rate structure devised by the Commission for the Permian Basin.

IV.

It is important first to delineate the criteria by which we shall assess the Commission’s rate structure. We must reiterate that 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. This Court has therefore repeatedly stated that the Commission’s orders may not be overturned if they produce “no arbitrary result.” FPC v. Natural Gas Pipeline Co., supra, at 586; FPC v. Hope Natural Gas Co., supra, at 602. Although neither law nor economics has yet devised generally accepted standards for the evaluation of rate-making orders, it must, nonetheless, be obvious that reviewing courts will require criteria more discriminating than justice and arbitrariness if they are sensibly to appraise the Commission’s orders. The Court in Hope found appropriate criteria by inquiring whether “the return to the equity owner [is] commensurate with returns on investments in other enterprises having corresponding risks,” and whether the return was “sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital.” Id., at 603. And compare S. W. Tel. Co. v. Public Serv. Comm., 262 U. S. 276, 290-292 (dissenting opinion). But see Edgerton, Value of the Service as a Factor in Rate Making, 32 Harv. L. Rev. 516. These criteria, suitably modified to reflect the special circumstances of area regulation, remain pertinent, but they scarcely exhaust the relevant considerations.

The Commission cannot confine its inquiries either to the computation of costs of service or to conjectures about the prospective responses of the capital market; it is instead obliged at each step of its regulatory process to assess the requirements of the broad public interests entrusted to its protection by Congress. Accordingly, the “end result” of the Commission’s orders must be measured as much by the success with which they protect those interests as by the effectiveness with which they “maintain . . . credit and . . . attract capital.”

It follows that the responsibilities of a reviewing court are essentially three. First, it must determine whether the Commission’s order, viewed in light of the relevant facts and of the Commission’s broad regulatory duties, abused or exceeded its authority. Second, the court must examine the manner in which the Commission has employed the methods of regulation which it has itself selected, and must decide whether each of the order’s essential elements is supported by substantial evidence. Third, the court must determine whether the order may reasonably be expected to maintain financial integrity, attract necessary capital, and fairly compensate investors for the risks they have assumed, and yet provide appropriate protection to the relevant public interests, both existing and foreseeable. The court’s responsibility is not to supplant the Commission’s balance of these interests with one more nearly to its liking, but instead to assure itself that the Commission has given reasoned consideration to each of the pertinent factors. Judicial review of the Commission’s orders will therefore function accurately and efficaciously only if the Commission indicates fully and carefully the methods by which, and the purposes for which, it has chosen to act, as well as its assessment of the consequences of its orders for the character and future development of the industry. We are, in addition, obliged at this juncture to give weight to the unusual difficulties of this first area proceeding; we must, however, emphasize that this weight must significantly lessen as the Commission’s experience with area regulation lengthens. We shall examine the various issues presented by the rate structure in light of these interrelated criteria.

The first issue is whether the Commission properly rejected the producers’ contention that area rates should be derived from field, or contract, prices. The producers have urged that prevailing contract prices provide an accurate index of aggregate revenue requirements, and that they are an appropriate mechanism for the protection of consumer interests. The record before the Commission, however, supports its conclusion that competition cannot be expected to reduce field prices in the Permian Basin to the "lowest possible reasonable rate consistent with the maintenance of adequate service in the public interest.” Atlantic Rfg. Co. v. Public Service Comm’n, 360 U. S. 378, 388.

The field price of natural gas produced in the Permian Basin has in recent years steadily and significantly increased. These increases are in part the products of a relatively inelastic supply and steeply rising demand; but they are also symptomatic of the deficiencies of the market mechanism in the Permian Basin. Producers’ contracts have in the past characteristically included indefinite escalation clauses. These clauses, in combination with the price leadership of a few large producers, and with the inability or unwillingness of interstate pipe-fines to bargain vigorously for reduced prices, have created circumstances in which price increases unconnected with changes in cost may readily be obtained. These market imperfections, operative despite an “essentially monopsonistic environment,” have accentuated the consequences of inelastic supply and sharply rising demand. Once an increase has been obtained by the larger producers, the escalation clauses have guaranteed similar increases to others. In contrast, consumers have been left without effective protection against steadily rising prices. Their alternative sources of energy are in practice few, and the demand for natural gas, particularly in California, is therefore relatively unresponsive to price increases. The consumer is thus obliged to rely upon the Commission to provide “a complete, permanent and effective bond of protection from excessive rates and charges.” Atlantic Rfg. Co. v. Public Service Comm’n, supra, at 388.

We do not now hold, and the Commission has not suggested, that field prices are without relevance to the Commission’s calculation of just and reasonable rates under § 5 (a). The records in subsequent area proceedings may more clearly establish that the market mechanism will adequately protect consumer interests We hold only that, on this record, the Commission was not compelled to adopt field prices as the basis of its computations of area rates.

We next examine the Commission’s decision to create two maximum area rates for the Permian Basin. Under the Commission’s rate structure, the applicable maximum price for a producer’s sale is determined both by the moment at which the gas was first dedicated to the interstate market, and by the method by which the gas was produced. It follows that two producers, simultaneously offering gas of identical quality and Btu content, may be confronted by different maximum prices.

The premises of this arrangement are two. First, the Commission evidently believed that price should be employed functionally, as a tool to encourage the production of appropriate supplies of natural gas. A price is thus just and reasonable within the meaning of §§ 4 (a) and 6 (a) not merely because it is “somebody’s idea of return on a ‘rate base,’ ” but because it results in satisfactory programs of exploration, development and production.

Second, the Commission concluded that price could usefully serve as an incentive to exploration and production only if it were computed according to the method by which gas is produced. Natural gas produced jointly with oil is necessarily a relatively unimportant byproduct. The value of oil-well gas is on average only one-seventeenth that of the oil with which it is produced. See 34 F. P. C., at 322. It cannot be separately sought or independently produced; its production is effectively restricted by state regulations intended to encourage the conservation of oil. Accordingly, the supply of oil-well gas is, as the examiner observed, “almost perfectly inelastic.” Id., at 323.

On the other hand, gas-well gas is produced independently of oil, and of state restrictions on oil production. More important, the Commission found that a separate search can now be conducted for gas reservoirs; cumulative drilling experience permits at least the larger producers to direct their programs of exploration and development to the search for gas. The supply of gas-well gas is therefore relatively elastic, and its price can meaningfully be employed by the Commission to encourage exploration and production. The Commission reasoned that a higher maximum rate for gas-well gas dedicated to interstate commerce after the approximate moment at which a separate search became widely possible would provide an effective incentive. Correspondingly, the Commission adopted a relatively low price for all other natural gas produced in the Permian Basin, since price could not serve as an incentive, and since any price above average historical costs, plus an appropriate return, would merely confer windfalls.

We find no objection under the Natural Gas Act to this dual arrangement. We have emphasized that courts are without authority to set aside any rate adopted by the Commission which is within a “zone of reasonableness.” FPC v. Natural Gas Pipeline Co., supra, at 585. The Commission may, within this zone, employ price functionally in order to achieve relevant regulatory purposes; it may, in particular, take fully into account the probable consequences of a given price level for future programs of exploration and production. Nothing in the purposes or history of the Act forbids the Commission to require different prices for different sales, even if the distinctions are unrelated to quality, if these arrangements are “necessary or appropriate to carry out the provisions of this Act.” § 16, 15 U. S. C. § 717o. We hold that the statutory “just and reasonable” standard permits the Commission to require differences in price for simultaneous sales of gas of identical quality, if it has permissibly found that such differences will effectively serve the regulatory purposes contemplated by Congress.

The Commission’s responsibilities include the protection of future, as well as present, consumer interests. It has here found, on the basis of substantial evidence, that a two-price rate structure will both provide a useful incentive to exploration and prevent excessive producer profits. In these circumstances, there is no objection under the Natural Gas Act to the price differentials required by the Commission.

The symmetry of the Commission’s incentive program is, however, marred. The Commission held in 1965 that the higher maximum rate should be applicable to gas-well gas committed to interstate commerce since January 1, 1961. It is difficult to see how the higher rate could reasonably have been expected to encourage, retrospectively, exploration and production that had already occurred. There is thus force in Commissioner Ross’ contention that this arrangement is not fully consistent with the logic of the two-price system.

Nonetheless, we are constrained to hold that this was a permissible exercise of the Commission’s discretion. The Commission believed that its Statement of General Policy, issued September 28, 1960, had created reasonable expectations among producers that higher rates would thereafter be permitted for initial filings under § 7. The Commission evidently concluded that fairness obliged it to satisfy, at least in part, those expectations. We must also recognize that an unexpected downward revision of the guideline price for initial filings, with accompanying refunds, might have seriously diminished the producers’ confidence in interstate prices, and perhaps threatened the future interstate supply of natural gas. We can assume that the Commission gave attention to this possibility. Compare 34 P. P. C., at 188. These factors provide a permissible basis for this exercise of the Commission’s authority.

We must next examine the methods by which the Commission reached the two maximum rates it created for gas produced in the Permian Basin. The Commission justified its adoption of a two-price rate structure by reliance upon functional pricing; it suggested that two prices, with an appropriate differential, may be used so as both to provide an incentive to exploration and to restrict to reasonable levels producers’ profits. In turn, it computed the two area maximum prices directly from costs of service, without allowances for noncost factors. The price differential which the Commission expects to serve as an incentive is the product of differences in the time periods and geographical areas for which costs were computed, and not of noncost additives to cost components. Finally, the Commission, by its adoption of a moratorium until January 1, 1968, created a temporary price freeze in the Permian Basin.

Although we would expect that the Commission will hereafter indicate more precisely the formulae by which, it intends to proceed, we see no objection to its use of a variety of regulatory methods. Provided only that they do not together produce arbitrary or unreasonable consequences, the Commission may employ any “formula or combination of formulas” it wishes, and is free “to make the pragmatic adjustments which may be called for by particular circumstances.” FPC v. Natural Gas Pipeline Co., supra, at 586. We have already considered the Commission's adoption of a two-price system and of a moratorium, and have concluded that they are each reasonably calculated to achieve appropriate regulatory purposes. It remains now to examine its computation of the area maximum prices from the producers' costs of service.

The Commission derived the maximum rate for new gas-well gas from composite cost data intended to evidence the national costs in 1960 of finding and producing gas-well gas. It reasoned that these costs should be computed from national, and not area, data because, first, the larger producers conduct national programs of exploration, and, second, “much, if not most, of the relevant information” was available only on a national basis. It held, in addition, that costs in the Permian Basin did not “vary sufficiently from the national average to warrant a different treatment . . . .” 34 F. P. C., at 191. The Commission found that 1960 cost data should be used, and historical data disregarded, because only relatively current cost data would adequately guarantee an effective incentive for future exploration and production. The Commission was obliged to obtain the relevant cost data from a variety of sources. Natural gas producers have not yet been required to adopt any uniform system of accounts, and no private or public agency had in 1965 collected all the pertinent information. Many of the data were taken from nationally published statistics; the balance was derived from questionnaires completed by the producers. The Commission concluded that these sources “in combination provide an adequate basis for the costs we have found.” Ibid.

The maximum just and reasonable rate for all other Permian Basin gas was calculated from cost data intended to reflect the historical costs of gas-well gas produced in 1960 in the Permian Basin. The examiner had computed this rate by essentially the same method he had used for new gas-well gas, with certain cost components adjusted by back-trending. The Commission’s staff, on the other hand, offered a comprehensive study of historical costs of service. The Commission adopted both methods, using the examiner’s back-trended cost computations as a check upon the accuracy of the staff's presentation.

The Commission reasoned that excessive producer profits could be minimized only if the rate for flowing gas were derived from the most precise available evidence of actual historical costs. It therefore held that these costs should be taken from area, and not national, data.

The Commission’s staff obtained the data necessary for its computation of historical costs from questionnaires completed by producers. The information used by the staff, and ultimately adopted by the Commission, was taken from questionnaires submitted by 42 major producers, which together account for 75% of all the gas produced in the Basin, and 85% of all the gas-well gas. Nonetheless, some two-thirds of all the gas produced in the Permian Basin is oil-well gas, and Sun Oil estimates that the staff’s gas-well gas data were thus applicable only to some 15.3% of the total production of natural gas in the Basin in I960.

We hold that the Commission, in calculating cost data for the two maximum rates by differing geographical bases and time periods, did not abuse its authority. The Commission’s use of separate sources of data for the two rates permitted the creation of a price differential between them without the inclusion of noncost components. Its selections of time periods and geographical bases were entirely consistent with the logic of its system of incentive pricing. In these circumstances, we can find no tenable objection to this aspect of the Commission’s rate structure.

It is further contended that the Commission imper-missibly used flowing gas-well gas cost data to calculate the maximum rate for old gas, thereby disregarding entirely the costs of gas produced in association with oil. The Commission’s explanation was essentially pragmatic. It reasoned that the uncertainties of joint cost allocation preclude accurate computations of the cost of casinghead and residue gas. Further, the Commission averred that it is administratively imperative to simplify, so far as possible, the area rate structure. The Commission regarded its adoption of a single area maximum price for all gas, except new gas-well gas, its residue and gas-cap gas, as “an important step toward simplified and realistic area price regulation.” 34 F. P. C., at 211.

We cannot say that these arrangements are impermissible. There is ample support for the Commission's judgment that the apportionment of actual costs between two jointly produced commodities, only one of which is regulated by the Commission, is intrinsically unreliable. It is true that certain of the costs of gas-well gas must also be apportioned, but the Commission reasonably concluded that these difficulties are relatively less severe. The Commission was, in addition, entitled to give great weight to the administrative importance of a simplified rate structure. Finally, it is relevant that the Commission found that the cost of casinghead and residue gas could not be higher, and, if exploration and development costs are realistically discounted, must surely be lower than the costs of flowing gas-well gas. These considerations in combination warranted the Commission’s judgment that a single area maximum price for all gas other than new gas-well gas should be imposed, and that this maximum rate should be derived entirely from the historic costs of flowing gas-well gas.

We turn now to the Commission’s computation of the proper rate base. The Commission’s method here differed significantly from that frequently preferred by regulatory authorities. It did not use a declining rate base and return, but instead computed an average net production investment, to which it applied a constant rate of return. The Commission assumed for this purpose that a gas well depletes at a uniform rate, and that it is, on average, totally depleted in 20 years. It found that the annual capital-recovery cost, including depletion, depreciation, and amortization, was 3.95$ per Mcf. Allowing one year for a lag between investment and first production, the Commission obtained an average production investment of 43.45$ per Mcf. The proper return per Mcf was then calculated by multiplying this figure by the rate of return.

The producers argue that this has the effect of postponing revenue, and thus discounting its present value; they suggest that the Commission should properly have employed a declining investment base and return. This is a question peculiarly within the Commission’s discretion, and, while the method adopted by the Commission was evidently less favorable to the producers than various other possible formulae, we cannot hold that it was arbitrary or unreasonable.

We next consider whether the rate of return adopted by the Commission was a permissible exercise of its regulatory authority. The Commission first asserted that rates of return must be assessed by a comparable-earnings standard. Under such a standard, earnings should be permitted that are “equal- to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties.” Bluefield Co. v. Public Service Comm., 262 U. S. 679, 692; FPC v. Hope Natural Gas Co., supra, at 603. Although other standards might properly have been employed, the Commission’s decision to examine comparable earnings was fully consistent with prevailing administrative practice, and manifestly was not an abuse of its authority.

The Commission relied for purposes of comparison chiefly upon the rates of return that have recently been permitted to the interstate pipelines. It found that pipelines had been given returns of 6.0 to 6.5% on net investment, with a yield on equity of 10 to 12%. The Commission noted that producers characteristically have less long-term debt than pipelines, and that the financial risks of production are somewhat greater than those of transmission. It reasoned that these differences warranted a more generous rate of return for producers. In addition, the Commission stated that the risk of finding gas of less than pipeline quality, created by the Commission’s promulgation of quality and Btu standards, should be reflected in the rate of return. Finally, the Commission sought to determine the rate of return recently earned by producers of natural gas. It found that accurate rates of return could not be calculated with assurance, although the Commission’s staff offered evidence of an average return for nine companies over five years of 12.4% on net investment. The Commission concluded that, despite its statistical deficiencies, this and similar evidence must be given “heavy consideration in the decisional process.” 34 F. P. C., at 203.

On balance, the Commission selected 12% as the proper rate of return for gas of pipeline quality. We think that this judgment was supported by substantial evidence, and that it did not exceed or abuse the Commission’s authority. The evidence before the Commission fairly suggests that this rate will be likely to “maintain [the producers’] financial integrity, to attract capital, and to compensate [their] investors for the risks assumed . . . .” FPC v. Hope Natural Gas Co., supra, at 605. Further, the distributors and public agencies before the Court have not suggested, and we find no reason to believe, that this return will exceed the proper requirements of the industry. Certainly, as we shall show below, this return is no more than comparable to that characteristically allowed interstate pipelines.

Nonetheless, there remains one further issue essential to an accurate appraisal of the return permitted by the Commission. The Commission’s computation of the rate of return was specifically premised in part on the additional financial risks created for producers by the Commission’s promulgation of quality and Btu standards. Its opinion in these proceedings included a series of specific quality standards. The Commission ruled that gas that fails to satisfy these standards must be sold at prices lower than the applicable area maximum; the amount of the reduction necessary in each sale is to be initially determined by the parties, subject to review by the Commission. Further, natural gas with a Btu content of less than 1,000 per cubic foot must be sold at a price proportionately lower than the applicable area maximum, and gas with a Btu content of more than 1,050 per cubic foot may be sold at a price proportionately higher than the area maximum. The Commission conceded that it could not precisely determine the revenue consequences of these adjustments, although its opinion denying applications for rehearing provided various estimates. It appears to be conceded that the quality of gas produced in the Basin is characteristically lower than the Commission’s standards, and that the standards are therefore likely to be more significant than they might be in other producing areas.

The producers urge, and the Court of Appeals held, that this arrangement is doubly erroneous. First, it treats as a risk what properly is a cost, and thus evades the necessity of appropriate findings on the revenue consequences of the quality adjustments. Second, it reduces the rate of return actually permitted individual producers to an unascertainable figure of less than 12%, and thus prevents an accurate appraisal of its sufficiency. We find both suggestions unpersuasive.

We cannot now hold that it was impermissible for the Commission to treat the quality adjustments as a risk of production. It must be recalled that the Commission was in this first area rate case unable to determine with precision the average amount of the necessary price reductions, and that it thus would have been difficult to have included them as costs, as the Court of Appeals suggested. Further, we recognize that the Commission’s method, premised on agreement between the parties to each sale, has at least the advantage of requiring discrete and accurate adjustments for each transaction. Finally, as we shall show below, treatment of these adjustments as risks of production did not in this case result in inadequate findings, and does not prevent proper appraisal of the rate of return permitted by the Commission. In any event, the Commission’s discretion in such matters is necessarily broad, and its choice cannot be said to have abused its discretion.

The Commission estimated in its opinion denying applications for rehearing that the quality adjustments would result in average price reductions of from 0.7$ to 1.5$ per Mcf. In turn, the amount of these adjustments will be reduced by price increases for high Btu content, and by revenue from plant liquids. We believe that, in the circumstances presented, these estimates were adequate. The Commission’s information about existing contracts was evidently not sufficiently complete to permit precise calculations from previous experience. Moreover, since the adjustments are to be, in the first instance, the product of agreement between the parties, a dimension of uncertainty is necessarily created. De-pite these difficulties, the Commission provided reasonably specific estimates of the range of adjustments that it believed would result. We are entitled now to take notice that these are confirmed by subsequent events. We hold that the Commission’s promulgation of quality standards was accompanied by adequate findings as to their revenue consequences.

The Commission did not provide specific findings as to the effect of these revenue adjustments upon the producers’ rate of return. This was an unfortunate omission, but it does not preclude evaluation of the Commission’s conclusions. It would appear, and counsel for the Commission have estimated, that the rate of return “on average quality” natural gas sold in the Permian Basin might, after quality adjustments, yield “as little” as 10 to 12% on equity. These figures presumably must be adjusted upward for sales of pipeline quality gas, sales of gas with a high Btu content, and revenue from plant liquids. Even as adjusted, however, the aggregate return permitted to producers will apparently exceed only slightly that customarily allowed pipelines, for the quantities of pipeline quality and high Btu content gas produced in the Permian Basin are evidently quite small. Nevertheless, the record before the Commission contained evidence sufficient to establish that these rates, as adjusted, will maintain the industry’s credit and continue to attract capital. Although the Commission’s position might at several places usefully be clarified, the producers have not satisfied the “heavy burden” placed upon those who would set aside its decisions.

y.

We have concluded that the various segments of the Commission’s rate structure do not separately exceed or abuse its authority. Nonetheless, certain of the producers have argued vigorously that the aggregate revenue permitted by the rate structure is, or might be, inadequate. They urge that the imposition of maximum prices computed from composite costs reduces contract prices to a maximum premised on a cost average; and they conclude that the Commission has therefore denied them the revenue necessary for appropriate programs of exploration and development. Related questions troubled the Court of Appeals. It held that the Commission must, under Hope, place in balance revenue and requirements, and that findings must be provided that will permit reviewing courts to assess the skill with which the Commission has employed its scales. Although we sustain, for reasons stated above, the Commission’s rate structure, we believe it proper to examine these additional contentions.

Three interrelated questions are pertinent. First, the adequacy of the Commission’s aggregate revenue findings must be assessed. Second, we must consider the producers’ contentions that the Commission has ¡significantly underestimated the deficiencies of present programs of exploration. Finally, we must determine whether the Commission’s use of averaged costs has created a rate structure that is unjust and unreasonable in its consequences.

We turn initially to the adequacy of the Commission’s revenue findings. It must be emphasized that we perceive no imperative obligation upon the Commission, under either the Natural Gas Act or the decisions of this Court, to provide an apparatus of formal findings, in terms of absolute dollar amounts, as to aggregate revenue and aggregate revenue requirements. It is enough if the Commission proffers findings and conclusions sufficiently detailed to permit reasoned evaluation of the purposes and implications of its order. Compare Chicago & N. W. R. Co. v. A., T. & S. F. R. Co., 387 U. S. 326, 345-347. As we shall show, the Commission’s revenue findings were not, in the circumstances of these proceedings, unduly imprecise. The ambiguities about which the Court of Appeals expressed concern were two. First, the court faulted the Commission for the imprecision of its findings as to the revenue consequences of the quality and Btu adjustments. We have already found adequate the Commission’s estimates of the necessary price reductions. Second, the court stated that the rate structure could not be accurately assessed, since the Commission has incorporated in its calculations both cost and noncost factors; it believed that “the Commission decision rides two horses and we have no way of knowing the outcome of the race.” 375 F. 2d, at 34.

We find this unpersuasive. Although the Commission’s exposition of these questions might have been more carefully drawn, it has quite appropriately incorporated in its calculations factors other than producers’ costs. Cost and noncost factors do not, as the Court of Appeals supposed, race one against the other; they must be, as they are here, harnessed side by side. The Commission’s responsibilities necessarily oblige it to give continuing attention to values that may be reflected only imperfectly by producers’ costs; a regulatory method that excluded as immaterial all but current or projected costs could not properly serve the consumer interests placed under the Commission’s protection. We have already considered each of the points at which the Commission has given weight to noncost factors, and have found its judgments consistent with the terms and purposes of its statutory authority. There is no reason now to return these cases to the Commission for clarification of these issues.

Nor can we hold that the Commission has underestimated the deficiencies of current programs of exploration. The producers’ argument has been uniformly-premised upon the assertion that the ratio of proved recoverable reserves to current production is an accurate index of the industry’s financial requirements. The producers urge that this ratio has dangerously declined, and conclude that any reduction of prevailing field prices will jeopardize essential programs of exploration. There is, however, substantial evidence that additions to reserves have not been unsatisfactorily low, and that recent variations in the ratio of reserves to production are of quite limited significance. Nothing in the record establishes- as proper or even minimal any particular ratio. We do not suggest, nor did the Commission, that the Commission should not continuously assess the level and success of exploration, or that the relationship between reserves and production is not a useful benchmark of the industry’s future. We hold only that the Commission here permissibly discounted the producers’ reliance upon this relationship to establish the inadequacy of its rate structure.

Finally, we turn to the contention that these area maximum rates were derived from averaged costs, and therefore cannot, without further adjustment, provide aggregate revenue equal to the producers’ aggregate requirements. The producers that support the judgments below emphasize that revenue in 1960 from all jurisdictional sales in the Permian Basin averaged 12.72(4 per Mcf. They contend that this revenue will, under the Commission’s order, be reduced by the amount of any necessary quality deductions, by refunds, and by loss of revenue from abrogation of contract prices above the area maximum rates. The producers conclude that the Commission’s rate structure will necessarily cause revenue deficiencies, measured by the difference between actual average revenue (12.720 less these adjustments) and 14.5(4 per Mcf, the rate assertedly found by the Commission to be just and reasonable for flowing gas. They urge that the Commission was properly obliged to balance revenue and costs either by increasing the area minimum rate, or by placing the area maximum rates above average costs.

The inadequacies of this reasoning are several. First, it neglects important characteristics of the rate structure. We understand the Commission, despite certain infelicities of its opinion, to hold that the just and reasonable rate for old gas not of pipeline quality is 14.5(4 per Mcf, less the cost of processing necessary to raise it to pipeline quality. The Commission’s net just and reasonable rate for such gas is therefore 13.00 to 13.80, and not 14.50 per Mcf. Further, average unit revenue will not be simultaneously reduced, as the producers have suggested, by refunds and by abrogation of above-ceiling field prices. As to the past, the two are in large part synonymous; as to the future, only the latter will be applicable.

Moreover, the Commission’s computation of its area rates was not intended to reflect with complete fidelity either the producers’ average costs or their sources of revenue. First, the actual average unit costs of casing-head and residue gas are substantially lower than the average unit costs of flowing gas-well gas; yet the maximum rate for all associated and flowing gas was derived entirely from the latter. It follows that the producers’ net revenues from sales of casinghead and residue gas will prove higher than the return formally permitted by the Commission. Second, producers receive significant payments for liquid hydrocarbons extracted by the pipelines during their processing of gas-well gas. The maximum rate for new gas-well gas evidently takes into account only part of these receipts, and that for old gas-well gas disregards altogether this source of additional revenue. Third, some 20% of all the gas sold under the Commission’s jurisdiction in the Permian Basin is controlled by Spraberry contracts, by which producers are paid for liquids processed by the pipelines from oil-well gas. Much of the gas sold at prices below the applicable area maximum rate is governed by such contracts. This source of revenue was not incorporated in the Commission’s calculation of the maximum rate for oil-well gas. The Commission was unable to compute with precision the revenue obtained by producers from these disparate sources, but it estimated it to be “substantial.” 34 F. P. C., at 1073.

Finally, the producers have ignored the limits of the Commission’s statutory authority. This Court has held, under the Federal Power Act, that the Commission may not abrogate existing contractual arrangements unless the contract price is so “low as to adversely affect the public interest — as where it might impair the financial ability of the public utility to continue its service, cast upon other consumers an excessive burden, or be unduly discriminatory.” FPC v. Sierra Pacific Power Co., 350 U. S. 348, 355. It is not enough, the Court there held, that the contract price permits less than a fair return; the Commission may not, absent evidence of injury to'the public interest, relieve a regulated company of “its improvident bargain.” Ibid. The pertinent provisions of the Federal Power Act “are in all material respects substantially identical to the equivalent provisions of the Natural Gas Act.” Id., at 353. It follows that the Commission was here without authority to abrogate existing contract prices unless it first concluded that they “adversely affect the public interest.” And see FPC v. Tennessee Gas Co., 371 U. S. 145, 153. The Commission found that field prices of less than 90 per Mcf had such consequences, but it declined so to hold for all prices less than the two area maximum rates. There was no evidence before the Commission that required a different result, or that would now permit this Court to set aside the Commission’s judgment.

It does not, however, necessarily follow that the Commission was forbidden to consider, as it selected maximum rates from within the zone of reasonableness, the aggregate revenue deficiencies that might result from improvident contractual limitations. Within this zone, the Commission is permitted to give weight to the consequences upon producers, and thereby upon supply, of such limitations. Nonetheless, the Commission permissibly declined to make adjustments in the area rates because of prevailing contract prices. It recognized that such adjustments would increase the cost of natural gas to some groups of consumers, in order simply to offset bargains previously obtained by others.

The regulatory system created by the Act is premised on contractual agreements voluntarily devised by the regulated companies; it contemplates abrogation of these agreements only in circumstances of unequivocal public necessity. See United Gas Co. v. Mobile Gas Corp., 350 U. S. 332. There was here no evidence of financial or other difficulties that required the Commission to relieve the producers, even obliquely, from the burdens of their contractual obligations. We do not suggest that the Commission need not continuously evaluate the revenue and other consequences of its area rate structures. A principal advantage of area regulation is that it centers attention upon the industry’s aggregate problems, and we may expect that, as the Commission’s experience with area regulation lengthens, it will treat these important questions more precisely and efficaciously. We hold only that, in the circumstances here presented, the Commission’s rate structure has not been shown to deny producers revenues consonant with just and reasonable rates.

VI.

There remain for consideration various additional objections by the producers to the Commission’s cost determinations, and to the sources of information from which those determinations were derived. These questions were not decided by the Court of Appeals. Although this Court ordinarily does not review an administrative record in the first instance, United States v. Great North ern R. Co., 343 U. S. 562, 578; Seaboard Air Line R. Co. v. United States, 382 U. S. 154, 157; there are persuasive reasons now to reach and decide these remaining issues. Almost eight years have elapsed since the Commission commenced these proceedings; we are convinced that producers’ rates may be fairly and effectively regulated only after this and the other area proceedings now before the Commission have been successfully terminated. These issues were briefed and argued at length before this Court; very extended additional proceedings would doubtless be necessary in order to review them yet again.

Moreover, the circumstances here parallel closely those in Chicago & N. W. R. Co. v. A., T. & S. F. R. Co., 387 U. S. 326. It was there said that the “presentation and discussion of evidence on cost issues constituted a dominant part of the lengthy administrative hearings, and the issues were thoroughly explored and contested before the Commission. Its factual findings and treatment of accounting problems concerned matters relating entirely to the special and complex peculiarities of the railroad industry. Our previous description of the Commission’s disposition of these matters is sufficient to show that its conclusions had reasoned foundation and were within the area of its expert judgment.” Id., at 356. This reasoning is entirely applicable to the circumstances presented here; we hold, as did the Court there, that no useful purpose would be served by further proceedings in the Court of Appeals, and that there is no legal infirmity in the Commission’s findings.

VII.

Lastly, we reach questions of the validity of the refund obligations imposed by the Commission’s orders. Two categories of refunds were created. First, producers must return amounts charged in excess of the applicable area rates, including quality and Btu adjustments, for periods following September 1, 1965, the date of effectiveness of the Commission’s order. 34 F. P. C., at 243. The Commission imposed interest of 7% upon these refunds. Second, producers must refund amounts collected in excess of the applicable area rates, including quality and Btu adjustments, during previous periods in which their prices were subject to refund under §4(e). Such obligations ultimately arise from filings by the producers under § 4 (d) for increases in existing price schedules. The appropriate interest on these refunds was held to be that specified in each § 4 (e) proceeding. Refunds in both categories were, under the Commission’s order, to be measured by comparison of individual company price schedules with the applicable area rates.

The Court of Appeals initially sustained the Commission’s refund orders. 375 F. 2d, at 33. On petitions for rehearing, however, the court held that “no refund obligation may be imposed for a period in which there is a group revenue deficiency.” Id., at 36. The court believed this to be an essential corollary of the Commission’s asserted obligation to bring into balance group costs and group revenues; it would have permitted the Commission to order refunds only in periods in which aggregate revenue is found to exceed aggregate revenue requirements, and only as to the amount of the excess. The Commission was expected to apportion any refunds “on some equitable contract-by-contract basis.” Ibid.

We find the court’s reasoning unpersuasive. The Commission may, in the course of its examination of the producers’ financial positions, consider the possible refund consequences of its rate-making orders; but its power to order refunds is not limited to situations in which group revenues exceed group revenue requirements. Area regulation offers a more expeditious method for the calculation of just and reasonable rates, and it will necessarily more rigorously focus the Commission’s attention upon the producers’ common problems. It does not, however, lessen the significance, or modify the incidents, of findings that specific rate levels are or are not just and reasonable within the meaning of §§ 4 (a) and 5 (a). A rate found to be unjust and unreasonable is declared by § 4 (a) to be unlawful; if the rate has been the subject of a rate schedule modification under § 4 (d), the Commission is empowered by § 4 (e) to order its refund. We can see no warrant, either in the Act or in the terms of the Commission’s orders, now to impose any additional limitations upon the Commission’s authority; we hold that the Commission’s'discretion is not constricted in the fashion described by the Court of Appeals.

Wisconsin v. FPC, supra, does not require a different result. It did not, as the Court of Appeals evidently supposed, create any imperative procedure for the disposition of refunds from locked-in rates. The Commission there held that, given its decision to begin a system of area regulation, it was not in the public interest “to reopen these proceedings, to determine a cost of service on the basis of completely new evidence and to attempt to determine rates on the basis of Phillips’ individual cost of service.” 24 F. P. C., at 1009. No just and reasonable rates had been, or could then have been, calculated for Phillips’ sales in the relevant periods. The Commission did not urge, and this Court did not hold, that Phillips’ revenue deficiencies imposed a limitation upon the Commission’s authority to require refunds; the Court merely sustained the Commission’s refusal, in the circumstances there presented, to pursue further a lengthy and burdensome series of § 4 (e) proceedings. See also Hunt Oil Co., 28 F. P. C. 623; and Wisconsin v. FPC, supra, at 306, n. 15.

The Commission reasonably concluded that the adoption of a system of refunds conditioned on findings as to aggregate area revenues would prove both inequitable to consumers and difficult to administer effectively. Such arrangements would require consumers to accede to unjust and unreasonable prices merely because other prices, perhaps ultimately benefiting other consumers, had proved improvident. Nor would these arrangements necessarily serve the interests of the improvident producers; they might merely permit more prudent competitors to escape refunds on concededly unlawful prices. We hold that the Commission’s refund orders do not exceed or abuse its statutory authority.

The motions for leave to adduce additional evidence are denied, the judgments of the Court of Appeals are affirmed in part and reversed in part, as herein indicated, and the cases are remanded to that court for further proceedings consistent with this opinion.

It is so ordered.

Mr. Justice Marshall took no part in the consideration or decision of these cases.

MR. Justice Douglas,

dissenting.

I.

What the Court does today cannot be reconciled with the construction given the Natural Gas Act by FPC v. Hope Natural Gas Co., 320 U. S. 591, 602. In that case we said, in determining whether a rate had been properly found to be “just and reasonable” under the Act, that

(1) “it is the result reached not the method employed which is controlling”;

(2) it is “not theory but the impact of the rate order which counts”;

(3) “If the total effect of the rate order cannot be said to be unjust and unreasonable, judicial inquiry under the Act is at an end.”

The area rate orders challenged here are based on averages. No single producer’s actual costs, actual risks, actual returns, are known.

The “result reached” as to any producer is not known.

The “impact of the rate order” on any producer is not known.

The “total effect” of the rate order on a single producer is not known.

It is said, however, that if any producer is aggrieved, it may apply for relief and if it fails to obtain relief it can resort to the courts. But unless we know the standards which will govern in case it applies for relief, we are, with all respect, mouthing mere words when we say the rate is “just and reasonable.” In absence of knowledge, we cannot possibly perform our function of judicial review, limited though it be.

It was urged in the separate opinion of Mr. Justice Jackson in Hope that a system of regulation be authorized which would center not on the producer but on the product “which would be regulated with an eye to average or typical producing conditions in the field.” 320 U. S., at 652. But the Court rejected that approach, saying that §§ 4 (a) and 5 (a) of the Natural Gas Act contained “only the conventional standards of rate-making for natural gas companies.” Id., at 616.

Group regulation of rates is not, of course, novel. It has at times been authorized. The Federal Aviation Act of 1958, § 1002 (e), 72 Stat. 789, 49 U. S. C. § 1482 (e), permits it. And see General Passenger-Fare Investigation, 32 C. A. B. 291. Under the War Power, extensive price regulation on a group basis was sustained. Bowles v. Willingham, 321 U. S. 503, 517-519. The Interstate Commerce Commission has undertaken it, as revealed by the Divisions of Revenue cases. New England Divisions Case, 261 U. S. 184; United States v. Abilene & S. R. Co., 265 U. S. 274; Chicago & N. W. R. Co. v. A., T. & S. F. R. Co., 387 U. S. 326. See also § 15 of the Interstate Commerce Act, as amended, 24 Stat. 384, 49 U. S. C. § 15 (3). The requirement in the Divisions of Revenue cases is that the group evidence be “typical in character, and ample in quantity, to justify the finding made in respect to each division of each rate of every carrier.” 261 U. S., at 196-197. In other words, where the rates fixed will recover the typical group cost of service, the individual producer’s right to a minimum of its operating expenses and capital charges is protected. Cost of service includes operating expenses and capital charges. FPC v. Natural Gas Pipeline Co., 315 U. S. 575, 607 (concurring opinion). With that protection I can see no reason why group rates may not be sanctioned here. But more is required than the Commission undertook to do in these cases.

In the present cases the Commission found averages; but there are no findings as to the typicality and representative nature of those averages. We certainly cannot take judicial notice that the averages are typical. Mr. Justice Brandéis in the leading Divisions of Revenue case said that “averages are apt to be misleading” and they cannot be accepted “as a substitute for typical evidence.” 265 U. S., at 291. Cf. American Motors Corp. v. FTC, 384 F. 2d 247, 251-259, 260-262 (C. A. 6th Cir. 1967).

The Commission found no m,edian. Moreover, as we observed in another context, it did not find what was “the average cost” of groups made up of individual members who have “a close resemblance” when it comes to the “essential point or points which determine the costs considered.” United States v. Borden Co., 370 U. S. 460, 469.

With respect to the cost of new gas-well gas, the Commission did not determine whether the average costs compiled from the questionnaires or derived from industry-wide data were typical or representative.

In finding the cost of flowing gas, the Commission noted that the 1960 level of costs compiled by the staff in large part from the questionnaire responses was “fairly representative of the costs during the three year period ending in 1960” (34 F. P. C. 159, 213) and that “[t]he 1960 test year is . . . typical of current and future costs of the flowing gas . . . .” Ibid. This reference to “representative” and “typical” costs, however, dealt only with the question of time — i. e., the staff’s use of 1960 data in developing its composite cost presentation was deemed permissible since 1960 was found to be a typical and representative year.

The Court professes to find that the Commission adequately determined that the averages it employed were “typical” and “representative.” Ante, at 802-803, n. 79. But the statements plucked from the Commission’s opinion do not support that interpretation.

The Commission also observed, with respect to the questionnaire data, that 42 of the major producers (representing all but one of the major producers in the Permian area) responded on the Appendix B questionnaires. The Commission agreed with the Examiner that “the data provided by the major producers with respect to their Permian production was fully representative of area costs,” and that exclusion of the Appendix C returns from small producers would have only a de minimis effect. 34 F. P. C., at 214. But although the data submitted by the major producers were found to be typical data for the area, and I assume also for the major producers in the area, there are no findings whether the averages compiled from the data were typical or representative of the costs of those major producers or of other producers in the area.

The Commission’s statement that the sources used “in combination provide an adequate basis for the costs we have found” certainly cannot be read as a finding that those sources were “typical and representative.” Nor does the fact that the sources were “recognized, published statistical data sources,” or “well-recognized and authoritative,” mean they also contained typical and representative averages.

An average cost is not only apt to be “misleading”; it may indeed not be representative of any producer.

The Commission allowed a 12% rate of return, the return being “on capital invested in finding new gas well gas.” 34 F. P. C., at 306, 343. “Production investment costs” constituted this “capital invested” and were the bases to which the Commission applied the 12% rate to arrive at a return of 5.21$ per Mcf to be included in the rate base for new gas-well gas. 34 F. P. C., at 197, 204. These “production investment costs” included successful well costs, lease acquisition costs, and the cost of other production facilities. But they were likewise determined on the basis of averages. See 34 F. P. C., at 197-198, 295, 377-382.

The average per capita income of a Middle East kingdom is said to be $1,800 a year. But since one man— or family — gets most of the money, $1,800 a year describes only a mythical resident of that country.

The 12% return allowed by the Commission and computed on an average-cost basis may likewise have no relation whatever to the reality of the actual costs of any producer.

One producer’s cost, though varying from year to year, may average out at $1 per Mcf. Another’s may average out at 5(4 per Mcf. Does that make 52.5$ per Mcf representative of either producer or typical of all producers, or, indeed, typical of any producer, even if the 52.5$ per Mcf is stable over the entire period of years?

The Commission could follow the lead of the Interstate Commerce Commission and produce rates on a group basis. But it simply has not done so in any rational way.

Averages are apt to take us with Alice into Wonderland. That is one reason why the case should be remanded to the Commission for further findings.

The Commission will allow individual application for relief from these new rates. But it has not prescribed the terms and conditions on which relief will be granted. It has said, however, that an individual producer must show more than that its cost of service is greater than the averages on which the rate is based. 34 F. P. C., at 180.

In a regulated industry there is no constitutional guarantee that the most inefficient will survive. Hegeman Farms Corp. v. Baldwin, 293 U. S. 163, 170-171.

That assumes, however, an ability to withdraw from the business. But a producer of natural gas may not abandon its existing facilities that supply the interstate market without Commission approval. United Gas Pipe Line Co. v. FPC, 385 U. S. 83.

The Commission says that a producer will be able to obtain relief to cover its out-of-pocket expenses. 34 F. P. C., at 226. Do they include return, depreciation, depletion, exploration, development, and overhead? The Court of Appeals did not know (375 F. 2d, at 30); and we certainly do not. The remand by the Court of Appeals for further definition was therefore clearly necessary. For even if we need not know the precise impact of the new group rate on each producer at the time of the group rate order, we certainly must know the conditions on which a producer can get relief before we can say that a rate as to it is “just and reasonable.”

Although we assume that the Act authorizes group rate-making, we cannot disregard the basic structure of the Act, patterned on the “conventional standards of rate-making” (FPC v. Hope Natural Gas Co., supra, at 616) and providing in §§ 4 (a) and 5 (a) that all rates of “any” natural gas company be “just and reasonable.” Beyond the group is the single producer; beyond the community of producers is the individual. The ultimate thrust of the Act reaches the individual producer; and unless we know what the group rate in final analysis does to it or disables it from doing we cannot perform our duty of judicial review.

II.

If we move to the regulation of the group as such and consider the impact of these rate orders on it, we are likewise not able on the present record to perform our function of judicial review.

It is impossible to say whether the proper revenue requirements of the group can be satisfied under this rate order. For the costs represent averages; and there is no way for us to find from the record whether these averages are typical and what the impact of the rates on the group will be.

The error is compounded when the costs used are the purported costs of gas-well gas and do not include the costs of casinghead gas, residue gas derived therefrom, and gas-well gas from combination leases. The Commission concluded that the costs of casinghead gas and residue gas produced therefrom did not exceed the costs for gas-well gas. Yet at the same time it rejected proffered evidence of higher costs of processing gas to remove liquid hydrocarbons. Commission expertise should not be allowed to make its own “facts” to justify the desired result.

Beyond that are the quality adjustments. Upward price adjustments are permitted for Btu content above 1,050 per cubic foot and downward adjustment for Btu content below 1,000. The Commission was concerned with the value of the “energy content of the gas, which in reality is what the consumer is purchasing.” 34 F. P. C., at 223.

With that standard in mind it allowed price reductions

(1) where the gas contains more than 10 grains of hydrogen sulphide or 200 grains of total sulphur per Mcf;

(2) where it contains more than .009 pound per Mcf of water;

(3) where it contains more than 3% by volume of carbon dioxide;

(4) where the gas pressure is less than 500 pounds per square inch.

When any of these standards are not met, the applicable ceiling price is adjusted downward by the net cost of processing the gas to bring it up to standard.

Under the Commission’s standards about 90% of the flowing gas moving interstate from the Permian Basin is not of the pipeline quality that the Commission has prescribed. 375 F. 2d, at 30. What the costs will be to1 convert the gas to these new standards is not found in this record. Perhaps this deficiency is due to the fact that the Commission, almost as an afterthought and not with clear, advance notice, decided to deal with detailed quality standards. But without knowing these costs through competent evidence, neither we nor the Commission has any way even to guess at whether the new rates will satisfy the criteria of Hope.

III.

The Court approves the Commission’s treatment of the quality adjustments as a risk of production. But whether they be labeled a risk of production or a cost would seem to be irrelevant. That is a matter of semantics as far as the standards of Hope are concerned. For the question is whether we can reasonably determine the end result from the computations of the Commission, including both risk and cost factors.

Any unknown cost is a risk. But the Commission should not be permitted to excuse its failure to solicit or proffer appropriate evidence concerning the cost of converting gas into pipeline quality by labeling that cost a “risk.” The Court of Appeals recognized this point. See 375 F. 2d, at 31-32, 35. Commissioner O’Connor noted in his opinion concurring in the denial of rehearing that: “To bury the quality impact in our rate of return determination is to overlook the basis for the 12 per cent allowance: comparable return on equity of 10-12 per cent by the far less risky operations of transmission companies.” 34 F. P. C., at 1081. And, as one commentator recently observed:

“The Commission stated that the rate of return also reflected the risk of finding gas of less than pipeline quality — a clever way of avoiding the quality discount problem. Since there was no evidence in the record as to what those discounts would be, one can only say that 'risks’ were involved. It is a novel doctrine, indeed, that the rate of return should be adjusted to reflect the risk that the regulatory cost computations are incorrect.”

The Court concedes that the lack of specific findings concerning the effect of the quality adjustments upon the rate of return was “an unfortunate omission.” Ante, at 812. But it proceeds to scratch about for evidence to support the Commission. With all respect, there is no competent evidence in the record to permit a meaningful determination of the impact of the quality deductions. The Court of Appeals was clearly correct in remanding to the Commission for proper findings on this point.

Behind the veneer of the Court’s opinion may be an unstated premise that the complexity of the task of regulating the wellhead price of gas sold by producers is both so great and so novel that the Commission must be given great leeway. But the permissible bounds, so far as judicial review is concerned, are passed when guesswork is substituted for reasoned findings, when the Commission can avoid finding “costs” by the convenience of calling them “risks,” when rates of return are computed for those mythical producers who happen to meet the “average” specifications.

If the task of regulating producer sales within the framework of the Natural Gas Act is as difficult as the present cases illustrate, perhaps the problem should be returned to Congress. But certainly we do little today to advance the cause of responsible administrative action. With all respect, we promote administrative irresponsibility by making an agency’s fiat an adequate substitute for supported findings.

IV.

New Mexico and Texas, in which the Permian Basin is located, have comprehensive oil and gas conservation codes. A substantial portion of their taxes on the production of natural gas within their boundaries goes into school funds. They say that the “public interest” entrusted to the Commission by 15 U. S. C. § 717 (a) includes the interest of the States where the gas is found. They claim that pricing can be disastrous to the producing States and urge the need for threefold findings by the Commission to ensure an adequate supply of natural gas for future use:

“First, the Commission must determine the quantity of gas needed to constitute an adequate future supply. Secondly, it must make a conclusion as to the level of exploration and development which will produce the needed gas supply. Finally, it must prescribe a rate which will elicit that level of exploration and development.”

They argue that where Commission rates are lower than existing contract rates, continued operation is uneconomical in many so-called “stripper fields”:

“Although daily per well production from these fields is relatively low, their combined remaining recoverable reserves nevertheless constitute a considerable percentage of the total reserves for the area which will be forever lost if it becomes necessary to plug and abandon these fields for economic reasons.”

The Court of Appeals did not entertain these objections (375 F. 2d, at 18) because it read the Hope case as foreclosing them.

Hope, however, did not involve regulation of producers of natural gas, only interstate pipelines. At that time, Phillips Petroleum Co. v. Wisconsin, 347 U. S. 672, giving the Commission authority over these producers, had not been decided. In Hope we assumed that the Act meant what it said in § 1 (b) when it did not extend federal control to the “production or gathering of natural gas.” We were not then reviewing a federal order fixing wellhead gas prices for producers. Wellhead gas was not even involved in the Hope case. We were concerned there with abuses and overreaching by pipeline companies. We said:

“If the Commission is to be compelled to let the stockholders of natural gas companies have a feast so that the producing states may receive crumbs from that table, the present Act must be redesigned. Such a project raises questions of policy which go beyond our province.” 320 U. S., at 614.

Now that Phillips has put the prices of producers under federal control, the interests of the producing States must be considered, appraised, and weighed as an important ingredient of the “public interest.” Regulation of wellhead prices by the Commission directly influences the level and feasibility of production, and can significantly affect the producing States’ regulation of production. See Phillips Petroleum Co. v. Wisconsin, supra, at 689-690 (dissenting opinion).

As the Court today says in another context, price in functional terms can be “a tool to encourage” the production of gas. Ante, at 760. The effect of price on the regulatory responsibilities of the several States must therefore be weighed, unless contrary to the mandate of the Act regulation of production is to pass into federal hands.

What the merits may be on this issue we do not know. The matter is complicated. For example, it seems that the revenues of the processing plants are dérived primarily (about 80%) from the liquids which they extract from the casinghead gas, rather than from the sale of the residue gas. We do not know how to appraise the chances that this gas would be flared rather than processed if the price were too low. For example, it might be that the processing plants would continue to purchase and process casinghead gas as long as the revenues from the liquids extracted plus those from the residue gas processed exceeded the cost of gathering, processing, and marketing the gas. As long as there is a market for the residue gas remaining after extraction of the liquids, it might be that the processor would sell it at almost any price rather than flare it, in order to recover at least part of his costs. This assumes, of course, that the processor has already made the investment in equipment necessary to purify the residue gas to make it salable, and that the operating costs of this process are not prohibitive. Conceivably, the price of the residue gas could influence the processing plants in deciding whether to maintain or install the equipment and procedures necessary to make salable quality residue gas as the liquids are being extracted. We do not know how many processors do not now have that necessary equipment or the cost of operating and maintaining that equipment.

If the processor is willing to gather and process the gas because of the value of the liquids extracted, it might be that a producer would be willing to sell its casinghead gas rather than flare it, in order to obtain some payment for the gas. On the other hand, the price of the casing-head gas might well be critical for marginal producers, whose revenues from the sale of casinghead gas justify keeping their oil wells in production. But we have no evidence concerning how many oil producers in the Permian Basin area could be termed “marginal.”

It may be that the posture of Hope was the reason why this phase of the case was not developed. Whatever the reason, it must be developed if the interest of the producing States is not by judicial fiat to be subjected entirely to complete federal supremacy, contrary to the promise in the Natural Gas Act.

       Section 5 (a) provides in pertinent part that “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 ....”'

       Section 1 (b), 15 U. S. C. §717 (b), provides in part that the “provisions of this Chapter shall apply ... to the sale in interstate commerce of natural gas for resale for ultimate public consumption for domestic, commercial, industrial, or any other use ....’’ We shall, for convenience, hereafter describe sales within the Commission’s regulatory authority as “jurisdictional” or “interstate” sales.

       The Permian Basin was defined by the Commission's order commencing these proceedings so as to include Texas Railroad Commission Districts Nos. 7-C and 8, and the New Mexico counties of Lea, Eddy, and Chaves. Area Rate Proceeding No. AR61-1, 24 F. P. C. 1121, 1125.

       There were some 384 parties before the Commission, including 336 gas producers. Hearings began on October 11, 1961, and closed on September 10, 1963. The final transcript included more than 30,000 pages. The examiner’s decision was issued on September 17, 1964. The Commission heard three days of oral argument, and issued its decision on August 5, 1965. A supplementary opinion denying applications for rehearing was issued on October 4, 1965.

       Indeed, §1 (b), 15 U. S. C. §717 (b), provides in part that the “provisions of this Chapter . . . shall not apply to . . . the production or gathering of natural gas.”

       Independent producers are those that do “not engage in the interstate transmission of gas from the producing fields to consumer markets and [are] not affiliated with any interstate natural-gas pipeline company.” Phillips Petroleum Co. v. Wisconsin, 347 U. S. 672, 675.

       This position was first adopted by the Commission in Columbian Fuel Corp., 2 F. P. C. 200. See also Billings Gas Co., 2 F. P. C. 288; Fin-Ker Oil & Gas Production Co., 6 F. P. C. 92; Tennessee Gas & Transmission Co., 6 F. P. C. 98.

       Section 4(a), 15 U. S. C. § 717c (a), provides that “All rates and charges made, demanded, or received by any natural-gas company for or in connection with the transportation or sale of natural gas subject to the jurisdiction of the Commission, and all rules and regulations affecting or pertaining to such rates or charges, shall be just and reasonable, and any such rate or charge that is not just and reasonable is hereby declared to be unlawful.”

       See generally Phillips Petroleum Co., 24 F. P. C. 537, 542.

       It has been observed that costs-of-service standards are “most generally accepted in the regulation of the levels of rates” charged by both publicly and privately owned utilities. J. Bonbright, Principles of Public Utility Rates 67 (1961).

       It has been said that “the primary, even though not the sole, distinguishing feature of a public utility enterprise is to be found in a technology of production and transmission which almost inevitably leads to a complete or partial monopoly of the market for the service.” Bonbright, supra, at 10. See also Sunray Oil Co. v. FPC, 364 U. S. 137, 160 (dissenting opinion).

       The Commission in its second Phillips opinion stated that there were then 3,372 independent producers with rates on file; these producers had on file 11,091 rate schedules and 33,231 supplements to those schedules. There were, at the moment of the Commission’s opinion, 570 producers involved in 3,278 rate increase filings awaiting hearings and decisions. 24 F. P. C., at 545. See for listings by sales of natural gas producers, Federal Power Commission, Sales by Producers of Natural Gas to Natural Gas Pipeline Companies 1963, 1 (1965).

       The Commission stated in its second Phillips opinion that “if our present staff were immediately tripled, and if all new employees would be as competent as those we now have, we would not reach a current status in our independent producer rate work until 2043 A. D.— eighty-two and one half years from now.” 24 F. P. C., at 546. It added that if “the plan of rate regulation we here announce is not lawful,” it would follow that “as a practical matter, adequate regulation of producers appears to be impossible under existing law.” Id., at 547.

       Landis, Report on Regulatory Agencies to the President-Elect, printed for use of the Senate Committee on the Judiciary, 86th Cong., 2d Sess., 54. Contrast Landis, Theoretical and Practical Considerations with Reference to Price Regulation in Production and Transmission of Natural Gas, 13th Oil & Gas Inst. 401, 406 (1962).

        Phillips Petroleum Co., supra, at 542-548.

        Id., at 547; Statement of General Policy No. 61-1, 24 F. P. C. 818.

        Area Rate Proceeding (Hugoton-Anadarko Area) No. AR64--1, 30 F. P. C. 1354, 1359 (dissenting opinion of Commissi oner Ross).

       We are informed that four other area proceedings are pending in various stages before the Commission. These, in combination with the present proceeding, reach some 90% of the sales of natural gas subject to the Commission’s jurisdiction. Brief for the Federal Power Commission 14-15.

        Phillips Petroleum Co., supra, at 548.

       It is proper to note that certain of the Commission’s statements in Phillips concerning the difficulties of unit cost computations do not appear to have been entirely reaffirmed in its opinion in these proceedings. The two opinions are, however, broadly consistent, and the Commission is not, in any event, forbidden “to adapt [its] rules and practices to the Nation’s needs in a volatile, changing economy.” American Trucking v. A., T. & S. F. R. Co., 387 U. S. 397, 416.

       The Statement provided separate guideline prices for initial filings and for increased rates. The Commission said merely that “prices in new contracts are, and in many cases by virtue of economic factors, must be higher than the prices contained in old contracts.” 24 F. P. C., at 819. The guideline prices applicable to the producing areas subsequently included in these proceedings were in each case 160 and 110 per Mcf, with the higher price for initial filings.

       Statement of General Policy No. 61-1, supra, at 818.

       The Commission defined gas-well gas as “gas from dry gas reservoirs and gas condensate reservoirs, and gas from gas-cap wells.” It added that gas-cap gas is “a special category of gas from an oil reservoir that can be produced free from the influence of oil production.” 34 F. P. C. 159, 189 and n. 23. Residue gas derived from new gas-well gas is also to be subject to higher maximum rate. See id., at 211.

       Natural gas is variously classified, and certain of the descriptive names that will be employed in this opinion should be briefly explained. Casinghead gas is “the common name for gas produced from oil wells in conjunction with the production of oil.” 34 F. P. C., at 208. Residue gas is “the gas remaining after casing-head gas or gas-well gas has been processed to remove liquids present in the raw gas stream in the form of vapor or droplets.” Id.., at 210. Associated gas is “[f]ree natural gas in immediate contact, but not in solution, with crude oil in the field or reservoir.” American Gas Association, 1966 Gas Facts 246 (1966). Dissolved gas is that “in solution with crude oil in the reservoir.” Ibid. Oil-well gas encompasses associated, dissolved, and casinghead gas, together with residue derived from casinghead gas. In addition, we shall adopt the Commission's usage, and on occasion describe gas subject to the lower maximum rate as “old” or “flowing” gas. 34 F. P. C., at 212, n. 31.

       Joint costs “are incurred when products cannot be separately produced . . . .” M. Adelman, The Supply and Price of Natural Gas 25 (1962). Compare the following: “Products are 'truly joint’ if they must be produced together and in constant proportions. Truly joint costs are variable costs. They vary (as a total) with the output of the entire set (fixed combination) of joint products.” F. Machlup, The Economics of Sellers’ Competition 21 (1952). And see Bonbright, sufra, at 354-357. It appears to be conceded that even gas-well gas has costs jointly, as well as in common, with petroleum, but the Commission evidently, and permissibly, believed that the difficulties of allocation connected with gas-well gas were relatively uncomplicated. See 34 F. P. C., at 214r-215, 339.

       A Btu, or British thermal unit, is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit under stated conditions of pressure and temperature.

       Tabular summaries of the cost components from which the distributors and the producers derived recommended rates for new gas-well gas may be found in the examiner’s opinion. 34 F. P. C., at 343. Based on allowances for production investment costs, return, exploratory costs, royalty and production taxes, and other factors, the producers recommended a rate of 23.24*4 per Mcf; the distributors derived from the same factors a rate of 15.39(4 per Mcf. See also id., at 357. Similar tables summarizing the Commission’s findings were included in its opinion. Id., at 192, 220.

       The Commission excluded New Mexico state production taxes because they are not uniform throughout the three counties. See the Commission’s opinion denying applications for rehearing, 34 F. P. C., at 1074.

       Section 4(d), 15 U. S. C. § 717e (d), provides in part that “[ujnless the Commission otherwise orders, no change shall be made by any natural-gas company in any such rate, charge, classification, or service, or in any rule, regulation, or contract relating thereto, except after thirty days’ notice to the Commission and to the public.”

       The restricted contract provisions include most-favored-nation, spiral escalation and redetermination clauses. See Pure Oil Co., 25 F. P. C. 383, 388, n. 3. They were said by the examiner to “cause price increases ... to occur without reference to the circumstances or economics . . . .” 34 F. P. C., at 373 (initial decision of the presiding examiner).

       Many of the refund obligations in question here stem from the consolidation of proceedings conducted in connection with filings for rate increases under § 4 (d). For purposes of these filings and of the attendant refund obligations, these proceedings were conducted under § 4 (e). Area Rate Proceeding No. AR61-1, 24 F. P. C. 1121.

       The various parties before the Court have taken quite disparate positions. The distributing companies, with the exception of amici, and the public authorities, with the exceptions of the States of Texas and New Mexico, have all supported the Commission’s orders in their entirety. They urge that “consumers . . . have waited long enough,” and assert that “no good purpose can be served by further proceedings.” See Joint Brief for the City of San Diego and the City and County of San Francisco 24. Certain of the producers support the judgment below; others challenge the validity of portions of the Commission’s orders that were sustained below. We have, nonetheless, frequently not indicated which of the parties join, and which oppose, various contentions. This does not suggest that we do not recognize differences in position; we want merely to simplify, so far as possible, an already lengthy opinion.
      One further comment is pertinent. The organization and presentation of issues is, of course, a matter for the judgment of counsel. Nonetheless, it is proper to remark that the effectiveness and clarity with which issues are presented in cases of this complexity might be significantly increased if even greater efforts were made to focus and consolidate argumentation on behalf of parties with essentially similar views.

       The opinion of the Court stated simply that “[w]e recognize the unusual difficulties inherent in regulating the price of a commodity such as natural gas. We respect the Commission’s considered judgment, backed by sound and persuasive reasoning, that the individual company cost-of-service method is not a feasible or suitable one for regulating the rates of independent producers. We share the Commission’s hopes that the area approach may prove to be the ultimate solution.” 373 U. S., at 310 (note omitted).

       Compare Bowles v. Willingham,, supra, at 517.

       The Court of Appeals remarked that “[o]ut-of-pocket expenses are not defined and we do not know what they include.” 375 F. 2d, at 30. It is certainly true that the Commission proffered no definition, but we cannot regard this as a fatal omission.

       Section 7(b), 15 U. S. C. §717f(b), provides that “[n]o natural-gas company shall abandon all or any portion of its facilities subject to the jurisdiction of the Commission, or any service rendered by means of such facilities, without the permission and approval of the Commission first had and obtained, after due hearing, and a finding by the Commission that the available supply of natural gas is depleted to the extent that the continuance of service is unwarranted, or that the present or future public convenience or necessity permit such abandonment.”

       Indeed, Commissioner Ross has already urged that the Commission modify its area proceedings so as to reflect the essentially national character of the relevant issues. Area Bate Proceeding {Hugoton-Anadarko Area) No. AR64--1, 30 F. P. C. 1354, 1359-1362 (dissenting opinion). Moreover, we note the “essential amalgamation” of the Hugoton-Anadarko and Texas Gulf Coast area proceedings before the Commission, where “identical issues were heard on a joint record.” 1 Joint Initial Staff Brief in Area Rate Proceedings Nos. AR64-1 and AR64r-2, 1. Finally, we must emphasize that we understand the present proceeding to be merely the first of many steps toward a more expeditious and effective system of regulation.

       34 F. P. C., at 227.

       See, e. g., Transcontinental Gas Pipe Line Corp., 34 F. P. C. 584.

         We obtain additional assistance from §16; it provides that the Commission “shall have power to perform any and all acts, and to prescribe . . . such orders, rules, and regulations as it may find necessary or appropriate to carry out the provisions of this” Act. 15 U. S. C. § 717o.

         Section 4 (d) is set out at n. 29, supra.

       Section 4(e), 15 U. S. C. §717c(e), provides in part that “[wjhenever any such new schedule is filed the Commission shall have authority, either upon complaint ... or upon its own initiative ... to enter upon a hearing concerning the lawfulness of such rate, charge, classification, or service; and, pending such hearing and the decision thereon, the Commission . . . may suspend the operation of such schedule and defer the use of such rate . . . but not for a longer period than five months beyond the time when it would otherwise go into effect; and after full hearings, either completed before or after the rate, charge, classification, or service goes into effect, the Commission may make such orders with reference thereto as would be proper in a proceeding initiated after it had become effective. If the proceeding has not been concluded and an order made at the expiration of the suspension period . . . the proposed change of rate . . . shall go into effect. Where increased rates or charges are thus made effective, the Commission may, by order, require the natural-gas company to furnish a bond . . . and, upon completion of the hearing and decision, to- order such natural-gas company to refund, with interest, the portion of such increased rates or charges by its decision found not justified.”

       See n. 1, supra.

       34 F. P. C., at 228.

        Id., at 230.

       The Commission has elsewhere provided brief definitions of the pertinent types of clauses. See generally Pure Oil Co., 25 F. P. C. 383. Two-party most-favored-nation clauses are those “activated by higher prices paid to any other supplier by the same purchaser.” Three-party most-favored-nation clauses are “activated by higher prices paid to any other supplier by any purchaser.” Spiral escalation clauses provide “that in the event the price which the buyer receives for the gas is increased, the price concurrently paid by the buyer to the supplier under the contract shall be increased in proportion to the buyer’s increase.” Redetermination clauses provide “that the price currently paid under the contract shall be subject to upward adjustment at certain specified times to reflect the average of the highest prices then paid by buyers to other suppliers for gas delivered under substantially similar terms and conditions.” Id., at 388, n. 3.

       Order No. 232, 25 F. P. C. 379. This was subsequently modified by Order No. 242, 27 F. P. C. 339. See 18 CFR § 154.93.

       The Commission stated in its Order No. 242 that indefinite escalation clauses “have created a significant portion of the administrative burdens under which this Commission is laboring,” and that they produce a “flood of almost simultaneous filings” that “bear no apparent relationship to the economic requirements of the producers who file them.” 27 F. P. C. 339, 340. See also 5 Joint Appendix 1858-1859.

       The Commission defined a small producer as one “selling jurisdictionally less than 10,000,000 Mcf annually on a nationwide basis.” 34 F. P. C., at 235. See further the testimony of producer witness Abel, 1 Joint Appendix 339-342. This would include some 250 of the filing producers in the Permian Basin, leaving some 40 large producers. Under this definition, there are some 2,000 small producers in the United States, and 75 large producers. 34 F. P. C., at 235. See also Federal Power Commission, Sales by Producers of Natural Gas to Natural Gas Pipeline Companies 1963, 1-6 (1965).

       The examiner observed that the “basic difference between the small and the large producer is that the risks of the business are materially different for each.” 34 F. P. C., at 360. Compare 1 Joint Appendix 318-319, 328-332.

       These questions were discussed at length in testimony before the examiner on behalf of the Texas Independent Producers and Royalty Owners Association, and others. See generally 5 Joint Appendix 1655-1714, 1773-1787; 1 id., at 224-232, 255. And see Supplement to Joint Appendix 3s-6s.

       The examiner stated that small producers had “relatively larger dry hole expenses, a smaller proportion of geological and geophysical expenses, and a smaller proportion of lease acquisition expenditures”; he added that they had relatively larger depletion, depreciation, and amortization expenses. 34 F. P. C., at 361. The examiner also found that the “ratios of income available for' income taxes, cash dividends, and working capital to net investment were 7.8, 2.5, and 7.4 for the large producers, small producers and for the weighted average.” Ibid. See also testimony at 3 Joint Appendix 1114-1116.

       The Commission found that they provide only about 15% of the total supply of natural gas moving in interstate commerce, and that “they usually cannot obtain more for their gas than the regulated price we fix for the major producers.” 34 F. P. C., at 234. And see id., at 363. On the other hand, the Commission noted that in specific situations the small producers might have a very important portion of the relevant market. Id., at 235. The examiner indicated that “[f]ewer than 50” large producers sell 87% of the gas sold from the Permian Basin under the Commission’s jurisdiction. Id., at 361.

       It should be noted that the small producers did not at first wish any special exemptions; they evidently feared that any such exemptions might cause the Commission to ignore their difficulties, and ultimately perhaps to permit them to be priced out of the industry. These discussions may be traced at 5 Joint Appendix 1692-1714.

       Correspondingly, the small producers need not take quality adjustments into account for purposes of refunds, unless they wish to take advantage of upward price adjustments because of high Btu content. 34 F. P. C., at 233.

       It is pertinent that the Commission estimated regulatory expenses, for purposes of the calculation of area maximum rates, at 0.140 per Mcf. The Commission stated that “no participant disputes its inclusion . . . 34 F. P. C., at 197. In contrast, it has been estimated that the total costs to producers of the Commission’s regulation are some 1.1640 per Mcf. Of this total, 0.0390 are said to arise from administration, 0.8090 from delay, and 0.3160 from contingencies. See Gerwig, Natural Gas Production: A Study of Costs of Regulation, 5 J. Law & Econ. 69, 85, 86, 88.

       It is pertinent that much of the cost and other data upon which the Commission relied reflected national, and not area or local, circumstances. Further, the Commission found that production costs in the Permian Basin did not “vary sufficiently from the national average to warrant a different treatment . . . .” 34 F. P. C., at 191. Moreover, no party offered a comprehensive cost study premised on a larger Permian Basin, although certain information relevant to adjacent areas was presented. See 1 Joint Appendix 37-41; 6 id., at 15e. But see 1 id., at 242-244.

       The rate structure is summarized above, at 759-764.

       Economists have frequently proved more candid about these difficulties. Social welfare and public interest standards have been described as “almost unique in the extreme vagueness of [their] ultimate verbal norm.” Bonbright, supra, at 27. Similarly, it is said that no writer “whose views on public utility rates command respect purports to find a single yardstick by sole reference to which rates that are reasonable or socially desirable can be distinguished from rates that are unreasonable or adverse to the public interest.” Id., at 67. But compare National Broadcasting Co. v. United States, 319 U. S. 190, 216.

       This phrase was taken by the Court of Appeals as the substance of the opinion of the Court in FPC v. Hope Natural Gas Co., supra. The court contrasted unfavorably the Commission’s assertion that it had found a “fair relationship” between the consumer interests and the producers’ costs. See 34 F. P. C., at 1074; 375 F. 2d, at 34. We are unable to find in the verbal differences between these two phrases any objection to the Commission’s orders. The Commission’s exercise of its regulatory authority must be assessed in light of its purposes and consequences, and not by references to isolated phrases from previous cases.

       The Commission found that the 2.80 per Mcf paid as an average price in 1947 had risen to 9.00 in 1954, and to 13.80 in 1960. In 1960, El Paso, the dominant pipeline company in the Basin, renegotiated its contracts and offered prices ranging from 13.50 to 170 per Mcf. 34 F. P. C., at 182. The examiner pointed out that between 1947 and 1960, the average price paid nationally by pipelines trebled, from 4.950 to 15.610 per Mfc. Id., at 312. And see 2 Joint Appendix 423-432.

       It appears that five producers were responsible in 1960 for more than one-half of all the natural gas sold from the Basin under the Commission’s regulation. Fifteen producers accounted for almost three-fourths of the sales. See Memorandum of the Texas Independent Producers and Royalty Owners Association, 5 Joint Appendix 1775, 1780. See also Analysis of Independent Producer Rate Schedules, 6 Joint Appendix 275e-293e. These questions are very usefully discussed by distributor witness Kahn at 2 Joint Appendix 410-432. He notes the significance of “a sharply rising demand operating on a sluggishly responding supply,” id., at 423, but also emphasizes the importance of the escalation clauses and of various market imperfections.

       The Commission stated that “the entire history of pipeline purchasing activity, since the end of the El Paso monopoly in the Permian Basin, has been characterized by the overriding needs of the pipelines to contract for the large blocks of uncommitted reserves essential to maintain their competitive position in developing markets . . . and their inability to accomplish this objective except at ever increasing prices.” 34 F. P. C., at 182. It is noteworthy that, despite the obvious importance of these proceedings, the pipeline companies did not take an active part here, in the Court of Appeals or before the Commission. See also 2 Joint Appendix 423-432. But see 4 id,,, at 1384-1388.

       The phrase is Commissioner O’Connor’s. 34 F. P. C., at 252 (opinion concurring and dissenting on limited issue). It is proper to note that he would have made much wider use of field prices for the calculation of the area rates. Monopsony is the term used to describe a situation in which the relevant market for a factor of production is dominated by a single purchaser. See J. Robinson, The Economics of Imperfect Competition 215 (1933). The relevant market here is that for uncommitted reserves. See 2 Joint Appendix 410. Finally, for a general examination of the usefulness of the competitive model for regulation, see Bonbright, supra, at 106-108.

       It should be observed that the significance of the escalation clauses will presumably be diminished by the Commission’s series of orders restricting their use.

       Some 85% of the gas sold in interstate commerce from the Permian Basin is ultimately consumed in California. 34 F. P. C., at 174, 312. The demand for natural gas among residential and commercial consumers, once they have purchased the necessary equipment, is relatively inelastic. Id., at 313. The demand among industrial consumers is more responsive to price, but restrictions in California on the use of various industrial fuels have left industrial demand less responsive to price there than in other parts of the country. Id., at 313-314.

       Indeed, the Commission explicitly stated that “[w]e recognize that the history of negotiated prices in the area is an important element to be considered in reaching our decision.” 34 F. P. C., at 181.

       We note that economists have sometimes concluded that the market mechanism works satisfactorily in the natural gas industry. “There is ... no question but that the field price of gas in the United States is competitively determined.” Adelman, supra, at 39. See also E. Neuner, The Natural Gas Industry 125-134, 238-290 (1960). In contrast, Professor Kahn said of oil and gas that “few other industries in our entire economy . . . are so insulated . . . from the normal forces of the market.” 2 Joint Appendix 607. But see 1 id., at 217-218, 280-281. And see R. Hooley, Financing the Natural Gas Industry 5-25 (1961).

        Colorado Interstate Co. v. FPC, 324 U. S. 581, 612 (concurring opinion).

       The examiner found that the larger producers could now predict with high accuracy whether drilling in a particular area would be likely to produce associated or unassociated gas. 34 F. P. C., at 325-329. This appears primarily to be the consequence of accumulated experience, and not of any improvement in technology. See also 2 Joint Appendix 558, 581; 1 id,., at 56, 307-308. Useful statistical evidence of predictability may be found in producer testimony. See 3 id., at 952-955, 963, 965-967, 1079-1080. And see 7 id., at 572e-575e. It should be noted that the Commission’s staff denied that gas could be separately sought. 3 id., at 933-934.

         Estimates of the moment at which directional search became possible varied; one witness testified that Phillips regarded January 1, 1959, as an appropriate date of calculation. 1 Joint Appendix 56.

       See 34 F. P. C., at 273. But contrast the testimony of distributor witness Kahn, who recognized that it would be “in some measure arbitrary” to give the lower price to gas wells that began production after 1960 but before the Commission’s final decision in these proceedings. 2 Joint Appendix 635.

       The Statement provided a guideline price of 16$ per Mcf for initial filings, and 11$ per Mcf for previously committed gas. 24 F. P. C., at 820. The Commission indicated that this was in recognition of “economic factors.” Id., at 819.

       It is pertinent that Gerwig found that a premium of 1.160 per Mcf is necessary before producers rationally enter the interstate market. Gerwig, supra, at 85. See also Kitch, The Permian Basin Area Rate Cases and the Regulatory Determination of Price, 116 U. Pa. L. Rev. 191, 207. Compare Johnson, Producer Rate Regulation in Natural Gas Certification Proceedings: CATCO in Context, 62 Col. L. Rev. 773, 784, n. 61. Finally, see the testimony of producer witness Foster, 1 Joint Appendix 142-144.

       We see no objection to the Commission’s preference for January 1, 1961, instead of December 23, 1960, the date on which it issued the order commencing these proceedings. This choice was adequately justified by administrative convenience.

       It should be observed that the witness chiefly responsible for the contrivance of the two-price system ultimately adopted by the Commission, see 2 Joint Appendix 510-513, 576-585, 601-611, has elsewhere described the need for close restraints on increases in the price for natural gas. Kahn, Economic Issues in Regulating the Field Price of Natural Gas, 50 Am. Econ. Rev. 506, 510-514. See also Kitch, supra, at 211-212.

       34 F. P. C., at 191. And see id., at 339-340.

       It should be noted that the parties proffered a list of sources of information, to which the examiner gave his approval. See 1 Joint Appendix 291-305, 309-310. These were said by the parties to be “recognized, published statistical data sources.” Id., at 292. The Commission described them as “well-recognized and authoritative.” 34 F. P. C., at 191. Nonetheless, careful efforts were made to determine whether these and other sources of evidence, including the producers’ questionnaires, were, as to the various cost components, accurately representative of the relevant groups of producers. See, e. g., id., at 377, 378, 380, 381, 384, 387, 392, 393.

       Three sets of questionnaires were used. Appendix A was applicable to all producers, and concerned chiefly drilling costs. Appendix B was required of large producers, and concerned costs, revenues and production. Appendix C was a simplified version of Appendix B, which small producers were permitted to use. The producers have argued vigorously that these questionnaires did not provide a sufficient basis for the Commission’s findings. We cannot agree. The Commission reasonably concluded, as had the examiner, that the Appendix C questionnaires received from small producers were not necessarily representative. 34 F. P. C., at 214. And see 3 Joint Appendix 1117-1118. Moreover, the addition of the Appendix C data from the small producers would evidently not have produced a significant change in the ultimate cost components. See 34 F. P. C., at 214, 392-393, 400. Further, the Commission found that the responses to the Appendix B questionnaires received from 25 small producers would not have “change [d] the results.” Id., at 214, n. 34. Of the 43 large producers that filed Appendix B questionnaires, the staff and Commission disregarded only one, which had not been properly completed. See generally 2 Joint Appendix 731-748; 3 id,., at 753-761. In these circumstances, the Commission concluded, we think reasonably, that “the data provided by the major producers with respect to their Permian production was fully representative of area costs 34 F. P. C., at 214. This Court has repeatedly held that administrative agencies may “proceed on a group basis ... on ‘evidence which the Commission assumed was typical in character, and ample in quantity’ to justify its findings . . . ." Chicago & N. W. R. Co. v. A., T. & S. F. R. Co., 387 U. S. 326, 341, quoting New England Divisions Case, 261 U. S. 184, 196-197. The Commission has here reasonably found that the evidence before it satisfied these requirements; we therefore find no objection.

       See generally the examiner’s discussion, 34 F. P. C., at 393-400. Economists have described these difficulties with repetitive pungency. “To make laborious computations purporting to divide [such] costs is ‘nonsense on stilts,’ and has no more meaning than the famous example of predicting the banana crop by its correlation with expenditures on the Royal Navy.” Adelman, supra, at 25. See also Machlup, supra, n. 25, at 21; Bonbright, supra, at 339-342. Compare Eckstein, Natural Gas and Patterns of Regulation, 36 Harv. Bus. Rev. 126, 129-133; and Kahn, supra, at 510-514.

       By one estimate, the costs of nonassociated gas are 45% separate, 31% joint, and 24% common. See 34 F. P. C., at 339. All of the costs of associated gas are joint. Ibid. But see Kitch, supra, at 202.

       34 F. P. C., at 1072. None of the distributors or public agencies before the Court, except amid, have argued that this permits excessively generous returns to producers. Indeed, representatives of the consumers who ultimately purchase most of the gas produced in the Permian Basin have urged us to avoid “long extensive delays” and to affirm the Commission’s orders in their entirety. See, e. g., Brief for the City of Los Angeles 6; Joint Brief for the City of San Diego and the City and County of San Francisco 24; Brief for People of the State of California 63. These parties did not petition the Court of Appeals to review the Commission’s orders, and participated below only as intervenors in full support of the Commission’s position. Even assuming arguendo that, these questions are not now foreclosed by § 19 (b), we can find no basis on which to set aside the area rates as excessive. As we shall show below, the rate of return permitted the producers does not substantially exceed that ordinarily allowed to pipelines. Further, it must be recalled that the area maximum rates were, even before adjustment for quality and Btu deficiencies, intended to approximate average unit costs. Finally, we note that the Commission’s area rate for new gas-well gas, after adjustment for average quality deficiencies, very nearly equals that originally proposed by distributor and consumer representatives. Compare 34 F. P. C., at 343, and at 1073. We cannot say that the Commission’s rates are above the “zone of reasonableness” permitted by the Natural Gas Act.

       These questions are usefully discussed in Bonbright, supra, at 240-283. See also the Commission’s discussion of the true yield method. 34 F. P. C., at 202. Compare 4 Joint Appendix 1267, 1406-1416. And see the Initial Decision of the Presiding Examiner in Area Rate Proceeding (Southern Louisiana Area), No. AR61-2, issued December 30, 1966, at 75-85.

       34 F. P. C., at 201. Compare id., at 343-352. And see for estimates of more recent equity allowances, Brief for the Federal Power Commission 144, n. 16.

       The examiner found that nonintegrated producers had an average debt of approximately 12%. The pipelines were found to have debts “sometimes as large as 70 percent of total capitalization ...” 34 F. P. C., at 345. See also contrasting testimony at 1 Joint Appendix 173-177; and 2 id., at 614-626. It is proper to observe that it has sometimes been argued that the leverage of high borrowings itself creates certain financial risks. But see G. Stigler, Capital and Rates of Return in Manufacturing Industries 64, n. 15 (1963). Finally, it should be noted that risk has on occasion been regarded as cause for a reduction of the rate of return. See C. Hardy, Risk and Risk-bearing 37-38 (1931).

       As will appear below, we find the Commission’s discussion of relative financial risks imprecise. There is, however, a plain statement in the Commission’s opinion to the effect that exploration and production are financially more hazardous than transmission. See 34 F. P. C., at 201. The Commission did not indicate clearly whether it considered production taken in the aggregate as more hazardous than the affairs of an individual pipeline company, or indeed even whether it considered such aggregate calculations relevant.

       See the discussion at 34 F. P. C., at 203-204. And see id., at 349-352. Finally, see 3 Joint Appendix 850-936.

       But see Kitch, supra, at 201. See also Stigler, supra, at 62-64.

       It has been argued with force that the producers were not given fair notice that the Commission might promulgate such standards. It appears that the Commission did not announce in terms that it might create quality standards, and that it tacitly denied a motion to consolidate this proceeding with a rule-making proceeding intended to devise national quality standards. We cannot say that the Commission impermissibly refused to complicate still further this proceeding by the addition of issues centering on national quality standards. Moreover, the general terms of the Commission’s order commencing this proceeding reasonably encompassed questions of quality standards, 24 F. P. C. 1121, 1124, and we do not regard the Commission’s denial of the consolidation motion as foreclosing the ultimate adoption of such standards. The producers’ motion was premised on the desirability of national standards, and explicitly recognized that prices and differences in quality “are so inextricably tied together that they cannot be meaningfully separated one from the other.” 9 Joint Appendix 69d, 71d. We cannot hold that the Commission denied the producers fair notice that it might as a consequence of these hearings impose quality standards.

       It is argued vigorously that the standards adopted by the Commission lack substantial basis in the record. Emphasis is placed chiefly on the examiner’s statement that it would be “probably impossible on this record ... to establish a complete set of differentials for the various value and quality characteristics of gas.” 34 F. P. C., at 368. See also 1 Joint Appendix 123-136. We believe this statement to be inapposite to the issues before us. The Commission did not create such a set of differentials; it merely posited a series of pipeline standards, and placed the responsibility for reaching specific price differentials upon the parties to each sale. It indicated that it would accept any agreement that appeared to be a good-faith effort to determine the pertinent processing costs. It should be noted that at least one witness testified that negotiation among the relevant parties is the proper method for measurement of processing costs. See 3 Joint Appendix 983. Further, various estimates of quality adjustments were provided by witnesses before the examiner. See 5 id., at 1769-1771, 1867-1899, 1907-1908. We conclude that the Commission’s findings on these questions are adequately supported by the record.

       Commissioner O’Connor argued forcefully in a concurring and dissenting opinion that the Commission’s adoption of high and low Btu standards was unfair to producers. 34 F. P. C., at 267-268. The Court of Appeals indicated that it was unable to understand the reasons for the dual standard. 375 F. 2d, at 31. We agree that the Commission might have dealt more clearly with these questions, but we have found no basis on which we can set aside its judgment. The Commission found that, by prevailing practice, the minimum Btu standard in the Permian Basin was 1,000 per cubic foot; the average Btu.content is, however, in a range of 1,034 to 1,042 per cubic foot. 34 F. P. C., at 223, 267-268. It concluded that it would require downward price adjustments only where Btu content is less than 1,000, and permit upward adjustment only where it exceeds 1,050 per cubic foot. Although this is evidently less favorable to producers than other possible formulae, we have found no evidence that suggests that it is arbitrary, or an abuse of the Commission’s authority. Compare Initial Decision, Area Rate Proceeding (Southern Louisiana Area), No. AR61-2, issued December 30, 1966, at 180-183.

       The Commission pointed out that sellers of gas-well gas receive payments for “liquid hydrocarbons extracted from the gas by the pipelines.” 34 F. P. C., at 1073. These payments may amount to 0.60 to 0.8$ per Mcf in the Permian Basin. Ibid. An allowance of only 0.20 per Mcf was incorporated by stipulation in the new gas-well gas rate. Id., at 388. Moreover, producers receive “substantial payments” for liquids extracted from oil-well gas sold under Spraberry contracts. Id., at 1073. And see n. 111, infra. Compare 34 F. P. C., at 208-209.

       The Commission’s order accepting quality statements filed by producers in the Permian Basin indicates that the adjustments average 0.780 per Mcf for old gas-well gas, and 0.860 per Mcf for old residue gas. 37 F. P. C. 52, 53.

       Brief for the Federal Power Commission 141.

       The Commission emphasized that because exploration “is fraught with uncertainties foreign to its transmission,” a “greater return” should be allowed. 34 F. P. C., at 201. Nonetheless, as we have found, the rate of return actually permitted by the Commission, after allowance for quality and other adjustments, does not substantially exceed that permitted to pipelines. We note, however, that the risks incidental to exploration have not always been thought to be greatly in excess of those incidental to transmission. See Kiteh, supra, at 201. And see on the insurance principle, Nelson, Percentage Depletion and National Security, reprinted in Federal Tax Policy for Economic Growth and Stability, papers submitted to the Joint Committee on the Economic Report, 84th Cong., 1st Sess., 463, 470 (Comm. Print 1955). See also Dirlam, Natural Gas: Cost, Conservation, and Pricing, 48 Am. Econ. Rev. 491, 498. And compare 3 Joint Appendix 907.

        FPC v. Hope Natural Gas Co., supra, at 602.

       The Commission first emphasized that “we make clear that we do not confine ourselves to a cost calculation in determining just and reasonable rates.” 34 F. P. C., at 190. It later said that “there is no justification in this area for any adjustment of a cost-determined ceiling price.” It added that “no such [noncost] adjustments are required in the Permian Basin.” Id., at 207. Yet it is quite plain that the Commission’s rate structure is, and was intended to be, significantly influenced by “non-cost considerations.” Unfortunately, the Commission never paused to reconcile these general observations with the specific terms of its rate structure.

       We understand the principal points at which the Commission employed noncost factors to be four. It used the logic of functional pricing to justify both its two-price rate structure and its selections of sources of cost data. Second, it explained its imposition of a single maximum rate upon all old gas by, among other reasons,- the importance of a relatively uncomplicated rate structure. Third, the Commission justified its adoption of a temporary period of price restriction by the exigencies of area regulation. Fourth, the Commission based its calculation of the rate of return upon risk factors that it did not directly reduce to cost components.

       We are cognizant, as presumably is the Commission, of the forceful argument that the computation of rates from costs is ultimately circular. See Kitch, supra, at 195-196; compare Kahn, supra, at 510-514. See also Eckstein, supra, at 129-131. The Commission has not, however, relied simply upon cost computations, and we have found no basis on which we could now properly set aside the Commission’s orders. We assume that the Commission will continue to examine both the premises of its regulatory methods and the consequences for the industry’s future of its rate-making orders. Nothing under the Act or the cases of this Court compels the Commission to reduce its regulatory functions to self-fulfilling prophecies. Compare City of Detroit v. FPC, 230 F. 2d 810, 818.

       The ratio “has been as high as 32.5 to 1 in 1946 and it has steadily declined to about 18.7 to 1 in 1963 . . . .” 34 F. P. C., at 183. At year end of 1965, proved recoverable reserves totaled 286.5 trillion cubic feet; withdrawals in 1965 were 16.25 trillion cubic feet. American Gas Association, 1966 Gas Facts 1 (1966). These questions may be traced in testimony at 1 Joint Appendix 20-34, 76-95, 97-111, 352-360 ; 2 id., at 459-471. See also Hooley, supra, 5-25.

       In 1965, “[g]ross additions to reserves aggregated 21.3 trillion cubic feet, the third highest since the Natural Gas Reserves Committee initiated its reports in 1946.” American Gas Association, supra, at 5. Further, “[o]ver the past twenty years, gross additions have resulted in more than 343 trillion cubic feet being added to the nation's proved reserves of natural gas. During this same period, net production of natural gas totaled 207 trillion cubic feet.” Ibid. See for similar evidence, American Gas Association, 1967 Gas Facts 5 (1967). It is, however, proper to recognize that the ratio of new discoveries to annual net production has generally declined since 1946, although the decline is neither steep nor consistent. See 34 F. P. C., at 319; 1 Joint Appendix 76-95, 97-111. And see generally Cram, Introduction to the Problem of Developing Adequate Supplies of Natural Gas, Southwestern Legal Foundation, Economics of the Gas Industry 1 (1962).

       It is pertinent that the American Gas Association in 1957 observed of the reserves-to-production ratio that so “long as new additions exceed production there need be little cause for concern about such an hypothetical ratio.” 1957 Gas Facts 6 (1957). See for similar evidence 34 F. P. C., at 309-317.

       The producers have argued vigorously that 20 to 1 is the minimum reserves-to-production ratio. There is, however, ample evidence to support the Commission’s judgment that lower ratios are permissible. One intervenor witness forcefully described the concern for that ratio as a “neurotic preoccupation.” 1 Joint Appendix 357. See also id., at 352-360; and 2 id., at 459-471. These questions are usefully discussed in Terry, Future Life of the Natural Gas Industry, Southwestern Legal Foundation, supra, at 275, 284-285; and in Netschert, Economic Aspects of Natural Gas Supply, id., at 27, 56-68.

       Indeed, the Commission described the adequacy of reserves as “an important factor in our determination here,” and said that it will “continue to be an important factor in reviewing area rates in the future . . . .” 34 F. P. C., at 185.

       There appears to be some uncertainty about the appropriate figures. Compare Brief for the Federal Power Commission 96. The producers’ use of 12.720 per Mcf is supported by 7 Joint Appendix 538e.

       Certain of the producers urge that the Commission described 14.50 and 16.50, unadjusted for quality deficiencies, as the just and reasonable rates for the Permian Basin. This ellipsis may sometimes have entered the Commission’s opinion, but on fair reading its intentions seem entirely clear. See 34 F. P. C., at 239.

       It is pertinent to reiterate that the Commission has recently calculated the actual adjustments required by the quality statements filed by producers in the Permian Basin through August 31, 1966, as 0.780 per Mcf for old gas-well gas and 0.860 per Mcf for old residue gas. Area Rate Proceeding (Permian Basin Area), 37 F. P. C. 52, 53.

       The Commission stated that “the evidence in the record makes clear that with respect to casinghead gas and residue gas derived therefrom (which together make up by far the largest share of the Permian gas subject to quality adjustments) the costs are substantially below the 14.5 cents per Mcf ceiling price.” 34 F. P. C., at 1072. And see id., at 356-360.

       The Commission pointed out that there was evidence that suggested that these payments average 0.60 to 0.80 per Mcf for gas-well gas in the Permian Basin. 34 F. P. C., at 1073.

       The new gas-well gas rate includes a credit of 0.2$ per Mcf for plant liquids. 34 F. P. C., at 197, 1073. This figure was determined by stipulation. Id., at 388. No such credit was included in the flowing gas rate.

       The Spraberry, or El Paso, contract is one which provides “for the purchase of casinghead gas by a pipeline which processes the gas, pays the producer a percentage of the proceeds from the sale of the extracted liquids, plus a fixed price for the residue gas delivered to the pipeline.” 34 F. P. C., at 208. The presiding examiner would have essentially prohibited such contracts in the Permian Basin, but the Commission declined to do so. Nonetheless, it asserted jurisdiction, we think properly, over the sale of casinghead gas under the contract. The Commission indicated that the producers’ revenue from the contracts for the extracted liquids is “substantial.” 34 F. P. C., at 1073.

       Compare 34 F. P. C., at 209 and 1072.

       The Commission’s calculation of the minimum rate was, however, left largely unexplained. The Commission clearly found that “the establishment of minimum rates in this case is in the public interest and that the price impact on the consumer will be de minimis.” 34 F. P. C., at 231. It failed to offer any explanation of its selection of 90 as the minimum rate, relying entirely on the examiner’s preference for that figure. The examiner adopted two minimum rates: 90 per Mcf for residue and gas-well gas, and 70 per Mcf for casinghead gas. His calculations were evidently premised on his computation of the revenue standard for the various classes of natural gas. See id., at 369. The composite explanation for the choice of 90 as the area minimum rate is thus imprecise. Nonetheless, the Commission reasonably concluded that a minimum rate was imperative, and there is no evidence before us that permits the conclusion that its selection was unjust or unreasonable.

       Two additional issues should properly be separately considered. First, the States of Texas and New Mexico have urged that we reconsider Hope, and require the Commission to give special weight to the probable effects of its orders on the economies of producing States. We have examined these contentions, but decline to modify the treatment of the similar questions in Hope. See 320 U. S., at 607-614. As we said there, we do not “suggest that Congress was unmindful of the interests of the producing states . . . when it drafted the Natural Gas Act.” Id., at 612. But to go as far as Texas and New Mexico now ask “raises questions of policy which go beyond our province.” Id., at 614.
      Second, the Commission indicated that it would apply these area rates to sales initiated during the pendency of these proceedings. 34 F. P. C., at 237. See order issuing certificates, id., at 418. The effect of this order is to impose these rates as the in-line rate for the Permian Basin for periods prior to the Commission’s decision in these proceedings. See generally United Gas v. Callery Properties, 382 U. S. 223, 226-228. The Court of Appeals found it unnecessary to decide the propriety of this arrangement. 375 F. 2d, at 35-36. Nonetheless, we believe that in the circumstances here presented it is appropriate to resolve this issue without awaiting consideration by that court. Compare Chicago & N. W. R. Co. v. A., T. & S. F. R. Co., 387 U. S. 326, 355-356. We hold that the Commission was not forbidden to employ the area rates as the in-line rate for purposes of sales initiated after commencement of its proceedings, but before its final decision. The area rates were properly calculated as the just and reasonable rates for the Permian Basin for periods subsequent to the periods at issue, on the basis of cost factors believed to be stable throughout these periods. As the Commission observed, to prevent their use as the in-line rate “would require an unending succession of Section 5 area rate proceedings, each covering only the sales instituted prior to the institution of the proceeding.” 34 F. P. C., at 237. We need not, however, determine for what further periods or in what other circumstances the Commission may use unadjusted area rates as in-line rates. Orders involving § 7 proceedings commenced after the Commission’s decision in these proceedings were not before the Commission, and are not now before the Court.

       It is, however, proper to take special notice of various arguments that have been vigorously pressed by certain of the producers. First, it is urged that the Commission should have included an allowance for federal income taxes in the rate for new gas-well gas. It appears that the producers originally presented no evidence supporting such an allowance, and that producer witnesses did not include such costs in their computations. Further, there was evidence that the computation of such an allowance would be difficult, see 3 Joint Appendix 992, and that, in any event, the producers will incur “no Federal income tax liability at any return up to 15 percent.” 34 F. P. C., at 206. In these circumstances, we think that the Commission did not err in excluding such an allowance.
      Second, it is urged that the Commission failed to include an adequate allowance for exploration costs. We must emphasize that we perceive no obligation upon the Commission, under the Constitution or the Natural Gas Act, to permit recovery of all exploration costs, regardless of their amount and prudence. Although other methods of computing these costs might have been used by the Commission, see id., at 192-193, we have found nothing that would properly permit reversal of the Commission’s judgment.
      Finally, Sun Oil asserts that it was at various points denied due process. It is enough to say that we have examined these contentions, and find them without substance.

       We note that the terms of the stay entered by the Court of Appeals on January 20, 1966, would reduce this rate of interest to 4%%. See 12 Transcript of Record 12, 13-14. The court offered no explanation of this modification of the Commission’s orders. We perceive no basis for the court’s order, particularly since the question was evidently not raised in the producers’ applications to the Commission for rehearing. See § 19 (b), 15 U. S. C. § 717r (b). And see Wisconsin v. FPC, 373 U. S. 294, 307. We hold that the Commission’s order imposing interest of 7% must be restored.

       We understand these interest rates to be in some cases 6% and in others 7%. Brief for the Federal Power Commission 169.

       A locked-in rate is one in which an “increased rate is later superseded by a further increase It is thus “effective only for the limited intervening period, called the ‘locked-in’ period, and retains significance in § 4 (e) proceedings only in respect of its refundability if found unlawful.” Wisconsin v. FPC, supra, at 298, n. 5.

       See Brief for the Federal Power Commission in Nos. 72, 73, 74, October Term, 1962, 48-53.

       Compare FPC v. Tennessee Gas Co., 371 U. S. 145, 152-153.

       We note that Mobil and others have argued vigorously that the Commission’s refund formulae would impose obligations to refund amounts below the “last clean rate.” The latter is a rate established by a final permanent certificate unconditioned by a refund obligation under either § 7 or § 4 (e). The Commission concluded that it need not reach this question since “no such situation has been presented as resulting from our order herein.” 34 F. P. C., at 1074-1075. And see Gulf Oil Corp., 35 F. P. C. 375. Given the Commission’s postponement of the question, we intimate no views on the proper limitations of the Commission’s authority in this regard.

       In its effort to determine costs of production, the Commission sent out questionnaires (Appendices A, B, and C), to 458 producers in the Permian Basin area, 361 of which were named respondents in these proceedings. Appendices B and C inquired as to production costs; Appendix A covered drilling costs. Appendix B was a comprehensive questionnaire designed for major producers, while Appendix C was a simplified form for small producers (those with under 10,000,000 Mcf in nationwide jurisdictional sales in 1960). Small producers, however, could answer either Appendix B or C.
      The Commission received complete responses on Appendix B from 67 producers, of which 25 were small producers. Responses to Appendix C were filed by 105 small producers. (Some of the responses represented composite data for more than one company.) The Commission excluded the Appendix C replies from consideration. 34 F.x P. C. 159, 213-214.
      The Commission’s staff used these responses to develop a composite cost of service study. The staff arranged the Appendix B replies on various charts, arraying the data from high to low in respect to various categories (e. g., total unit costs and allow-anees, cash expense unit costs). Then, weighted cost averages were computed — i. e., the replies on Appendix B were given a weight proportional to the volume Mcf covered by the responses.
      In establishing the rate for new gas-well gas, the Commission elected to proceed by determining costs on a national, rather than an area, basis. 34 F. P. C., at 191. It used the Permian questionnaire responses, however, as “a vital source of information,” ibid., employing them in determining various components of the final national average cost. See id., at 191-200. The Commission also turned to various “well-recognized and authoritative industry data sources [which] were utilized by various witnesses in the proceeding.” Id., at 191. These included such sources as the United States Census Bureau’s Census of Mineral Industries for 1958 (wherever this source was used, the figures were trended to 1960 on the basis of the Permian questionnaire data), the 1961 Chase Manhattan Bank’s Annual Analysis of the Petroleum Industry, and the 1958 Joint Association Survey (a survey made by three industry trade groups based on questionnaires mailed to all member companies).
      Various adjustments were made because of factors such as atypical years or the Permian questionnaire data being disproportionate to the national figures. See 34 F. P. C., at 194^196.
      The Commission’s rate for flowing gas was based primarily on the questionnaire data which had been compiled by the staff into a composite cost of service study. The Commission in this instance based the ceiling price on Permian Basin area costs, although it used nationwide data in determining exploration and development costs. See 34 F. P. C., at 212-218. And, although the term “flowing gas” was defined to include casinghead gas, residue gas derived therefrom, and old gas-well gas, the Commission used only the costs of the old gas-well gas in determining the area rate. Id., at 208-212.

       Nor did the Commission discuss the distribution of the data within the grouping being considered — that is, matters of the concentration, symmetry, and uniformity of the data.
      The Commission asserts in this Court that “while producer costs vary widely from year to year on an individual-company basis, in the long run the costs of most producers tend to approximate the industry average.” In support of this assertion, it cites record testimony and refers to the existence of fairly stable industry averages for drilling costs of successful wells as compared with erratic figures for individual companies. Apart from the fact that not all of the testimony cited stands for the proposition stated by the Commission, but indicates at most only that there is less instability in individual producers’ costs over time rather than that they tend to average out, there was conflicting testimony on the point of representativeness offered by a witness for the Sun Oil Company, who showed that certain averages were not representative of the basic data because the distribution of the data was so widely spread and skewed from the mean. The fact that there were no comprehensive cost data suitable for supplying all the necessary elements of a cost study (see 34 F. P. C., at 191) does not excuse the Commission from finding whether the data it chose to use were typical and representative. In fact, the necessity of making such a finding is accentuated, because of the number of different sources entering into the computation of virtually all of the individual cost components. See 34 F. P. C., at 191-207, 212-218.
      The Commission stated that it would use national rather than area data in arriving at a cost for new gas-well gas, noting: “It may be that in some areas production costs may vary sufficiently from the national average to warrant a different treatment but on the record in this case we agree that cost of new gas-well gas should be determined on the basis of nationwide data.” 34 F. P. C., at 191. Since the Commission was discussing the use of area versus national costs, that statement at most suggests only that the Permian Basin composite costs did not vary sufficiently from the national average costs to warrant not using the latter, rather than that the Commission was comparing the national average with individual producer costs in the Permian Basin.
      Perhaps for a group as large and diversified as that involved in this case, typical and representative averages cannot be computed. Hunt Oil Company presses this point strongly, contending that wide variations in unit costs are an inherent characteristic of gas and that a uniform ceiling rate fixed at the average composite cost level is unlawful per se because of the wide disparity in costs among different categories of gas as well as among different producers. The Commission itself noted this fact of wide variation in individual costs as part of its justification for basing costs on overall producer experience (see 34 F. P. C., at 179); but, as pointed out, it failed to go forward and determine whether the averages used to construct this overall producer experience were typical and representative. If they were not, then perhaps the Commission could have subdivided the group until it arrived at groupings whose members possessed essentially similar characteristics. Cf. United States v. Borden Co., 370 U. S. 460, 469. This would not mean that the Commission would in effect be returning to an individual producer regulatory method; rather, the Commission could stop the subdivision at that point where group averages became typical and representative. But, as this ease now stands, the Commission has not made the necessary findings; and, of course, this Court, lacking the required expertise, cannot undertake to supply those findings for the Commission, nor is it our function to do so. See, e. g., United States v. Abilene & S. R. Co., 265 U. S. 274.

       Kitch, The Permian Basin Area Rate Cases and the Regulatory Determination of Price, 116 U. Pa. L. Rev. 191, 201 (1967) (footnote omitted).

       Counsel for the Commission observe in their brief to this Court that “[n]o more precise determination was possible in the state of the record” than the 0.70 to 1.5$ range for the average adjustment for quality predicted by the Commission in its opinion denying rehearing. See 34 F. P. C., at 1073. Counsel also cite to certain record testimony and exhibits to support the Commission’s determination of this 0.7(4 to 1.50 range.
      It should be noted first that the 0.70 to 1.50 prediction is an average. I have already discussed the misleading nature of averages not found to be typical and representative, and those observations are equally pertinent here. Moreover, we have no idea whether the Commission relied in making its prediction on any of the sources cited by Commission counsel to this Court.
      In computing the 0.70 to 1.50 range in its opinion denying rehearing, the Commission apparently relied on Commissioner O’Connor’s statement in his concurring opinion to the initial decision that the average adjustment would be between 1.00 and 1.70, and then adjusted those figures to allow for certain changes made with respect to quality standards in the decision denying rehearing. But at the time of the Commission’s initial decision, Commissioner O’Connor did not and could not know the costs incurred by the pipelines in bringing gas up to pipeline quality, for the pipelines’ processing costs were not in the record. Commissioner O’Connor based his estimate in large part on contract exhibits, as is evident from his opinion; and he noted that a precise adjustment for quality could not be ascertained from those exhibits. See 34 F. P. C., at 266. His view of the evidence on this point was clearly stated in his opinion concurring in the denial of rehearing, in which he observed that the record “does not permit a meaningful determination of the impact.” 34 F. P. C., at 1081.
      Commission counsel also note the Examiner’s finding that 10 represented a reasonable estimate for bringing new gas-well gas up to pipeline quality and 10 to 1.50 for old gas-well gas. But, as counsel admit, this finding was not made in conjunction with defining pipeline quality standards on which the costs of conforming the quality of the gas would be based. In fact, the Examiner con-eluded that: “This record does not permit the determination of a complete set of quality and value differentials.” 34 F. P. C., at 370.
      The percentage calculations translating the 0.70 to 1.50 range into terms of rate of return, which are relied upon by the Court, were presented by Commission counsel to this Court and do not appear in the Commission’s opinion or in the record.

       See N. M. Stat. Ann., c. 65 (1953); Tex. Stat. Ann., Art. 6004r-6066d (1962). In 1935, Texas, New Mexico, Kansas, Oklahoma, Illinois, and Colorado agreed upon an interstate compact for the conservation of oil and gas. Congress subsequently gave its consent to the compact on August 27, 1935, for a period of two years. Pub. Res. No. 64, 49 Stat. 939. The compact has been extended by the compacting States, with the consent of Congress, for successive periods without interruption, the latest extension being from September 1, 1967, to September 1, 1969. Pub. L. No. 90-185, 81 Stat. 560.

       See also H. R. Doc. No. 342, 84th Cong., 2d Sess., 2 (1956).