
    487 F.2d 1043
    PUBLIC SERVICE COMMISSION FOR the STATE OF NEW YORK, Petitioner, v. FEDERAL POWER COMMISSION, Respondent, Atlantic Richfield Co., et al., Intervenors.
    No. 71-1828.
    United States Court of Appeals, District of Columbia Circuit.
    Aug. 24, 1973.
    Argued Nov. 8, 1973.
    
      See also D.C.Cir., 485 F.2d 1036.
    
      Peter H. Schiff, Gen. Counsel, Public Service Commission for the State of N. Y., Albany, N. Y., with whom Joseph J. Klovekorn, Staff Counsel, Public Service Commission for the State of N. Y., Albany, N. Y., and Michael H. Rosenbloom, Washington, D. C., were on the brief, for petitioner in No. 71-1828.
    Carroll L. Gilliam, Washington, D. C., with whom Tom P. Hamill, Houston, Tex., and Philip R. Ehrenkranz, Washington, D. C., were on the brief for petitioners in No. 71-1836 and intervenor Mobil Oil Corp. in No. 71-1828.
    John R. Rebman, Bartlesville, Okl., with whom Martin E. Erck, Houston, Tex., was on the brief, for petitioner in No. 71-1988 and intervenor Humble Oil and Refining Co. in Nos. 71-1828 and 71-1836 also argued for certain other producer petitioners.
    George B. Mickum, III, Washington, D. C., with whom James L. McHugh, Jr., Washington, D. C., was on the brief for intervenor, Blanco Oil Co., in No. 71-1828.
    Thomas G. Johnson, Houston, Tex., with whom Dan A. Bruce, Houston, Tex., was on the brief for petitioner in No. 71-1989 and intervenor Shell Oil Co. in Nos. 71-1828 and 71-1836, also argued for certain other producer intervenors.
    Michael J. Manning, Atty., F. P. C., with whom Gordon Gooch, Gen. Counsel, Lee E. Forquer, Sol., and George W. McHenry, Jr., First Asst. Sol., F. P. C., were on the brief for respondent. J. Richard Tiano, First Asst. Sol., F. P. C., at the time the record was filed, also entered an appearance for respondent.
    John Frederick Moring, Washington, D. C., with whom John E. Holtzinger, Jr., Washington, D. C., was on the brief for intervenor, Associated Gas Distributors in Nos. 71-1828 and 71-1988.
    Edwin S. Nail, Tulsa, Okl., was on the brief for petitioner in No. 71-2025 and intervenor Amerada Hess Corp., in No. 71-1828.
    W. H. Emerson, Tulsa, Okl., was on the brief for petitioner in No. 71-2020.
    Tom Burton, Houston, Tex., was on the brief for petitioner in No. 71-1930 and intervenor Continental Oil Co. in Nos. 71-1828 and 71-1988.
    Justin R. Wolf, Washington, D. C., and Paul W. Wright, Falls Church, Va., were on the brief for petitioner in No. 71-1991 and intervenor, The California Co.
    Warren M. Sparks, Tulsa, Old., was on the brief, for petitioner in No. 71-1911 and intervenor in Gulf Oil Corp.
    Robert W. Henderson and Paul W. Hicks, Dallas, Tex., were on the brief for petitioners in No. 72-1071.
    Kenneth Heady, Bartlesville, Okl., was on the brief for petitioner in No. 71-2055 and intervenor Phillips Petroleum Co. in Nos. 71-1828 and 71-1836.
    Richard F. Remmers, Oklahoma City, Okl., was on the brief for petitioner in No. 71-1913 and intervenor Sohio Petroleum Co. in No. 71-1828.
    H. W. Varner, Houston, Tex., and Frank P. Saponaro, Jr., Washington, D. C., were on the brief for petitioner in No. 71-1990 and intervenor Superior Oil Co. in No. 71-1828.
    J. Donald Annett, Washington, D.C., Kirk W. Weinert and C. Fielding Early, Jr., Houston, Tex., were on the brief for petitioner in No. 71-2015 and intervenor, Texaco, Inc., in Nos. 71-1828 and 71-1836.
    
      Tilford A. Jones and William A. Mo-gel, Bethesda, Md., were on the brief for intervenor United Distribution Companies in Nos. 71-1988, 71-1989 and 71-1990.
    Charles F. Wheatley, Jr., Washington, D.C., was on the brief for intervenor, American Public Gas Assn, in No. 71-1828.
    John T. McMahon, New Orleans, La., was on the brief for intervenor Ashland Oil Inc. in No. 71-1828. Richard F. Generally, Washington, D.C., also entered an appearance for intervenor Ashland Oil Inc., in No. 71-1828.
    Charles E. McGee, Washington, D.C., was on the brief for intervenor Atlantic Richfield Co. in No. 71-1828.
    Richard F. Generally, Washington, D. C., was on the brief for intervenors, Callery Properties, Inc., F. A. Callery Inc., Forest Oil Corp., General American Oil Co. of Texas in No. 71-1828.
    Sam Riggs, Jr., Liberal Kan., was on the brief for intervenor Cities Service Oil Co. in No. 71-1828.
    William A. Sackmann, Geneva, Switzerland, was on the brief for intervenor Marathon Oil Co. in No. 71-1828.
    Cecil N. Cook, Houston, Tex., was on the brief for intervenor Puentieitas Oil Co. in Nos. 71-1828 and 71-1826.
    Ronald J. Jacobs, Manchester, Conn., was on the brief for intervenor, Skelly Oil Co. in Nos. 71-1828 and 71-1836.
    Stanley M. Morley, and Louis Flax, Washington, D.C., were on the brief for intervenor Sun Oil Co. in No. 71-1828.
    John E. Watson, Saint Petersburg, Fla., was on the brief for intervenor, Tenneco Oil Co. in Nos. 71-1828 and 71-1836.
    Dee H. Richardson, Los Angeles, Cal., was on the brief for intervenor, Union Oil Co. of California in No. 71-1828. Noble John Allen, Jr., entered an appearance for intervenor, Union Oil Co. of California in No. 71-1828.
    Francis H. Caskin, Washington, D.C., entered an appearance for intervenor Sun Oil Co. in Nos. 71-1828 and 71-1988.
    John S. White, Washington, D.C., entered an appearance for intervenor, Marathon Oil Co. in No. 71-1828.
    Bernard A. Foster, III, Washington, D.C., entered an appearance for intervenor, Skelly Oil Co. in Nos. 71-1828 and 71-1836.
    Graydon D. Luthey, Tulsa, Okl., entered an appearance for intervenor Cities Service Oil Co. in Nos. 71-1828 and 71-1836.
    Lewis J. Ottaviani, Bartlesville, Okl., entered an appearance for intervenor, Phillips Petroleum Co. in Nos. 71-1828 and 71-1836.
    William R. Choate, Houston, Tex., entered an appearance for intervenor Pennzoil Producing Co. in No. 71-1991.
    Robert J. Haggerty, Washington, D. C., entered an appearance for intervenor, Getty Oil Co. in No. 71-2015.
    Before BAZELON, Chief Judge, LEVENTHAL, Circuit Judge, and RICHEY, United States District Judge of the District Court for the District of Columbia.
    
      
       Mobil Oil Corp. v. Federal Power Commission, No. 71-1836;
      Gulf Oil Corp. v. Federal Power Commission, No. 71-1911;
      Sohio Petroleum Co. v. Federal Power Commission, No. 71-1913;
      Continental Oil Co. v. Federal Power Commission, No. 71-1930;
      Humble Oil and Refining Co. v. Federal Power Commission, No. 71-1988;
      Shell Oil Co. v. Federal Power Commission, No. 71-1989 ;
      Superior Oil Co. v. Federal Power Commission, No. 71-1990;
      California Co. v. Federal Power Commission, No. 71-1991;
      Texaco, Inc. v. Federal Power Commission, No. 71-2015;
      Amoco Production Co. v. Federal Power Commission, No. 71-2020;
      Amerada Hess Co. v. Federal Power Commission, No. 71-2025;
      Phillips Petroleum Co. v. Federal Power Commission, No. 71-2055;
      Hunt Oil Co. v. Federal Power Commission, No. 72-1071.
    
    
      
       Sitting by designation pursuant to 28 U.S.C. § 292(a) (1970).
    
   PER CURIAM:

These petitions for review challenge the validity of the Federal Power Commission’s order, establishing “just and reasonable rates,” under Sections 4 and 5 of the Natural Gas Act, for sales of natural gas in interstate commerce from the Texas Gulf Coast producing area. The court remands the order to the Commission for further consideration.

The order is composed of two basic parts. The first is the schedule of base area rates. With respect to this, Chief Judge Bazelon files an opinion for the court, beginning at page 1087 infra. District Judge CHARLES R. RICHEY concurs in this opinion. Circuit Judge LEVENTHAL dissents for the reasons stated in Part VI of his opinion, pages 1063 to 1067 infra.

With respect to the second basic part of the order — the system of incentives • — and the remainder of the issues in this ease, Circuit Judge LEVENTHAL files an opinion in which Chief Judge BAZELON and District Judge CHARLES R. RICHEY concur. Thus, Parts I through V, pages 1051 to 1063 infra, and Parts VII and VIII, pages 1068 to 1080 infra, of Circuit Judge LEVEN-THAL’S opinion also constitute the opinion of the court.

So ordered.

LEVENTHAL, Circuit Judge:

In the Order before us for review in this case, establishing “just and reasonable rates” under Sections 4 and 5 of the Natural Gas Act, the Federal Power Commission has provided both base rates and incentive provisions to govern interstate sales of natural gas produced in the Texas Gulf Coast Area. This area consists of 54 Texas counties stretching along the Gulf of Mexico from Louisiana to Mexico. It also includes over 3,560 square miles of underwater continental shelf within state jurisdiction and 20,000 square miles of underwater shelf within Federal domain. The FPC’s approach of fixing gas producer rates by producing area rather than on a company by company basis was approved by the Supreme Court in the Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 344, 20 L.Ed.2d 312 (1968). The order in this area rate proceeding contains unusual features, which are challenged in the several petitions for review filed pursuant to section 19(b) of the Natural Gas Act, 15 U.S.C. § 717r. We shall first outline these features. The reasoning the FPC used in arriving at its results will be examined subsequently, in considering the challenges lodged against different aspects of the Order.

I. PROVISIONS OF THE FPC ORDER

The centerpiece of the FPC Order prescribing rates — a term used, for convenience, to identify the ceilings put on producers — is the provision for the Base Area Rates. This consisted of what is referred to as a three-vintage maximum rate system, with different maximum prices applied to casinghead and gas-well gas, depending on the date on which the producers contracted to deliver the gas. The prices per Mcf, determined on the basis of cost and noncost factors, depend on the three vintage periods of the contract, and then on the time of delivery, as follows:

(1) Gas sold under contracts dated prior to January 1,1961:
(i) 15.0 cents prior to January 1, 1965
(ii) 17.0 cents from January 1, 1965 to September 30,1968
(iii) 19.0 cents from October 1,1968 to September 30,1973
(iv) 20.0 cents on and after October 1, 1973
(2) Gas sold under contracts dated on or after January 1, 1961, and prior to October 1,1968:
(i) 18.0 cents prior to January 1, 1965
(ii) 18.5 cents from January 1, 1965 to September 30,1968
(iii) 19.0 cents from October 1, 1968 to September 30,1973
(iv) 20.0 cents on and after October 1,1973
(3)Gas sold under contracts dated on or after October 1, 1968:
(i) 24 cents prior to October 1, 1973
(ii) 25 cents on and after October 1, 1973

In sum, three “division dates” for contracts are set: 1961, 1968 and post 1968. Gas under contracts in each of these periods is given a different maximum price, depending on the delivery date. Thus the above table means that if gas was contracted for prior to 1961 and delivered in 1965, the maximum price would be 17^ per Mcf. These base area rates were combined with a moratorium provision on filing increases above the applicable area rates, until January 1, 1976.

The commission also found that “The present critical shortage of all forms of energy in the United States and the anticipated rapid growth of demand for natural gas, in particular, makes it imperative to provide incentives to find gas and dedicate that gas to the interstate market.” In view of the critical shortage, the FPC established two incentives :

(1) a credit of one cent per Mcf toward discharge of [a producer’s] refund obligations for each additional Mcf of gas hereafter dedicated to interstate commerce prior to January 1, 1976, by an individual producer;
(2) increases in the area rates of gas under contracts dated prior to October 1, 1968, from the time prior to January 1, 1976, that the independent producers as a group have dedicated to interstate commerce more than a specific amount of additional gas from the area.

In regard to the refund provision, the FPC Order provides that reserves dedicated for refund reduction, under paragraph (1), may not be counted toward new dedications needed to make the contingent escalation operative under paragraph (2).

The contingent escalation in price applies only to increase the base area rates for gas sold under contracts prior to October 1, 1968, and the increases are made on a group basis; after a gross amount of new dedications are made, all producers with pre-October 1, 1968 contracts receive an increase in price. The total new dedications needed and the corresponding increase are as follows:

Total New Dedications Base Area Rate Increase
4.000.000.000 cubic feet .5 cent per Mcf
6.000.000.000 cubic feet additional .5 cent per Mcf
10,000,000,000 cubic feet additional 1.0 cent per Mcf

II. SUPPLY SHORTAGE

Since many features of the FPC Order in this case, particularly the incentive provisions, concern the supply shortage of natural gas, some assessment of the record evidence on this matter should serve as a backdrop to the contentions of thé parties.

The Commission found that the demand for natural gas was expected to increase faster than the current rate of production. Total demand for natural gas is expected to reach 28.1 trillion cubic feet by 1975, requiring an annual level of domestic production of 27.2 trillion.

The Examiner, the Commission explained, had underestimated the possible shortage of supply in arriving at his price proposals. Thus, his opinion indicated that finding-to-production (F/P) ratios would be above unity in the foreseeable future; yet the Commission found that the F/P ratio has been below unity since 1967, and dropping.

A second indicator of supply, reserves-to-production, also indicated a shortage. The (R/P) ratio for interstate pipelines in the Texas Gulf Coast area had declined from 14.9 in 1964 to 11.5 in 1969. Less than 18% of the 1969 interstate production came from new sources of supply, reported in the six-year period commencing in 1964. The Commission found that if demands from the Texas Gulf Coast area during the next five years were to be satisfied, it was essential that jurisdictional sales increase from their 1965-1969 volume of 8 trillion cubic feet to 12.5 trillion cubic feet cumulatively for the period of 1971-1975. The Commission believed that to achieve this desired level, its goal for dedications of new reserves from the Texas Gulf Coast to the interstate market should be 20 trillion cubic feet during the 1971-1975 period.

The supply shortage of interstate gas reflects, inter alia, the fact that intrastate sales of natural gas are unregulated by the FPC. The demands from the intrastate market, particularly in the consuming states of the Texas Gulf Coast, increased 44% from 1963 to 1969, while interstate production was constant. Taking into account the fact that intrastate prices were often higher than those in interstate sales, due to the unregulated nature of the former market, the FPC stated it had to consider prices which would make interstate demands more competitive.

Not only was there a deteriorating reserves-to-production ratio in the area, but the absolute number of proven reserves available for interstate sale was low — about 1 trillion, as compared with the 20 trillion cubic feet of new reserves the Commission wants dedicated to the interstate market in the 1971-75 period. The supply shortage was the reason given by the Commission in setting its base prices, and in devising its incentive provisions in the proposed rate order.

III. STANDARDS OF JUDICIAL REVIEW

We turn to the Permian Basin Area Rate Case, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968), to lay the foundation for the standards of judicial review to be used in assessing the merits of the challenges before us. Generally, we must be mindful of our duty to sustain Commission rate levels which are within a “zone of reasonableness.” “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’.” These standards, as applied to a particular rate order are a carte blanche for Commission discretion. As Justice Harlan, writing for the majority in Permian, made clear, these broad principles could further be concretized as follows :

[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 forseeable.

Above all, the Court pointed out that “[j]udicial 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 the consequences of its orders for the character and future development of the industry.”

Most of the challenges to the Commission Order in this case involve issues relating to the inclusion of non-cost factors in pricing which are justified on the basis of the shortage of supply. While the task of justifying price methods which depart from pure costs poses difficult problems, due to the difficulty in understanding demand and supply elasticities of natural gas, this state of the art cannot be used as an excuse to offer no reasons for adopting these measures, or to supply reasons which have no basis in evidence and underlying reasoning. Whatever the problems of limitations on available knowledge, the Commission is under a duty to apply what knowledge is available, with a bona fide effort to identify both the scope and limitations of available knowledge, and the Commission’s pertinent reasoning.

This opinion is organized as follows: In Part IV, we summarize the issues presented. In Part V, we examine producers’ challenges to the general methodology, principally attacking the use of cost based methodology, and specific challenges of particular cost items, as well as other challenges to the rate structure. In Part VII we examine the validity of the Commission’s use of non-cost based incentives, contingent escalation and refund “work-off”, in the rate structure.

IV. THE SCOPE OF ISSUES AND THE POSITIONS OF THE PARTIES

The Order has been challenged from a multiplicity of points of view. We here set forth a brief overview of the disparte contentions. Subsequently we shall examine the challenges seriatim.

The rate structure has been attacked by the parties on a number of grounds: (1) the adoption of a cost-based pricing method is an inadequate response to the gas shortage, and prices on gas were set too low; (2) certain specific elements in the cost-derived prices were unreasonable; (3) the adoption of the moratorium in light of the shortage was unreasonable; and (4) the division date for new gas prices, October 1, 1968, was unreasonable. This last contention is made by the New York Public Service Commission (hereafter “New York”); the others are presented by producer petitioners.

As will appear from the opinion of Chief Judge Bazelon, the majority of the court construes the applications for rehearing and the petitions for review filed by both the producers and Public Service Commission of the State of New York as challenging the base rate structure on an additional ground: that, assuming a cost premise for rates, the upward adjustments in the FPC’s determination of costs and in its choice of rate from within the variable range of costs were not shown to be rationally related to the supply problem, either in concept or in amount.

Petitioner Blanco Oil Company raises a distinct issue which we shall consider in a separate opinion.

Challenges to the incentive provisions of the Order — the contingent escalation of rates on flowing gas, and the provision allowing credits on existing refund obligations — have been made, on different grounds, by New York and by producers.

The contingent escalations are claimed by New York to discriminate against new entrants who will not receive the gain realized by old producers on gas already under contract. Old producers without refund liability, such as Mobil Oil, contend that they are subject to unreasonable discrimination because their dedication of new reserves will earn escalations for the entire industry, while other producers, with refunds, will both get an individual benefit from their dedications, by reducing their refund obligation, and share in the industry-wide dedications due to the efforts of other producers. It is further contended by New York that the bonus arrangement discriminates among pipelines and their customers. They allege that since the bonus for finding new gas is chargeable to gas consumers in proportion to the existing contracts of the pipelines upon which they rely, whether or not their pipeline actually secures any of the new dedications the bonus produces, the provision is unreasonable in failing to correlate higher consumer prices with additional new gas reserves secured by distributors.

As to the refund provision, certain producers contend that the reduction provision unfairly discriminates against those who have already made refunds, since they would have obtained reductions, if they had awaited the outcome of this proceeding. This argument is given another edge by the contention that the FPC Order, in effect, prefers the largest refund accumulators. New York argues that new entrants are also disadvantaged by the reduction measure, since they have no existing liabilities which can be reduced by new dedications. Further, New York contends that the provision discriminates against those owed past refunds, since the FPC Order provides that only 50% of the new dedications used to discharge refund liability is required to go to those to whom the refunds were due.

We shall proceed to examine the various challenges.

Y. CHALLENGES TO THE RATE STRUCTURE

A. Challenges to General Methodology The Use of Cost Methodology

The most broad-based attack on the rate order challenges the use of cost methodology as an appropriate means of pricing gas under supply shortage conditions. It is argued that a price would be justified for new gas only if it would reasonably be expected to meet the supply objectives formulated by the Commission, and that the “new gas” price in this order does not accomplish this end. Producer petitioners adduce evidence that prices in the intrastate market, which competes with the demand of the interstate market, were as high as 30 cents on new contracts negotiated in the July 1, 1970 to 1971 period. It is argued that the desired level of dedications to the interstate market of 20 trillion cubic feet needed to supply both the interstate and intrastate markets, is not a credible target in light of the fact that total reserve additions in the area for the entire ten-year period of 1961-1970 were only 28.7 trillion cubic feet.

We are not prepared to follow these concerns to the point of overturning the methodology adopted by the Commission. First, the Commission did consider the effect that intrastate demand and prices would have on the supply available to the interstate market. The last data available to the Commission showed intrastate prices as high as 24.38 cents per Mcf for a contract dated in 1970. Whereas it is certainly true, as petitioners argue, that the Commission recognized that “the trend of intrastate prices is upward,” the general rate order does provide for a price increase to 25 cents for new gas in 1973 Moreover, the contingent escalation provision means the effective yield on new gas contracts could be much higher, and may lead producers to make interstate contracts even though the price on such contracts will be below that available in the intrastate market

Second, we are not sure what the producers want to put in the place of the cost-based pricing used here by the Commission. Two other techniques of pricing, a discounted cash flow method and a price based on a theory of supply elasticity, formulated in an econometric model, were found by the Examiner to have serious predictive and reliability problems which had led to their rejection in other area proceedings. There is a burden on producers to show that alternative price techniques will lead to a “just and reasonable price.”

Third, an analysis of the Commission’s approach, contained in the Appendix to this opinion, shows the 24 cent price is not a purely cost-based price. The supply shortage was reflected in the calculation of the variable ranges for each cost item, particularly the rate of return, and played a central role in the choice of the particular price within the range. Those who may be interested in this point can turn to the Appendix for amplification.

In its modification of the Examiner’s methodology, the Commission did depart from the strict cost-based price system used in Permian, but this approach was suggested in the Supreme Court’s opinion in Permian, and specifically approved by the Fifth Circuit in its initial review of the Southern Louisiana Area Rate Proceeding. The Commission used the strict cost-based price as an “anchor,” following our reasoning in the context of individual ratemaking proceedings.

The producers’ major point was that they wanted the FPC to discard costs entirely, offering instead an “econometric” approach that would focus on the prices needed to bring out increments of supply. The FPC responded that not enough was known of the methodology of such an economic approach to make it a reliable means of regulation. We cannot say this was error. In the last analysis, as we understand the matter, the underlying principle of economics requires that the determination of price needed to induce desired supply levels requires both some premise of profit necessary to spark management investment and effort, and also some determination or assumption of cost — whether of average cost, or the cost of the (bulk-line) increment of supply, etc.

Another option does remain— that of setting the price of natural gas at the market price, or of allowing the market price to govern the “just and reasonable price” of natural gas. A variant of this contention is the submission by the producers that in time of supply shortage, regulation for an area that serves not only an interstate market but also an (unregulated) intrastate market must set the regulated prices as high as the unregulated in order to prevent diversion to the intrastate market. However, so long as the legislature has assigned the agency the function of regulation of rates, it cannot legitimately execute that function in a fashion which, in fact, is tantamount to total deregulation or non-regulation.

Congress did not provide for agency action and court review as a charade.

The Commission has moved closer to this approach with Order 455, adopting an “Optional Procedure for Certificating New Producer Sales of Natural Gas.” This procedure provides that under § 7 of the Natural Gas Act, sellers can negotiate prices on contracts in excess of rates provided in the area rate system for:

A contract covering the sale of natural gas in interstate commerce [which] has been executed for gas produced from a well or wells commenced after April 6, 1972; or a contract covering the sale of natural gas in interstate commerce [which] has been executed for gas not previously sold in interstate commerce. .

Although we do not reach the merits of the legitimacy of the Optional Order 455, giving sway to market forces, we do note that its combination with the cost-based pricing system of the Rate Proceeding is significant in coping with objections of producers.

B. Calculation of “Flowing Gas” Costs

The second major producer challenge concerns whether the price calculated for flowing gas is a “just and reasonable” maximum rate.

Claims of alleged, failure to resolve disputed cost items

The producers object that the FPC failed to resolve disputed cost items. This contention is emmeshed in a stale data problem, caused here by the protracted nature of the proceedings. The producers object that, in updating the Examiner’s cost data, the FPC failed to make updated findings on each cost element for the rate base on flowing gas. “Staleness of the record, however, is not itself a reason for reversal.” Moreover, the FPC concededly made an adjustment for the stale data problem; it updated, as a whole, the costs used by the Examiner, first by increasing his base price, and then by escalating this base price over time. The producers argue that each cost item must be updated separately. Whereas recalculation of individual cost items may be desirable, we see no showing that it has led to an unjust and unreasonable ceiling, to an “end result” contrary to the statute or Constitution. The producers made no proffer that updating calculations made one by one would have led to a result significantly different from that reached by the FPC.

Claims of lack of findings that rates cover revenue requirements

Another contention of the producers, challenging the lack of a finding that prescribed rates will cover revenue requirements, fails for similar reasons. The Examiner found that a 13.4 to 13.7 cents per Mcf rate would cover costs. The FPC found that costs were higher and raised rates accordingly. This cost calculation of course included the profit element of “return” to the regulated producers. The Commission made a further allowance for the generation of capital for future exploratory efforts, both in setting the flowing gas base rate, and in the refund-forgiveness and contingent escalation provisions which supplement the rate structure. This goes to the substance of revenue requirements, and we cannot strain for formalities.

Return on flowing gas

The producers contend, in the alternative, that the FPC did not actually calculate a rate of return for flowing gas, and the rate of return should be 15%, the same rate allowed for new gas. The Examiner included a 10.5% rate of return in the costs used to calculate the 17.4 to 17.8 cents per Mcf that became the basis of the price on flowing gas for the 1961-68 period. In increasing the base price and allowing for escalations, the Commission, among other justifications, cited increased costs and the need for “a proper rate of return.” 45 FPC at 707. It is, therefore, difficult to say whether the increased price was based on an increased rate of return or merely increased costs, or what proportion of each. Despite the problem, we can say that there is substantial evidence that the effective rate of return arrived at is at least 10.5%

Rate of return is calculated on the base of production investment. That base includes successful well costs, lease acquisitions and other production facilities, but the record makes it reasonably clear that the FPC did not consider these items, for flowing gas, to have increased significantly.

The result of this analysis of the record (see note 41) establishes that the FPC’s rate of return for flowing gas was at least the 10.5% allowance used by the Examiner We turn to the alternative argument of the producers, that 10.5% is insufficient, and should be 15%, the same as rate of return allowed on new gas. We pass by both the prospect that the FPC’s prices will yield a rate of return for flowing gas exceeding 10.5%, and the circumstance that the Examiner used the same rate of return for both flowing and new gas. We see no immutable principle that the rate of return on both flowing and new gas must be equal. The time-honored standard for rate of return, formulated in Bluefield Water Works & Improvement Co. v. Public Service Commission, 262 U.S. 679, 692, 43 S.Ct. 675, 679, 67 L.Ed. 1176 (1923), and approved again in FPC v. Hope Natural Gas Co., 320 U.S. at 603, 64 S.Ct. 281, provides that “return” should be “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.” This “comparable earnings” standard, which has vitality for rate regulation, was used by the Examiner in calculating a 10.5% rate of return for both flowing and new gas. The Commission increased this figure to 15% for new gas because of its desire to provide an extra incentive for new gas exploration. The same was obviously not required for flowing gas, which did not reflect an investment made “at the same time.”

C. Producer Challenges to Specific Cost Items

Various producers challenge specific aspects of the FPC’s cost calculations. We discuss the four most significant points they raise.

Successful well costs

The producers’ attack on calculation of the items of successful well costs is not insubstantial, but does not warrant an upset of this feature of the rate base. They object to the variable cost range of 2.70-4.10 cents per Mcf used by the FPC for new gas on the basis of what it considers underestimated drilling cost per foot figures. The FPC estimated that drilling costs could range from $22.22 to $24.66 per foot, depending on the method of trending data for increased costs. The producers argue that the $22.22 figure was derived from the 1967 Census figure of $24.39, which the FPC adjusted downward for unreported drilling costs of small producers. The FPC made this adjustment on the basis of data reported to Census that these costs were 40% lower than those of the large producers, even though Census did not adjust its own figures because it considered the data based on an inadequate sample and of such poof quality as to be unreliable.

The issue does not warrant reversal. The Bureau of Census and the FPC have different functions. Census has the obligation of reporting facts of our economy which may be put to a host of unknown and unknowable uses, and properly errs on the side of conservatism in reporting as fact only that which is knowable. The FPC, engaged in rate fixing, has room for judgment in its use of data beset by .infirmities. The FPC proceeded on the premise that for every item of cost, there is a range of reliability in underlying data. The FPC established a variable cost range— to give a better idea of various possibilities it believed could justly be supported by the data. The objecting producers did not deny that small producers have lower drilling costs than large producers, even though the 40% extent of the differential was not reliably supported. Even the $24.39 figure proposed by producers is within the variable range used by the FPC. The FPC chose the high side of the variable range in calculating its new gas price. We see no substantial prejudice. As for the producers’ claim that the high side of the range should be 30 dollars per foot, this is a conclusory statement supported only by a speculative estimate of how high drilling costs are likely to go in the future.

Exploration and development costs

The producers challenge exploration and development (E & D) costs, as calculated by the FPC for the flowing gas rate. They attack the method the FPC used in sorting out E & D costs assignable to gas exploration from those incurred on oil. This is an old and difficult problem. The FPC adopted the Examiner’s method, allocating costs in proportion to Btu’s produced during a test year, with the Btu’s of liquids increased by a multiplier of 3.4 to indicate comparative values.

The producers make two alternative contentions: (1) that the multiplier is arbitrary, or (2) a method of allocation utilizing direct assignments of exploration and development costs, as used in other proceedings, should have been adopted here.

As the FPC brief points out, the use of the “modified Btu method” in Permian and Southern Louisiana I, and the direct assignment method in Southern Louisiana II, led the FPC to conclude in those cases that the new methods changed the cost result by only one cent, and that this possible one cent error is more than accounted for “by the range of estimates implicit in the flowing-gas cost methodology.” Compare Other Southwest Area Rate Case, supra, slip op. at 26 suggesting, but not requiring, Commission reconsideration, where the FPC did not respond to the factual allegation that the direct assignment method would have made a 6.17^5 difference in the flowing-gas rate. Rate regulation is unavoidably approximate in nature. We cannot dictate a choice of formulas. The use of the “Btu adjustment method” was not arbitrary in light of its use in the past, the fact that its results approached those achieved with the newer direct assignments method, and in the context of the broad adjustments used by the FPC in its price determinations.

Royalties

The producers argue that in arriving at a royalty cost of 14% of the price set for gas, as applied to both the new and flowing gas rate, the FPC assumed, as it had held in Opinion No. 562 (42 FPC 164), that the royalty interest, just like the producers’ working interest, is subject to FPC jurisdiction, and that Commission’s prescribed “area rate” ceilings are equally controlling on the royalty owner. This jurisdictional assumption, as producers correctly point out, was upset in Mobil Oil Corporation v. FPC, 149 U.S.App.D.C. 310, 463 F.2d 256 (1971), cert. denied, 406 U.S. 976, 92 S.Ct. 2413, 32 L.Ed. 2d 676 (1972). The producers extrapolate from our Mobil decision by contending that we held that royalty owners could maintain collateral suits to recover payments based on alleged “current market values,” and therefore royalty payments will exceed the FPC’s assumptions of cost levels. But we observed in Mobil, without reaching the issue, that the fact that “market rate” royalty contracts would be left to the courts, did not portend a necessarily unavoidable conflict with area rates. Indeed, we noted:

Without purporting to rule on the matter in any way, we can certainly visualize the possibility that a court confronted with a contention of entitlement to a market price basis higher than the producer’s ceiling would consider it to run counter to the intention of the parties, unless there is something to rebut the fair presumption that they contemplated interstate movement and market prices compatible therewith [footnote omitted].

Petitioners’ claims are premature. The FPC could not meaningfully reflect an unknown and unknowable increment in royalty costs.

“50 BTU gap”

The final costing contention involves what producers have labelled as the “50 BTU gap.” In Texaco Inc., 33 FPC 1228 (1964), followed in the Permian proceeding, the Commission established the general principle that a price adjustment is appropriate for varying Btu content of both new and flowing gas: an upward adjustment, for premium quality, from a level of 1050 Btu per cubic feet, and a downward adjustment, for shortfall in quality, from a level of 1000 Btu per cubic foot. Producers argue that these levels are not supported by the record, and that Btu adjustments both upward and downward should be made from the base of 1000 Btu per cubic foot.

The paradigm for the calculation of levels was developed in Southern Louisiana 7. In that proceeding the FPC adopted a base range rather than an exact base, as lessening the need for continual ceiling adjustments and agency monitoring; used the 1000 Btu base as a minimum notwithstanding average deliveries were at 1037 Btu, in order to avoid disturbing established industry practice; and balanced the savings thus accruing to producers by setting an upper level above 1037, put at 1050 as a matter of judgment. This justification for use of a range is reasonable. As to the location of the range, the producers show even less prejudice in the present case, in view of the Examiner’s finding that the weighted average of deliveries was at 1047 Btu, even assuming, as the producers contend, that the trend is downward.

As for the use of 1000 Btu in Hugo-ton-Anadarko Rate Proceeding, 44 FPC 761 (September 8, 1970), that was a settlement, and did not adopt a principle that must thenceforth be maintained as a standard.

D. Challenges to the Division Date and Moratorium Division Date

New York Public Service Commission contends that the October 1, 1968, division date between flowing and new gas is unreasonable, and argues for a later date, giving consumers a lower price (the 19 cents flowing gas rate) on more contract years of gas. The contention is that the allowance for incentive factors to achieve increased supply included in the new gas price of 24 cents can serve no purpose to elicit discovery for gas already discovered and under contract.

We have difficulty with the FPC’s rejection of this contention on the basis of “administrative convenience,” that this same division date has consistently been adopted in other area rate proceedings. While it might permit a certain standardization in forms for keeping track of information, certainly any mechanical difficulty involved in keeping in mind different dates of the various rate vintages of gas for the several areas cannot seriously be urged as a legitimate reason for putting a 25% rate increase (between 19 and 24 cents) in effect for deliveries during a two and a half year period. While Permian referred to administrative convenience, that went merely to the eight day period between the start of the Permian Basin Area Rate Proceeding and the date fixed for the commencement of new gas rates.

We do, however, think that this case may be brought within the reasoning of Permian sustaining the non-correspondence between the division date and the prospective application of the rate order. The Court approved the Commission’s action there establishing a price for new gas in 1965 applicable to gas committed to interstate commerce since January 1, 1961. Although stating (390 U.S. at 798-799) that “[i]t is difficult to see how the higher rate could reasonably have been expected to encourage, retrospectively, exploration and production that had already occurred,” the Court noted the Commission’s argument that its Statement of Policy issued on September 28, 1960 establishing a 16-cent guideline price for new gas sales in Permian, plus the commencement of the Permian area rate proceeding itself on December 23, 1960, had created expectations of higher rates among producers which fairness required it to satisfy in fixing the starting date for its new gas-well gas rate. The Court concluded, 390 U.S. at 799, 88 S.Ct. 1344, that these factors provided a “permissible basis” for the Commission’s choice.

In 1968, the same year that Permian issued, the FPC stated in Southern Louisiana I that the

use of the same division date as was used in the Permian Basin will ensure equality of treatment in this respect among producers operating in different pricing areas — a producer should not be penalized by having a later division date exclude its gas from the new gas category solely because he chanced to be in one area rather than another, unless strong and sufficient reasons are shown for the different treatment.

While an argument based on the same treatment for producers in different areas has a certain surface appeal, we think it cannot be pushed too far. The very concept of area rate proceedings produces unequal treatment to some extent: even though nationwide cost figures are used, the Commission has not adopted nationwide prices. Given the time lag in area proceedings, the 1968 division date could recede farther and farther behind the date of an FPC order issued to encourage “new” gas.

However, given the 1968 ruling in Permian and the expectations generated by the FPC’s 1968 statement in Southern Louisiana I, (even if not wholly sound), and taking into account the need for some cost increase above 1961 prices if a different division date is taken for new gas, we think an upholding of the FPC action as an application of Permian’s fairness concept marks the course most appropriate for this court. This is not wholly logical, but the Supreme Court knew that in Permian. The Supreme Court noted that it was acting with reluctance; we likewise note our reluctance. If the point is extended too far, it can become a mockery; but if that point has been neared in the case before us, it has not been passed.

However, it is incumbent on the FPC to reexamine its policies, with a view to breaking this expectation-fulfillment cycle if it serves no legitimate end, if the requirement of reasoned decision-making is to be observed, and the function assigned to FPC of produce rate regulation is to be fulfilled in accordance with law.

Moratorium

The question remains whether FPC’s imposition of a moratorium on price increase filings until January 1, 1976, was a permissible exercise of its authority. In Permian the Supreme Court accompanied approval of a similar moratorium with the caution, “we intimate no views on the propriety of moratoria created in circumstances of changing costs,” 390 U.S. at 781, 88 S.Ct. at 1367, a circumstance now concededly the forecast for the Texas Gulf Coast Area.

Individual producers are not prevented by the moratorium from seeking relief from the maximum rates, as appears from the provisions for special exemptions and the availability of motions for modification or termination. Producers may be correct in arguing that the automatic and contingent escalation provisions on flowing gas do not provide enough flexibility in rates, and will not adequately cover anticipated cost increases. Yet the rate order’s determination of the “just and reasonable price” will only come into conflict with the moratorium provision when, and if, increased costs are not adequately covered by the rates and no relief is granted by the Commission. We need not anticipate a change in circumstances before it occurs.

VI. CHALLENGES TO BASE RATES

In this part of the opinion I explain why I disagree with the decision of the majority, reflected in the opinion filed by Chief Judge Bazelon. The reader will have to read Judge Bazelon’s opinion before considering this Section VI of my opinion. If I understand it correctly, the majority has decided to remand the base area rate to the Commission on the ground that the FPC’s increase in the base rate chargeable by producers in the Texas Gulf Coast area is not adequately justified, since the FPC’s selection of a reference point in the zone of cost data was influenced by supply considerations without any determination of the amount of increased supply projected as aseribable to the resulting increase in base rate.

Much of what is said in Judge Bazelon’s opinion is interesting, and should be of interest to the legislators who may come to consider whether the Natural Gas Act of 1938, as previously amended, should be further amended or perhaps repealed. The history of natural gas regulation is particularly valuable for those who have not lived through it, and I confess to a middle-aged and sentimental yearning for the simpler days of yore, and for the problems that were being discussed when I was engaged for a few years in teaching natural gas regulation at New Haven during the late 1950’s.

1. My problem is to discern what Judge Bazelon’s opinion has to say for the case before us. It might be relevant if there were a petition to review filed by New York on the ground that the base rate was too low and was inadequately justified. But as is plain from the record, and recognized in one of Judge Bazelon’s footnotes, New York does not present any objection to the base rates, either for new gas or flowing gas. While New York’s application for rehearing did present to the Commission its objection that the Commission had provided “an over-generous price for new gas” (point 9), and had provided only a few conclusory statements that were inadequate to discharge its responsibility “to discuss in detail the supply to be elicited at the rates established” (point 10) it has not preserved any objection to the base rate in its petition for review. New York stated in its brief (p. 11):

The Federal Power Commission in this case has established maximum prospective rate ceilings for new and flowing gas produced in the Texas Gulf Coast area at 24 cents per Mcf and 19 cents per Mcf respectively. These rates are each approximately 5.-3 cents in excess of the rates proposed for new and old gas-well gas by its Presiding Examiner in his Initial Decision. However, while New York does not agree with much of the methodology utilized by the Commission in reaching these results, or with a number of the specific findings or absence of findings made by the Commission in support thereof, New York has, with the limited exceptions noted below, chosen not to challenge this portion of the Commission’s determination. We have reached this conclusion in the light of the current gas supply situation, which has caused the New York Public Service Commission to impose moritoria on many types of new sales by New York distributors and has resulted in serious curtailment by the interstate pipelines of existing firm obligations of their New York customers, and our belief that levels approximating those here fixed by the Commission could be justified by a proper decision upon a more up to date record.

A federal court exists to decide only cases or controversies. When a case enters the federal court system by a prayer to a circuit court of appeals to reverse an order of a federal agency, it is the pleading containing this prayer that presents the controversy between the petitioner (or appellant) and the agency. That pleading of New York contains no objection to the base rate. New York does not ask this court to engage in an academic exercise, and I think settled rules of judicial functioning and administration indicate we should neither do so ourselves, nor require the Commission to do so.

2. Judge Bazelon says that an objection to the base rate has been preserved by the producers. Section 19(b) of the Natural Gas Act provides: “No objection to the order of the Commission shall be considered by the court unless such objection shall have been urged before the Commission in the application for rehearing unless there is reasonable ground for failure to do so.” This provision is faithfully applied by the courts, see, e. g., Permian Basin Area Rate Cases, supra, 390 U.S. at 825, n. 116, 88 S. Ct. 1344 (1968).

The objection found meritorious in Judge Bazelon’s opinion is that the FPC erred in selecting a cost predicate for the base rate, albeit within the range of costs as elicited from the testimony (with suitable up-dating), because the “supply” reason of the FPC for its choice within that range were not adequately supported in its opinion. I now set forth the presentations made by the producers, which show, I think, as to the objection raised by Judge Bazelon, that “such objection” is not the one that was presented by the producers to the FPC.

There are numerous producer-intervenors before us: While their applications for rehearing differ somewhat one from another, the objections made by the producers adequately appear from the following sample, italics having been added for emphasis.

Humble’s application for rehearing states:

Although this Application for Rehearing sets out in detail matters which the Commission should, in our view, reconsider, we wish to express at the outset our basic agreement with the approach utilized by the Commission in Opinion 595. For the first time in area rate regulation, the Commission has recognized that the cost calculations on the record are not mathematically precise, but contain arbitrary judgments as to allocation procedures and a wide margin of error in both data and methods utilized (pp. 10-11). The Commission has also clearly recognized in Opinion 595 that area ceiling prices should serve a supply-eliciting function and that the gap between gas supply and demand has reached crisis proportions (pp. 11-14). The Commission properly found a wide range of current costs as constituting the “zone of reasonableness” for area ceiling prices, and selected a price which it believed to be supply-eliciting (p. 35). These are principles which the undersigned producers have long advocated, and we fully support the Commission’s adoption of them. The concept of escalating prices for gas delivered under pre-1961, and 1961-1968, contracts for different time periods is sound and is supported by the increase in costs which has occurred over this time period as well as by the increasing need for internally generated capital for additional gas exploration. The cutoff dates selected by the Commission are also valid and appropriate, assuming different vintaging is required. The specifications of error which follow deal with what we believe to be improper applications of these principles. (R. 42,025)
The Commission correctly recognizes that there is no reliable manner in which it, or anyone else, can forecast the amount of new gas reserves that would be committed to the interstate market as a result of any specific change in rates (p. Ik). In this respect the Commission gave recognition to recent evidence concerning the levels of prices in the intrastate markets in the Texas Gulf Coast Area. As a result of the Commission’s investigation in Docket No. R-389, it was determined that in the first half of 1970 intrastate prices ranged up to 24.38 cents per Mef. The Commission recognized that the trend of intrastate prices in the area is upward (p. 37).
The Commission’s action in establishing new gas rates at 24 cents per Mcf is clearly erroneous in light of (1) the understatement of the range of new gas cost estimates from which such level was selected; (2) the minimal increase (after adjustment for inflation) which such rate represents over rates which have failed to elicit sufficient supplies; and (3) the inadequacy of such rate to enable the interstate market to obtain gas supplies in this area. (R. 42,028-29) Continental Oil Co.’s application for

rehearing concludes (JA 793-4):

In view of the critical gas shortage, the need for drastic surgery on previous ineffectual and
inadequate efforts is urgent. The Commission needs to re-evaluate its entire area price approach and reject completely the hypocritical pretence of costing. A new regulatory method more in line with the economic realities of the industry needs to be devised. Fundamental to such new method must be recognition of a single price system whereby all gas is priced on a value basis.
The price level set by the commission must be sufficient to give incentive for finding new gas. While such incentive may be a matter of judgment, followed by trial and error, it must be at least 30-35‡ on Mcf in order to begin to complete [sic] with intrastate levels. Evidence since the close of the record may indicate that such levels are even higher.
WHEREFORE, for the foregoing reasons, the Commission should grant rehearing of Opinion No. 595 and upon rehearing modify its area pricing to provide a single price for all gas for all periods of time, regardless of date of contract. Such price should be higher than the “new gas” vintage level established in Opinion No. 595, for the reasons set forth in the Application for Rehearing of Indicated Respondents, and at least in the 30-35‡ range to provide any hope of incentive. (R. 42,142-43)

The joint brief filed by the indicated producer petitioners states (pp. 32-33):

Despite the fact that the Commission recognized that the gas supply shortage was rapidly growing more serious and that this shortage was engendered at least in part by inadequate regulated field prices, it nonetheless “elected to go through the methodology used in earlier cases” (R. 41,884) and utilized the Permian methodology as a “point of departure” (R. 41,885). Having found that such costs are inaccurate within the range noted, the Commission should have discarded them as a point of departure. Failure to do so had the effect of depressing the ceiling rate levels below what the supply evidence indicated, amounting to an abuse of the Commission’s discretion.
Should the Court find that the use of such costs is discretionary,' then we would further show that the Commission understated the range of costs, and that the limits of the range are actually much higher than noted in the opinion, as disclosed by evidence in the record. Finally, because of the rapidly worsening supply shortage the Commission should have prescribed ceiling rates reflecting the upper end of the range, rather than at the middle or lower end. Under the circumstances here, this was an abuse of the Commission’s discretion requiring a remand.

The fact that producers filed an objection or objections to the base rates on the ground of inadequacy of FPC methodology does not mean that it is the same objection as that on which the court is ruling, so that the court can fairly say that “such objection” was presented to the FPC. Judge Bazelon says that the FPC did not adequately set forth a forecast of the new reserves that would be committed. But as the foregoing applications show, the producers’ view is that the FPC correctly recognized that there is no reliable way of forecasting the reserves that can be committed as a result of the price change; and their objection, starting with that premise, is that since basically there must be an exercise of judgment, combined with trial and error, the interstate price must at least be equal to the intrastate price; that the cost range would permit a higher base price; that an incentive price should be nearer the high point of the true cost range; and that a contrary approach is in excess of the FPC’s permissible discretion. All these objections are far different from the objection found justified in Judge Bazelon’s opinion.

3. If the objection constructed by Judge Bazelon were properly before us, I would not agree with what Judge Bazelon has done. It seems to me that what the FPC has done, as a matter of methodology, is not beyond the range of discretion that is properly the Commission’s and is not unreasonable; that there are large areas of government regulation of industry that call for judgment and necessarily admit of considerable imprecision within the “zone of reasonableness”; and that Judge Bazelon’s opinion would constrain the Commission to seek a refinement in methodology that it has fairly indicated is not ascertainable and available.

For clarity, I emphasize that I am not here speaking to a situation in which an agency increases a ceiling price for supply reasons without any reference point in costs. This the FPC did not do — and, as stated elsewhere in this opinion, there is firm support for its conclusion that the econometric principles propounded by producers had an appearance of scientific support that was belied by the sponginess of the assumptions and techniques on close examination.

If I may put the matter in my own words, raising prices to obtain supplies without any foundation in cost analysis comes close to bargaining with the sellers solely in terms of asking at what price they would be willing to sell. While that may be appropriate for an unregulated market, it has no serious place in a program of government regulation.

Similarly, the Act does not permit a charade of regulation that rests in truth on a premise of nonregulation (see supra p. 1057), e. g., by rubber-stamping the prices reached in an unregulated market.

As to the issue before us, on the other hand, there are pertinent cost estimates. Now if the evidence shows a reasonably firm cost prediction in a range of, say, 24 cents to 26 cents per Mcf, I see no objection in principle to a determination by a Government agency along these lines: The range is between 24 cents and 26 cents per Mcf. No exact answer is possible, and the determination requires the exercise of judgment. We cannot know exactly how much more supply will be available at 26 cents than at 24 cents. Any investigation along those lines would reduce itself in the last analysis to an inquiry of sellers, and that is impracticable in view of their claim that a still higher price is what is really needed for supply — a claim that undercuts any meaningful answer as to willingness to sell at the lower price provided by even the highest point in the cost range. Under the circumstances, it is a responsible exercise of judgment to stay within the anchor of a cost range, but within that range to veer to the high side to avoid taking unnecessary risks of curtailing supply, at least at a time of shortage when the interest of consumers as well as the general public lies in avoiding unnecessary risk to supply-

It seems to me to lie within the discretion of the agency, and the domain of responsible regulation, to make a determination that reflects such an approach without undertaking a kind of meaningless and diversionary make-work effort at quantification.

4. Even the remand required by my opinion for the unanimous court opens the way to an agency’s reformulation of base rates. The FPC might well say that it had set a base rate on the assumption of conditions the court has found improper, and that if it is not to have the premise of such conditions, it finds another base rate appropriate. But that would have been a matter of administrative latitude in the exercise of the agency’s on-going function following a judicial remand. What causes me to differ from Judge Bazelon’s opinion is my concern lest it operate to require a remand proceeding that is unrealistically and unnecessarily refined, in pursuit of a regulatory will of the wisp.

I fear that Judge Bazelon is turning from Socrates, and his concern with the limits of knowledge, to Plato, and his quest for the ideal. Judges, however, must deal with the workaday world. In judicial review of administrative regulation courts have a dual role, of supervision of administrative agencies, and of responsible partnership in the public interest. They cannot fairly demand the perfect at the expense of the achievable.

VII. CHALLENGES TO INCENTIVE PROVISIONS

The FPC established non-eost based incentives to reduce the critical supply shortage. First, a contingent escalation in flowing gas prices for producers as a group, when certain specified new dedications of natural gas were made to the interstate market. Second, a credit of one cent per Mcf, toward discharge of refund obligations, for each additional Mcf of new dedications — subject to a provision to avoid double' counting of dedications. A number of challenges to both of these provisions are reviewed below.

A. Contingent Escalations

The provisions for contingent escalation are attacked as (1) adopted on inadequate hearing procedures; (2) lacking findings that these incentives will materially improve the supply situation; and (3) having a discriminatory and anti-competitive effect.

Hearing procedures

Area rate proceedings conducted under Sections 4 and 5 require a hearing and decision “supported by substantial evidence,” under § 19(b) of the Natural Gas Act. Petitioner Mobil Oil Corporation contends that both incentive provisions were not subject to development through a hearing, and thus are not based on record evidence.

The Examiner’s voluminous findings were based on hearings which began after the institution of the proceeding on November 27, 1963 and extended until his initial decision issued September 16, 1968. Some 25,000 pages of Joint Record were developed in hearings held jointly with the Hugoton-Anadarko Area Rate Proceeding, with another 5000 pages added in separate hearings pertaining only to the Texas Gulf Coast Area. The working assumption throughout was that prices were to be cost-based, and that adjustments for an increased level of supply would be accomplished through the uniform pricing system. Thus, there was no. presentation on incentive provisions, or such issues as (1) the size of such escalations needed to produce a given supply, (2) the relationship between such provisions and the incentives contained within the uniform price system, or (3) the actual returns different producers with different quantities of “flowing gas” might realize from these contingent provisions.

The incentive provisions were adopted ab initio by the FPC in its Opinion No. 595, (issued May 6, 1971) and were justified principally on the basis of record evidence indicating the shortage of supply. The FPC stated:

The present critical shortage of all forms of energy in the United States and the anticipated rapid growth of demand for natural gas in particular makes it imperative to provide incentives to find gas and dedicate that gas to the interstate market .... Accordingly, we believe it necessary and desirable in the public interest that incentives be offered independent producers of natural gas above and beyond the price we have fixed in this proceeding.

In Opinion No. 595-A, and “Order Modifying and Clarifying Prior Order [595] and Denying Rehearing,” the Commission’s only response to this challenge was that “[t]he rate and rate design issues raised in this hearing” were similar to those raised on rehearing in another area rate proceeding, Southern Louisiana II, and that it was “unnecessary to repeat what we said in that opinion.” In briefs and oral argument, Commission counsel lean heavily on the Southern Louisiana II opinion to support the incentive provisions adopted here.

Need for substantial support in the record

Even assuming the FPC’s shift from adjudicatory to rulemaking procedures survives judicial scrutiny here and in other proceedings as a permissible interpretation of the Natural Gas Act and Administrative Procedure Act, nevertheless the Natural Gas Act, with the provisions in § 19 that Commission decisions be reviewed under a “substantial evidence” standard, contemplates that the agency decision be made “on the record.”

In United States v. Florida East Coast Railway Co., Justice Rehnquist, speaking for the majority, decided that adjudicatory procedures afforded by the Administrative Procedure Act, 5 U.S.C. § 556, would not automatically be available, unless the basic statute — there section 1(14) (a) of the Interstate Commerce Act — expressly specified that the rule in question was to be made “on the record after opportunity for an agency hearing.” Even if the rationale of Florida East Coast is applicable to producer rates issued under the Natural Gas Act, a question we need not reach, that case was concerned only with determining when the Commission must employ adjudicatory procedures. A separate question is presented as to when a decision must be made “on the record,” whatever the procedures used to compile it. We take the statutory requirement of “substantial evidence” in § 19 of the Natural Gas Act to reflect a congressional intent to limit agency determinations to record evidence. In Phillips Petroleum Co. v. FPC, where the Tenth Circuit held that the Commission could conduct area rate hearings under rule-making procedures, the court indicated its agreement with this view, stating:

The final contention of the petitioners is that there can be a valid judicial review only if there is a record. However, we do not agree that this requires that there be a record resulting from a formal evidentiary hearing.
. The submissions of the petitioners would be placed in public files and made available for public inspection. Thus the petitioners are aware of the material which will be considered together with the application of Commission expertise to the information submitted.
Finally, the reviewing court is at liberty to remand the cause to the agency for further delineation, information or expression of views.

Reference to Southern Louisiana II proceeding

In the instant case, FPC counsel assert that critical features of the rate order — contingent escalations and refund discharges — can be adopted in this proceeding, on the basis of the record and decision in Southern Louisiana II.

The use of Southern Louisiana II as a constructive record underlying the Texas Gulf Coast Area order runs into problems of sequence and timing. Southern Louisiana II was issued on July 16, 1971, more than one month after the FPC’s opinion in the instant proceeding, issued on May 6, 1971. Indeed, the Southern Louisiana II opinion relied, on issues other than the incentive provisions, on the Texas Gulf Coast Area opinion. While the Texas Gulf Coast opinion 595-A, denying rehearing, did issue subsequent to Southern Louisiana II, so late a cross-reference to justify a central requirement of the rate order raises problems. Doubtless, both orders reflected a view that the Commission had been in the process of forming, yet its order presented to us must have substantial basis in the record presented to us. Without pressing this matter of sequence further, we observe that the technical footing for the avoidance of a record or reasons by reference to Southern Louisiana II is somewhat slippery.

Secondly, a problem surely exists with using the record from Southern Louisiana II. The FPC was not setting national rates, but was holding separate hearings in rate proceedings for different areas. We see no basis for charging the parties in one proceeding with notice of the contents of the record in another proceeding unless a fair procedure is adopted to alert the parties of a proposed incorporation by reference, and to give the parties in the second proceeding a clear opportunity to respond, by challenging the evidence transferred, or pointing out distinctions that limit the utility or propriety of transfer. See M. Dakin, Ratemaking as Rulemaking— The New Approach at the FPC; Ad Hoc Rulemaking in the Ratemaking Process, 1973 Duke L.J. 41, 76 n. 173.

Third, we focus on the fact that the opinion in Southern Louisiana II was based on a settlement proposal. The fact that Southern Louisiana II was a settlement was relied upon by the Commission, in significant measure, to sustain its order in that proceeding. 46 FPC at 103. Yet in a settlement, trade-offs on a wide range of pricing issues may have induced various participants in that proceeding to forego a legal challenge to the incentive provisions. “The parties may be disposed to avoid the expense and distractions of litigation if ... a settlement [does] not constitute a binding admission or ruling on principle.” City of Chicago v. FPC, 128 U.S.App.D.C. 107, 119, 385 F.2d 629, 641 (1967).

Finally, the cross-reference to Southern Louisiana II was almost casual, and indeed the FPC did not explicitly say that this reference related to the challenge on the incentive provisions. That position has been refined in briefs and oral argument of counsel, but these are not an adequate substitute for consideration and articulation by the agency.

We conclude, therefore, that the Commission cannot properly rely on the record of Southern Louisiana II, due to the lack of opportunity given to petitioners to respond to the incorporation of that record. We now move to a discussion of the evidence in the proceeding before us justifying the incentive provisions.

Relationship between incentives and required increase in supply

The FPC’s reference to the energy shortage as the reason for the incentive provisions properly calls on us to consider the record evidence that is available in this proceeding on the supply shortage, and other evidence in regard to adjustment of the price of flowing gas for eliciting increased supply. The existence of some record and some reasons, gives the FPC order the presumptive validity outlined in Permian, unless .this is undercut by petitioners.

Certain petitioners contend, broadly, that the FPC has presented no rational connection between the amount of incentives provided and the expected increase in supply of natural gas, that, in effect, the supply shortage per se cannot be used to justify any and all possible measures the Commission may take to reduce that shortage in any degree, to give a blank cheek to producers with no assurance that consumers will thereby benefit.

The Commission and producers defending the incentive provisions argue that (1) the degree of arbitrariness in the incentive provisions, in terms of eliciting supply, is no greater or different than that which attaches to flowing gas prices, which have been calculated, in part, to produce increased supply; (2) the incentives will generate capital funds, and an extremely high percentage of outlays for discovery of new gas comes from this source of capital; and (3) the incentives are only given on an “if . . . come” basis, so the price to the consumer will only be increased if the desired amount of gas is forthcoming.

These contentions of the defenders of the rate order are substantial refinements from the findings and conclusions of the Commission below. They represent an improvement in analysis, over the FPC’s bare position that the supply shortage per se justifies the incentive provisions, as approaching a “hard look” at the reasonableness of the incentives. However, these were not the justifications advanced for the measures adopted by the Commission, either in its initial opinion where these were interjected into the proceeding, or in response to the petition for rehearing, where it had the benefit of petitioners’ specific challenge. We remand to the Commission for its statement of its reasons, in view of the void that now exists. We áre strengthened in this course by difficulties we see with these justifications, which the FPC should be given an opportunity to take into account, in reexamining the relationship between non-cost incentives and the expected increase in supply.

The Fifth Circuit in Placid Oil Co., supra note 2, 483 F.2d at p. 893 stated “What the nation needs is gas, that is, gas that is burnable”. We agree. We cannot accept, however, a result under the Natural Gas Act in which the mere need for supply automatically justifies any and all proposals, or demands, by the person able to provide the needed supply. We believe it is important that alternative means be considered from the viewpoint of protecting the consumer, taking supply considerations into account, but not exclusively, and that the means finally chosen be evaluated against possible alternatives.

Flowing Gas Price Analogy

The Commission and the producers analogize the incentives to the supply adjustments made in the price of flowing gas. The majority of the court has concluded that these upward adjustments are themselves inadequately justified by the Commission as a response to the supply problem. But even if the upward adjustments had been approved, the analogy that the Commission and the producers seek to draw between them and the incentives is incomplete in one critical respect. The upward adjustments are at least within a range of cost-based levels. The methodology used by the Commission in arriving at the new gas price also has a cost-based orientation. When the Commission employs pure non-cost incentives there is no cost anchor that even arguably serves as a benchmark for the reasonableness of the rates. Thus, the use of pure non-cost incentives poses an issue different from those involved in adjustments or choices of base rates. It is hard enough to determine the amount of benefits to producers, and burdens to consumers, over and above familiar cost of service (including fair return), that may reasonably be projected to elicit a needed increment in supply. These difficulties are inherent in incentive programs. It is hard to discern what reason could justify an agency acting in such a way as to provide incentives without a glimmer of their extent. As to incentive provisions on newly discovered gas, the relationship of benefits to burdens have at least a measure of reasonable ascertainment in terms of the volumes of new discoveries, which can be measured against the escalation provided in the rates for those discoveries. The same calculation is not meaningful for flowing gas, because of the inherent differences between producers in the amount of flowing gas under contract. •This not only raises a problem of discrimination discussed subsequently, but also makes it difficult to assess the rate burdens to consumers from an increase in these prices.

If, as must be assumed, prices have been set for new gas that fully reflect the costs of exploration, including failures and the cost of attracting money (rate of return) to the exploration enterprises, then it is difficult to discern the argument for an extra allowance on existing gas flows, in the interest of providing an incentive to explore for new gas. The Commission’s brief insists that the FPC must have latitude to develop incentive provisions to meet exigencies (p. 42). We agree with this generality, and agree that it is supported by our decision in Public Service Commission v. FPC (Natural Gas Pipeline Co.), 151 U.S.App.D.C. 307, 467 F. 2d 361 (1972). But it is subject to a necessary premise that there be some justification, that the provision put forward as an incentive to exploration have some rational relation to the objective of exploration. That decision involved the FPC’s handling of advance payments made by pipelines to producers “for exploration and lease acquisition costs.” In upholding this as a means to ensure that necessary capital for development will be forthcoming, the court pointed out that this advance was not unreasonable on its face “since ultimately the consumers must be ready to shoulder the costs of such operations, if they are necessary to supply them with power.” But in the ease at bar the consumers who are being asked to shoulder the costs are not the same as the class of consumers who will be receiving the supplies. That is the nub of the problem.

The intervenor-producers’ brief argues (p. 8): “A primary basis for the Commission’s provision for contingent escalation of flowing gas prices was the recognized need to increase the availability of capital funds to gas producers in order to finance the expanded search for new gas reserves.” What the Commission in fact said (R. 41,924) was that as a result of its orders, sources of adequate financing will be available for exploration and development in the Texas Gulf Coast, with a large portion of the funds internally generated by the increased cash flow from gas flowing under pre-1968 contracts. The FPC did not say that this flowing gas increase was necessary to obtain exploration funds, and indeed it had already increased the prices for new gas in order to assure exploration capital. It is elementary in the petroleum industry that capital is provided for exploration in an area long before there are any funds flowing from that area — demonstrated, e. g. by the funds invested in Alaska, and in purchase of Gulf Coast off-shore leases offered by the Interior Department. It is obvious that future expenditures in any particular producer area depend on evaluations of future profits, not past or recent receipts from activities begun in the past, at least where, as here, the future operations will be governed by price conditions far more liberal than prevailed at the time current operations were planned and developed. The fact that petroleum company retained earnings were equal to 85% of investment outlays during 1954-1963 does not govern the present inquiry. It reflects both earnings retained out of gas and oil, and investment used for both gas and oil. Investment in an area was not related to earnings from that area, but rather to a company-wide assessment of funds available and investment opportunities. It reflects the easier availability, and less expense, of use of retained funds, and the approval given that course by stockholders, but does not negate the availability of debt or equity financing. In short, the producers’ contention simply does not focus on the core questions involved in any program of enlarging receipts on flowing gas because of the prospect— there is no requirement — that these particular receipts be used for exploration for new gas. Before any such approach could be indulged, there would have to be a more reasoned statement from the Commission of necessity and propriety. Furthermore, the relevant risk to investors in the equity of integrated petroleum companies, would seem to be defined not by the risk of exploration activity but by the risk from the entire operations of the corporation.

While at the margin the cost of raising capital makes retained earnings from current operations a preferred source for funds for new exploration, this does not establish that absent such earnings, all investment will be foregone. What determines the decision to make an investment is the estímate of earnings from the new investment, and if that is projected as a return that justifies the risk, capital will be available. Similarly, if the projected returns do not justify the risk, capital will not be invested even though retained earnings are available from current operations. Firms must assess the opportunity cost of investing their retained earnings in new exploration, as opposed to other uses in active, or even passive, investment opportunities.

The plan does provide that increases in price only come after new dedications are made. The critical question, however, is whether companies will use the money generated from the increased price of flowing gas in new exploration activity. They will get their moneys faster from a rate hike on flowing gas than new gas, but what will they do with the money?

In view of the absence of Commission analysis, we observe that our comments do not constitute an implacable prohibition on the use of flowing gas to raise required revenues. We have, however, identified substantial problems that the FPC will have to consider on remand.

Discriminatory and anti-competitive effects

Petitioners assert that the contingent escalation incentive is unduly discriminatory in its effects upon the industry, producing widely discrepant benefits for different producers, giving benefits to individual producers based not on their exploration, or even dedication to the interstate market, but on their previous volume of interstate sales (assuming an industry-wide dedication), and operating to the particular disadvantage of new entrants into the industry. Proponents of this feature of the rate order generally contend that discrimination between producers is inherent in the concept of area-ratemaking and that new entrants are not prejudiced by the flowing gas approach.

The issue of discrimination received a most cursory treatment by the Commission in its Order Denying Application for Rehearing. The Commission stated:

Texaco and Mobil object to the industry-wide incentives of price escalation for total industry dedications of new gas reserves. They would provide incentives, instead, for individual producers to make dedications. Mobil also suggests that simply giving higher prices without requiring new dedications would be a better incentive. While there is much to be said for individual incentives, and in a proper case they may be ordered, upon this record we are not convinced they are preferable in this area. This Commission is concerned with the incentives necessary for the producers to dedicate 10 trillion cubic feet in new gas reserves to interstate commerce. Accordingly, we found it in the public interest to provide industry incentives, rather than individual incentives. .

This is not an explanation but a conclusion, stating that the Commission would follow its announced policy. No semblance of analysis is indicated, in terms of the consequences upon industry structure from the provisions, nor is any reasoned consideration given to the alternative of an increase in the new gas price.

Section 5(a) of the Act contemplates that area rates should not be “unjust, unreasonable, unduly discriminatory, or preferential. . . . ” It is to avoid such results, that the Commission is charged with arriving at “just and reasonable rates.’’ In view of this expressed purpose of the Act, there is need for the Commission to be sensitive and responsive to the discriminatory effects of area rate orders.

In Permian, Justice Harlan stated: Judicial review of the Commission’s orders will therefore function aecurately 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, (emphasis added).

The absence of an “assessment” was called into particular question by the Fifth Circuit in Austral, supra, 428 F.2d at 441. Although the court was not willing to reverse or remand the order on that ground, the court indicated that “The Commission has considered few of these matters in this case either prayerfully or otherwise, and this deficiency is of great concern to a reviewing court.” 428 F.2d at 442. While Austral was concerned with a different, and perhaps converse, omission by the Commission— the failure to consider the supply shortage — the principal reason advanced by the Fifth Circuit for not reversing and remanding was that the new proceedings, which ultimately led to the Commission’s decision in Southern Louisiana II, were already underway for the major purpose of reexamining its prior order in light of changed supply conditions. The Fifth Circuit also believed that Permian gave the Commission a grace period during which a less full and careful examination by the Commission would be demanded by the courts, due to the experimental nature of area rate proceedings. In our view, allowance for experiment is, indeed, appropriate when applied to such matters as the level of price, and the difficulties of relating an incentive in the new gas price to a needed quantity of supply. The pragmatic need for room and time to experiment cannot substitute for reasoned analysis when the rate structure raises a serious problem of discrimination, a result which the statute expressly guards against, and which the Commission has long had experience in enforcing. Moreover, it is now five years after Permian and three years after Austral. As Justice Harlan cautioned in Permian:

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 increases.

Discrimination against producers with less or no flowing gas

We turn to the serious problem raised concerning discrimination against new entrants into the natural gas industry, a problem area made more complicated by the issue of anti-competitive effects. The discrimination against new entrants is plain enough. New entrants will, by definition, have no outstanding flowing gas. On new dedications to the interstate market, new producers will obtain only the authorized price for new gas; old producers, will obtain additional revenues through the authorization for increase in gas flowing under contracts and dedications of the past. This imbalance may impinge on competition —e. g., in the bidding for new gas leases, old producers will be able to outbid new entrants due to the expected differential in total returns. Such a result would be inconsistent with the Commission’s policy toward pipeline companies, whose entry or re-entry into the gas production arena is sought by FPC in the public interest. Presumably this policy evolved, in part, as a response to the “market imperfections” noted in the past by the Supreme Court. This traditional concern with competition in the industry makes it appropriate that the Commission assume the authority and the responsibility to consider this type of challenge and indicate its views.

The question of discrimination and anti-competitive effects is not limited solely to a comparison between old producers and new entrants. Since old producers may differ significantly among themselves, in terms of flowing gas under contract, the incentive provision may also affect the industry structure as to producers already in the market. The shape and extent of this problem should be identified on the record and considered by the Commission on remand.

FPC counsel argue that area ratemaking is inherently discriminatory. (We are not clear whether FPC would take the position that it is inherently anti-competitive.) If some discriminatory effects are inevitable, they should be kept to the irreducible minimum. While price increases for flowing gas inherently advantage old producers and not new entrants, to the extent that they are intended to reflect the recovery of real costs, the effect on competition is collateral and diluted. Even when some supply adjustments have been made to this price, as here, cost still functions as an anchor and anti-competitive effects are minimized.

When we speak of the vice of discrimination, we do not have in mind the theoretical argument that even uniform prices provide different rates of return, depending on the cost structures and efficiency of the various producers. Generally, at least, uniform prices give all producers an equal opportunity to reduce their costs, or improve their efficiency, to maximize their returns. When a rate differential is fixed by federal regulation, without basis in costs, there is a handicap to opportunity that cannot be removed by effort of the disadvantaged producer to enhance efficiency and competitiveness. This is not merely a problem where “one producer’s piece of cake is iced and another’s is not.” Placid Oil Co., supra, 483 F.2d at 905. At stake is the consumer’s interest in effective competitive conditions in the industry.

Discrimination against customers of flowing-gas producers

New York argues that there is invidious discrimination in that the bonus to producers from new dedications will be chargeable to their customers and consumers as a function of its past flowing gas take, regardless of whether the pipeline or other customers secure any or all of the new gas.

A regulatory system does not distribute costs and benefits in exactly equal proportions to consumers. The vintage rate system, for example, makes classifications of gas to which different costs attach, for different years of discovery and delivery. Vintage pricing of gas is based on average costs, and although costs may increase over time during a period, all consumers will pay the same price for the period. Yet Permian clearly sustains vintage pricing, if only for the administrative convenience of the Federal Power Commission. Similarly, administrative convenience has long recognized the propriety of zones of delivery for pipelines, with the same prices for all customers within a zone, although transmission costs are actually higher to those located farthest from gathering points.

There is a basic difference between reasonable classes or zones, with uniformity within the class or zone, established for administrative convenience, and a situation in which there is no inherent relationship between the consumers assigned the burdens and those deriving the benefits of a government pricing provision.

Such discriminatory effects would be minimized if the costs of new discovery were compensated by a higher price for new gas. Again, we stress that we are not precluding the use of increased flowing gas costs; we are simply indicating to the Commission that certain disadvantages seem to inhere in such a system, and although they may have to be borne ultimately, they must be evaluated and weighed against other possible regulatory approaches.

B. Refund “Work-off”

Many of our comments above on the matter of contingent escalations, are also appropriate in regard to the refund “work-off” provision of the rate order, which provides that a credit of one cent per Mcf toward discharge of refund obligations is provided for each additional Mcf of new dedications to the interstate market, with the proviso that reserves dedicated for refund reduction are not to be counted toward new dedications needed to trigger the contingent escalation on flowing gas. The provision for the refund provision is subject to the same absence of explanation as the other incentive provisions of the rate order, and our observations on that point need not be repeated here.

This provision is also challenged as discriminatory and anti-competitive.

The work-off provision gives an advantage to sellers charging high prices in the past, particularly as a result of section 4(e) filings which resulted in rates higher than those specified in the permanent certificate, for it lets them work off their refund obligation by dedications, giving them a preference over producers who had a lower potential refund liability or who had made cash refunds discharging their liability. This is a happenstance and capricious preference which is not accompanied by any justification of reasonableness.

Mobil argues that the preference is particularly unjustified because, due to its relationship with contingent escalations, those producers who are working off refunds by new dedications can rely on other producers who make dedications (without receiving refund credits), to trigger contingent escalations for the industry, and thus derive a regulatory benefit without a corresponding contribution. To some extent discrimination is inherent in the contingent escalation because it works on an industry basis, rather than on an individual producer basis. But it rubs salt in the wounds for producer A, who makes a full dedication, to know that not only is the same benefit accorded to producer B who makes no dedication whatever, but that an even greater benefit is accorded to producer C, who makes the same dedication as A, merely because his past conduct calls upon him to make equitable restitution.

Again, the refund incentive discriminates against new entrants who, of course, have no refund liability.

In addition to the above inter-producer effects, the Order discriminates, says New York, against the consumers who were owed the past refunds. FPC has provided that 50% of the new gas used to discharge refunds must be offered to those to whom the refunds were due, but New York contends that all such gas should go to those owed the refunds. As in the case of contingent escalation, the imperfect match will result in a redistribution of the costs of new gas, as compared with a system in which refund liability was separately discharged and incentives limited to the price of new gas.

There may be a sound explanation for the system adopted, but we have not been offered one by the Commission. The justifications, raised for the first time before this court, that the refund work-off will reduce the supply shortage, and that discriminatory effects are inherent in area rate regulation, are subject to our comments made in the context of contingent escalations. The Commission further asserts that the work-off must be sustained because of its special administrative discretion and power over the payment of refunds. We cannot agree.

Courts have traditionally held that there is broad discretion in the Commission to order the payment of refunds. As Justice Harlan pointed out in Permian, a rate found to be unjust and unreasonable is declared by § 4(a) to be unlawful, and if the rate has been the subject of a rate schedule modification, the Commission is empowered by § 4(e) to order a refund. This is pursuant to the Commission’s duty under the Natural Gas Act to protect the interests of consumers. It is in accord with this statutory duty that the power of the Commission to order refunds has been upheld in a variety of circumstances. As we stated in Niagara, supra, 126 U. S.App.D.C. at 382, 379 F.2d at 159, “the breadth of agency discretion is, if anything, at its zenith when the action assailed relates ... to the fashioning of policies, remedies and sanctions, including enforcement and voluntary compliance programs in order to arrive at maximum effectuation of Congressional objectives.”

In this case, however, the Commission seeks to relieve producers from refund obligations, and to the extent that it does so it lets stand, without redress, past violations, and it promotes unjust discrimination and anti-competitive effects. Its first impetus lies, if anything, in thwarting rather than effectuating the policies behind the Act, as expressed in § 4 as to refund obligations, and in § 5 as to the prohibition of undue preferences. This is not to say that wherever a potential refund liability exists, that it is mandatory upon the Commission to order payment. At the minimum, however, we would require the Commission “to look at the backdrop of the practical consequences” of its refund order, F. P. C. v. Tennessee Gas Transmission Co., 371 U.S. 145, 155, 83 S.Ct. 211, 9 L.Ed.2d 199 (1962), and to assess in a diligent manner whether effects prohibited by § 5(a) exist, and if so, whether they are avoidable. As in the case of the contingent escalation, we do not think that the supply shortage or need for capital rationale have been responsive to the asserted problems of discrimination .and anti-competitive effects, and this must be cured on remand.

In Placid Oil Co., supra, the Fifth Circuit stated that the “FPC realized that its refund credit program would not benefit all producers equally” and approved that result and added that the FPC had discretion to provide an incentive through the “work-off” provision. 483 F.2d at 907, accord, Other Southwest Area Rate Case, supra, slip op. at 28-290. We can agree with both of those propositions, but feel that the substantial potential for anti-competitive effects and discrimination require a response to the contentions of the petitioners.

C. Effect of Order J+55

Our remand for further consideration will permit the FPC to take into account the implications of Order 455, implementing an “Optional Procedure for Certificating New Producers Sales of Natural Gas,” which allows producers to opt out of area rate prices and regulation for “gas produced from a well or wells commenced after April 6, 1972” or for “gas not previously sold in interstate commerce,” and instead negotiate prices with buyers.

The interphase of these two systems should be examined by the Commission. We indicate no view as to whether, or to what extent, the availability of the “deregulated” system is valid or will obviate the potential defects of the Commission’s area-rate system in its present form.

VIII. CONCLUSION AND DISPOSITION

We find ourselves, at the end of the opinion, poised for the announcement of our order, yet uneasy that we have failed to identify and come to grips with a critical aspect of the case. We refer to the regulatory climate and context. Much of the learning on natural gas regulation, learning in both the Commission’s orders and past court opinions, has focused on the public interest, and the interest of the consuming public, in avoiding exorbitant rates. Now there is focus on the public interest in obtaining needed gas supply, and properly so. So long, however, as this is in a context of regulation, and not decontrol, it must be accompanied by reasoned consideration, and coming to grips with issues. It is not in the public interest to lend the forms and trappings of the administrative process (including the element of judicial review) to what is in substance an abdication to the producers. “It is the genius of our system that instead of government ownership we retain the spark of private profit and the drive of private enterprise, maintained under government surveillance at critical pressure points of regulatory policy.”

If public control is to avoid mere abdication, it must continue to require reasoned analysis, to assure fidelity to the functions assigned to the regulatory agency by the Congress. Judicial review is part of the means of assuring that fidelity.

To some extent, the function of meaningful judicial review is undercut by the tandem regulatory programs that have emanated from the Commission. Thus Order No. 455, for optional deregulation, seems to undercut the premise of area rate regulation, in substantial measure. We do not take the Commission to task for devising new remedies when the situation is in flux, and emergent. We only confess to an uneasiness, that we may be sweeping the snows of yesteryear, while the pertinent climate has changed. We have no option but to perform our assigned task. For that, we think it right to turn again, to Permian, and to Justice Harlan’s statement, 390 U.S. at 792, 88 S.Ct. at 1373, that—

Judicial review of the Commission’s orders will . . . 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 the consequences of its orders for the character and future development of the industry.

Although the Commission has attempted by its order in this proceeding to increase the supply of natural gas, it has not been responsive to petitioners' challenges to the incentive provisions of its rate order, and our judicial review function is thereby hampered.

In Placid Oil Co. v. F. P. C., the Fifth Circuit in approving a rate order, similar to the one we review here, that was the result of a settlement proposal, stated that the “ ‘experiment’ rationale of Permian and SoLa I [444 F.2d 125] still warrant a kid glove review of FPC rate cases” though the “kid glove [was not] to hold a rubber stamp”. 483 F.2d at 890. But see Other Southwest Area Rate Case, supra, suggesting, but not requiring, Commission reconsideration of its Order. In Placid the contingent escalations on flowing gas provision of the Commission Order were sustained on the basis of extra earnings needed to increase supply, at 898-900. Similar justifications were used to sustain the refund “work-off” provision. We fail, however, to discern a difference between a “kid glove” and a “rubber stamp” if all that is needed as a reason for Commission action is to point to a supply shortage. Even an “experiment” needs a rational design. The Natural Gas Act charges the Commission with protecting the interests of the consumer. We can agree that it is in the consumer’s interest to increase the supply of natural gas —but the question with the incentive provisions is whether the supply will indeed be increased, and if so whether this must be at the expense of anti-competitive effects and discrimination on the industry. Unless the Commission is to withdraw from regulating responsibility, it must be responsive to these concerns, which were presented to it by petitioners.

APPENDIX

This Appendix describes how in arriving at the price for “new” and “flowing” gas, the FPC took into account supply considerations.

“New Gas” Methodology

As a guide to our discussion of “new gas” methodology, we reproduce the Commission’s composite cost figures.

_Cost of new gas-well gas_

Examiner’s Cost elements conclusion Variable cost range

DD&A:

Successful well cost......... 2.77 2.70 to 4.10 cents.

Lease acquisitions .......... 1.13 1.13 to 2.03 cents.

Other production facilities ... .34 0.33 to 0.73 cent.

E&D:

Dry holes .................. 1.44 1.64 to 1.97 cents.

Other exploration costs...... 1.70 1.29 to 2.18 cents.

Adjustment for exploration i excess of production ...... 1.16

Production operating expense .. 2.70 3.11 cents.

Return on production investment 4.90 6.24 to 10.29 cents.

Return on working capital..... .35 0.47 to 0.72 cent.

Net liquid credit.............. (3.50) (4.10) to (4.41) cents.

Regulatory expense ........... .14 0.14 cent.

Royalty...................... 2.30 Derivative.

Production tax ............... .90 Derivative.c

Total................ 16.42

NOTE. — To these costs must be added 0.4 cent for gathering and delivery.

An examination of the derivation of both the costs and ranges of cost reveal that the Commission was responsive to increasing costs and the need to increase supply.

The first important point about the Commission’s approach is the use of the variable cost range. The proposed initial decision of the Examiner was issued on September 16, 1968, and the Commission decision on May 6, 1971. With the passage of time more data developed as to the possible trends in increased costs. In part, therefore, the variable cost range represents an update of data, or a possible range of costs which these data would support.

The calculation of “Successful Well Costs” may serve as an example. As the FPC explained, the computational method used since Permian is to divide drilling costs per foot by gas reserves added. As to the numerator, drilling cost per foot, the Examiner used the data of U.S. Census Bureau’s Census of Mineral Industries, taking the $16.48 figure from the 1963 Census, the last available census. The FPC departed from this finding in two ways. First, it used the 1967 Census Figure (published subsequent to the Examiner’s decision) of $22.22. Second, it used the Census data only as a starting point, and then “trended” the Census figure on the basis of the Joint Association Survey (JAS) data, from industry sources, which predicted gradually increasing costs by a certain factor, as of 1969, arriving at a figure of $24.66. This FPC approach thus (a) provided an update of information, through use of the 1967 Census Figure, and also (b) a change in methodology through use of JAS data to “trend” the last available Census Figure.

Similar departures occurred as to the calculation of the “productivity” denominator of the fraction, i. e., gas-well reserves added per foot (Mcf). Thus the Examiner, on the basis of the AGA-API Reserves Committee report, took an average of productivity for the years 1947-1965, arriving at the figure of 596. The Commission on the other hand, for the purposes of calculating a range, took three different averages: 1964-68 (723); 1964-69 (654) and 1947-69 (602). Again the FPC used updated information. And again the FPC made a change in methodology by its use of shorter averaging periods, which the Examiner had rejected as less reliable.

This combination of changes resulted in an FPC calculation of upper ceiling a variable cost range of “Successful Well Costs” with an upper ceiling of 4.10 cents per Mcf as compared with the Examiner’s finding of 2.77. A similar pattern obtains for other costs. In calculating ranges by alternative methods, the Commission never indicated a preference, but used the range to show that equally valid assumptions, put together with new data, could lead to a wide range of permissible costs for the different estimated items.

The calculation of the permissible rate of return on production investment also throws some light on the Commission’s methodology in arriving at a cost-based price. The Examiner used the approach of Permian. The computation consisted of taking production investment as consisting of successful well costs, lease acquisitions and other production facilities, calculated to be 4.24 cents per Mcf. This investment was to be recouped over an average period of ten years, beginning an average period of one year after investment. This was the “theoretical average rate base.” This figure was multiplied by the rate of return, based on a comparable earnings standard, of 10.5 per cent. Thus, the Examiner concluded that the cost element attributable to rate of return on production investment was 4.-24 X 11 X 10.5 = 4.90 (cents per Mcf.

The Commission, after raising various questions about methodological difficulties in calculating a rate of return, stated that “[i]n light of the current higher costs of capital and the need for additional incentives for investment in gas exploration” that the rate of return adopted would be 15 percent. Evidently assuming that recoupment of investment occurred over a shorter than 10 year period, or that a one year time lag was insufficient, the Commission applied the 15% rate of return to a “theoretical average rate base” calculated by multiplying production investment cost by a factor of 10, rather than 11. Given the range of production investment from 4.-24 to 6.86, this produced a variable range for rate of return of 6.24 (4. 24 X 10 X 15) to 10.29 (6.86 X 10 X 15) cents per Mcf.

Having calculated a variable range of costs, the Commission selected the 24 cents price as that which would be used for new gas-well gas. In support of this price, the Commission made two points: (1) non-cost factors were not quantified separately, but were instead reflected in each cost item, and (2) the price was within a range of possible prices, 22-26 cents per Mcf, which the variable cost ranges would support.

By non-cost factors, the Commission meant “such considerations as the incentive necessary to elicit additional supplies of natural gas, competitive consequences upon the industry, and the need for adequate capital to finance further exploration and development.” Presumably, this inclusion of non-cost factors was reflected in raising rate of return from 10.5% to 15%. The approach to reflect non-cost considerations in each cost component, rather than in a separate category, was a departure from the Examiner’s approach and from the Permian methodology generally.

The Examiner described the approach used since Permian as follows :

In Opinion No. 468 [Permian] the Commission stressed the importance of encouraging a level of exploratory effort which would continue to provide for findings (reserves added) in excess of production. It concluded that since revenues are obtained only from production, the “total cost of finding the necessary volumes of gas must be translated into an allowance per Mcf of gas produced so as to bring in the necessary revenues.” To this end, a 37 percent conversion factor was developed to adjust the per Mcf cost of unsuccessful E and D [Exploration and Development] efforts from the volume of gas produced during the year.

Following this procedure, the Examiner took various finding/production ratios, and determined that the evidence indicated a 37 percent figure, the same as utilized in Permian. The Examiner had calculated E & D at 3.14 cents (sum of cost of Dry holes and of other exploration costs), and applied the adjustment factor of 37%, for exploration in excess of production, to yield an additional 1.16 cents per Mcf.

The approach of the Examiner was intended to keep the findings/production ratio at its past level, which he calculated was close to 139% for the four year average of 1963-1966. As we have already noted, however, the F/P ratio has been below unity since 1967. In the view that a continuation past policy would prove inadequate to cure supply shortage, the FPC made adjustments to individual cost figures.

The FPC explained its choice of a maximum price, of 24 cents, as follows:

We can state with certainty that the facts before us in these proceedings support the result we have reached. It could also support a price higher or lower by as much as two or more cents in either direction; in other words, we could, with ample support select individual cost components to yield a result within this range, or an even larger one.

The Commission went on to state:

Our finding that 24 cents per Mcf is the just and reasonable rate for new gas is within the range or zone of reasonableness, which we find to exist and our selection of this price represents our judgment as to the level necessary to elicit additional supplies from this area. . . . We find that 24 cents is consistent with nationwide costs of new gas, and calculated to permit the interstate market to make some inroads into the trend of gas sales to seek the intrastate market in the Texas Gulf and other competitive market areas, nationwide.

The table set out at the beginning of this Methodology discussion reveals that it did not include cost figures for royalties or production tax, even though these costs were determined by the Examiner, calculated as percentages of the total cost of new gas-well gas; 4% for royalties and 7% for production tax. The reason for this non-calculation has more to do with the use that is to be made of the variable cost range than it does with the difficulties of calculation. Thus, the Commission states:

While any individual cost component might fall within the range indicated for it, it is improbable that either the high or low limit of every range would properly be cumulated to produce a total equal to the highest or lowest range of cost, so no total range may be derived upon which royalty or production might be computed.

Leaving aside this warning, it is, nonetheless, instructive to calculate the range of total cost which would result from cumulating the lowest costs and the highest costs, in the range of costs for each item. A mathematical calculation, on this basis, shows a resulting range of total costs from a low of 16.19 cents to a high range of 26.08 cents. Our calculation confirms the Commission’s indication that 26 cents would be the highest price its data would support, a price reached only on the “improbable” assumption of cumulating the higher limit in the variable range of costs for each item.

Viewed in this light, the 24 cents price is seen to lie between 16 cents and 26 cents (with appropriate adjustment), and thus is within the range. The selection of a specific figure tilted toward the high side of the cumulative range was presumably dictated by supply considerations. It will be recalled that these same supply considerations accounted for the higher limit for each variable range item.

That the 24 cent FPC price was based largely on supply considerations is also confirmed by the Commission’s comparison of the 24 cents price chosen with the price currently paid for gas in the intrastate market, a demand which competes with that of the interstate market. The FPC obtained a compilation of contract prices recorded in the intrastate market since 1966. These data indicated a low price of 10.025 units per Mcf, for a contract entered into in 1967, and a high price of 24.38 cents, for a contract dated in 1970. Although the Commission indicated that it expected intrastate prices to go even higher, and there is already information to support this view, it is clear that the Commission chose a price which it thought would give the interstate market a fair chance of competing with the intrastate market. As the Commission stated, “no substantial amount of gas will be obtained for interstate pipelines unless interstate buyers can offer prices competitive with the dominant intrastate market.”

“Flowing Gas”

The 24 cent rate thus reached was made applicable by the FPC only to “new gas.” Under the three-vintage system prescribed by its Order, the October 1, 1968 cut-off date for new gas made that price applicable only to gas sold under contracts dated on or after October 1, 1968. The Commission also established prices for two vintages of “flowing gas”: for gas sold under contracts dated prior to January 1, 1961, and for gas sold under contracts dated on or after January 1, 1961, and prior to October 1, 1968. We now discuss the Commission’s approach to pricing these vintages of gas. We defer discussion of the justification for the cut-off between new and flowing gas; here we consider only the method employed to set the price for “flowing gas,” a price that some producers challenge as too low, and not justified on the record.

As to “flowing gas,” the Examiner’s approach, which followed the methodology of Permian, was to base price strictly on costs, with little consideration given to non-cost factors, such as the need for increased supply. In his view any incentives for additional exploration activity were to come through the price of new gas. There seem to be two reasons for his approach: (1) prices above cost could not function as a reward for past exploratory activity, because prior to 1961 there was little “directionality” in the exploration for gas, i. e., one only explored for oil, and (2) prices above cost would naturally be unrelated to new discovery because the gas in question was already discovered, and, thus, any increase of the flowing gas rate would merely be a windfall for producers. The producers argued for a single priced system based on current costs, which they claimed was required “because revenues for current explorations and development must be internally generated from sales of gas from whatever source,” and because new discovery could not take place only as a function of the new gas price, since funds for investment purposes had to be generated from flowing gas revenues. Rejecting this producer approach, the Examiner considered this source-of-funds contention insubstantial, as distinguished from the issue of inducement, and was concerned lest the order provide funds, for the purpose of enhancing discovery, which would effect a windfall if not directed to new discovery, and made applicable to “flowing gas.”

In setting a flowing gas rate, the Examiner calculated historical costs, in a manner similar to that used in calculating current costs for the new gas price. The composite cost figures produced by this approach were:

Cents/mcf.
(1) Unit production cost ............... 7.38
(2) Additional Allowances to bring gas up to pipeline quality
(a) Separate gathering...............13
(b) Producer Plant Costs............81
(c) Pipeline Incurred Cost............14
(3) E&D expense ...................... 4.10
(4) Regulatory expense..................16
(5) Production Tax.....................93 13.65
Unit production costs were broken down as follows: 21 Cash operating expense ................ 2.03
DD&A .............................. 2.13
Return Allowance ..................... 3.22 7.38Í

The return allowance of 3.220 reflected use of a 10.5% rate of return, the same as the rate of return allowed on new gas. The Examiner, on the basis of these cost items, found that 13.7 cents per Mcf would be the “just and reasonable” ceiling rate, to govern contracts negotiated before January 1, 1961, the cut-off date he set for flowing and new gas.

The principal impact of the “flowing gas” rates is the effect upon outstanding refund obligations. Prior to the proceeding, the FPC had, through a certification procedure, authorized new deliveries on contracts with prices set, on the basis of a market price, subject, however, to a Commission determination of the “just and reasonable rate,” the right to sell at a negotiated price being thus conditioned on refund obligations. See Atlantic Rfg. Co. v. Pub. Serv. Comm’n (CATCO), 360 U.S. 378, 79 S. Ct. 1246, 3 L.Ed.2d 1312 (1959). Since the area rate “retroactively” establishes what was a “just and reasonable rate,” it simultaneously determines what portion of a price charged in the past must be refunded.

The Commission changed the Examiner’s approach in several respects: The Commission provided that there would be two, instead of one, vintages of flowing gas, and that the price for each vintage would increase over time and be keyed to the date of delivery. The Commission also departed from the Examiner in calculating the base price upon which the escalations were to be based.

In deciding to create two vintages of flowing gas, the Commission indicated it was following the approach the Commission took in the Southern Louisiana Area Rate Proceeding, 40 FPC 530 (1968). The choice of two vintages would seem to be related to differences in historical costs and the passage of time between the Examiner’s and Commissioner’s decision: thus, the pre-1961 period was dealt with by the Examiner as a flowing gas rate and the 1961-1968 period was dealt with as new gas, which by the time the Commission issued its decision, had, in fact, become flowing gas.

The Commission stated that it would take as a starting point the prices recommended by the Examiner for these two periods, the 13.680 price for pre1961 gas, and an 18 cent price for the 1961-68 period (the Examiner’s price for the second period, which he had calculated as being new gas, was 17.4-17.8 cents per Mcf). It then proceeded to adjust both prices.

For pre-1961 gas, the Commission raised the base rate to 15 cents, “[i]n order to assure that inaccuracy shall not result in the producers receiving less than their cost, including a proper rate of return. . . . ” The Commission then outlined a means by which this 15 cent “base price” would be increased depending on the date of delivery: 15 cents for gas delivered prior to January 1, 1965, at least a 17 cent ceiling for gas delivered after January 1, 1965; except that a 19 cent price applies to gas delivered after January 1, 1968. Four justifications were given for this escalation provision: (1) well drilling costs have increased between 1961 and 1968; (2) well rehabilitation and equipment repair and replacement is more of a factor in the Texas Gulf Coast than in any other major area; (3) a large percentage of 1962 flowing gas in the area comes from very old, low-cost leases, and as the amount of this low-cost gas declined, the average cost of 1962 flowing gas would increase in later years; and (4) “we recognize the importance of revenues from flowing gas a source of funds for new investments by the producers.”

Since the first three factors were all available to the Examiner, it seems likely that the last factor, supplying increased capital, is the likely explanation for the Commission action, especially in light of additional yields given on “flowing gas” by the contingent escalation feature of the rate order.

For gas sold under contracts dated between January 1, 1961, and October 1, 1968, the escalation features were similar. The increase in base and escalated prices was justified largely by reference to cost increases over time not considered by the Examiner because of the timing of his decision (1968). The need for increased capital may again be used to justify the elevation of the Examiner’s price.

BAZELON, Chief Judge,

with whom

CHARLES R. RICHEY,

District Judge, concurs:

At the heart of this case lies the problem of ensuring an adequate, continuing supply of natural gas to consumers in the interstate market. We are told that the nation is suffering a shortage in its gas reserves that has already reached crisis proportions and that threatens to become increasingly severe. In both major parts of its order in this proceeding —the system of incentives and the schedule of base area rates — the Federal Power Commission has responded to this supply shortage problem. The Commission justifies the incentive features solely on the ground that they are necessary to elicit increased gas supplies, without regard to the producers’ cost of service. We agree with Judge Leventhal that these noncost incentive provisions must be remanded to the Commission for further consideration. But our reasons for doing so lead us to reject the base area rate schedule as well. The defect that we find in the Commission’s order is, essentially, a lack of information, a lack so pervasive that, even within the narrow limits of our judicial review function, we are unable to say whether the rates announced in this order are reasonable or whether they comport with the requirements of the Natural Gas Act.

I

As Judge Leventhal points out, the base area rates devised by the Commission for both new and flowing natural gas contain significant upward adjustments purportedly justified by the supply shortage factor. In selecting the 24 cents price for new gas-well gas, the problem of supply entered the calculus at two points. First, the Commission took non-cost factors into account in calculating the components of the variable range of costs (including, presumably, the fifteen percent rate of return) within which the new price was to fall. The non-cost factors were, the Commission said, “such considerations as the incentive necessary to elicit additional supplies of natural gas, competitive consequences upon the industry, and the need for adequate capital to finance further exploration and development.” Second, and again apparently because of the supply problem, the Commission chose the 24 cents rate from the high end of the variable range thus calculated. As to the flowing gas rates, the Commission adjusted the vintages in light of the passage of time; it then raised the rates applicable to each on the basis of four factors, the last of which — “the importance of revenues from flowing gas as a source of funds for new investments by the producers” — responds to the supply problem.

The Commission has thus presented a wide spectrum of possible results, and argues that any result within that spectrum is, in significant part, cost justified and, pro tanto, can be supported by substantial evidence in the record taken in its entirety. The Commission argues, furthermore, that the supply shortage problem that figures so prominently in its results is itself established by substantial evidence. But these arguments cannot conclude our task, even if we undertake an independent examination of their validity. There remains a basic question: the relationship between the supply shortage problem, on the one hand, and the Commission’s response, on the other.

The producers have contended, both in their petitions to the Commission for rehearing and in their petitions for review in this court, that the order’s base area rates are too low to meet the supply problem that the Commission has identified. We do not follow their contention to the point of holding, or even implying, that because of the supply problem, cost of service calculations should be abandoned altogether as premises for establishing base area rates. On the contrary, we agree with much of what Judge Leventhal has said about the continued usefulness of costs as, at least, threshold criteria for judging whether rates are reasonable. Moreover, we fully recognize that we are required to approve the Commission’s rates if they fall within a “zone of reasonableness.” Our disagreement with the Commission (and apparently with Judge Leventhal) concerns, instead, its rather facile identification of the zone of reasonableness with the variable range of costs it has calculated, and its assumption that the zone encompasses the upward adjustments it has chosen to make.

In the Permian Basin Area Rate Cases, the Supreme Court imposed on reviewing courts an obligation to “require criteria more discriminating than justice and arbitrariness” in appraising the Commission’s orders. Although it is neither our function nor within our capacity to substitute our own judgment for that of the Commission, we must assure ourselves that the Commission has “given reasoned consideration to each of the pertinent factors.” To this end the Commission must indicate “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 responsible, not for determining what the Commission might have done in this proceeding, but for judging, on the basis of the record and the Commission’s reasoning, what it has done, and whether “each of the order’s essential elements is supported by substantial evidence.”

As we shall set forth, the problem of supply has come to play an increasingly central role in the Commission’s efforts at rate regulation under the Natural Gas Act. The order before us in this case represents one more step —a substantial step — in this process. The fact of the matter is that the Commission has used cost of service calculations, in the traditional regulatory sense, only as starting points in fixing the rates contained in its order; the range of variable costs is infused throughout with non-cost factors. We think the time has come to recognize that these factors are “essential elements” of the Commission’s order, and to apply to them the standard of review that the statute mandates.

The Commission’s justification for the upward adjustments in the base rates is contained in the following paragraph of its opinion:

There is no reliable evidence which would indicate the amount of new gas reserves that would be discovered as the result of any specific change in rates, nor evidence as to the amount of such reserves that would be dedicated to the interstate market. However, it is our judgment that the new gas prices we establish herein will re-suit in increased drilling efforts by the producers and new gas discoveries in the Texas Gulf Coast area. We are of the view that increased efforts in the Federal domain [i. e., offshore] area will be successful. The Potential Gas Committee estimates probable reserves of 40 trillion cubic feet in this offshore area. Although we realize the unregulated intrastate market will be successful in contracting for some of these new reserves — to the extent that the reserves are not in the Federal domain- — -it is our goal to establish a price which will both substantially increase discoveries and permit interstate pipelines to compete with intrastate purchasers for these new reserves.

The Commission has thus informed us —frankly and with full regard for our responsibilities — that it does not know what “the consequences of its order for the character and future development of the industry” will be. It has informed us that it believes the rate schedule it has decreed will result in increased discovery and dedication of natural gas to the interstate market. On the surface, this conclusion seems obvious; it appears to say only that supply may be influenced by price. The question that the Commission must answer, however, is not whether some increases in rates are necessary, but why it believes that these increases, in combination with the other elements of its order, are a reasonable response to the problem of supply that it says exists. And its answer to that question is what we must review for substantial evidence and for reasoned justification that takes full account of the interests Congress intended this statute to protect. We find, neither such evidence nor such justification in the record here.

It is necessary that we admit, as the Commission has admitted, that it may be impossible for it to discharge its responsibility under this statute, this procedural mechanism, and in this atmosphere of crisis. But if the choice is to maintain the form and suffer the evils of self-deception, or to require that whatever regulation we have be responsibly imposed, we must choose the latter. If the statute will not support the results that the Commission thinks appropriate, then it is the province of Congress to alter the statute.

II

And the statute is, we think, a substantial part of the problem. When the Natural Gas Act was enacted in 1938, granting the Federal Power Commission jurisdiction to regulate the transportation and sale of natural gas for resale in interstate commerce, it was generally thought applicable only to sales by interstate pipelines to intrastate pipelines and distributing companies, and not to initial sales by producers to the pipelines. The legislative history of the Act indicates that several factors combined to cause Congress to confer this jurisdiction. The first was the rapid expansion and increasing importance of the natural gas industry itself. As the industry developed, ownership of the pipelines came to be concentrated in the hands of a few companies, and state utility commissions, which had regulated intrastate pipeline sales to local distributors, found themselves unable, because of a combination of factors, to regulate the prices of the new interstate giants. Gas in the interstate market was thus subject to monopolistic controls: the interstate pipelines limited supply, prices were openly discriminatory, and attempts were made to drive “raiders”-— those who tried to introduce competing pipelines — from the market.

In the face of these problems, the overriding concern of Congress was to move back up the chain of distribution and to control the interstate movement of gas that the states had been unable to reach. Quite naturally, the proposed legislation simply adopted the regulatory approach that had been in use in the states and in other areas of federal regulation, such as railroads. The thought was that if prices established between interstate pipelines and intrastate pipelines and distributing companies were being unfairly inflated, it was only necessary to pierce the holding company veil and to determine, apparently on the traditional regulatory basis of cost of service, the just and reasonable rate for the interstate market. Indeed, supply, to the extent that it was considered at all, was broached only in terms of the need to prevent waste of gas by smoothing out the paths of interstate commerce.

In reciting these aspects of the legislative history, we do not mean to be drawn into the fervent and continuing debate as to whether it supports FPC jurisdiction over independent producers of natural gas. The Supreme Court resolved this question definitively in Phillips 7. We do mean to indicate, however, that under this statute the problems of regulating the interstate market in natural gas, difficult enough when such regulation extended to interstate pipelines (including those integrated with producers), became even more difficult, perhaps intractably so, when it was extended to cover the entire interstate field market. As the Supreme Court recognized in Permian, “ [producers of natural gas cannot usefully be classed as public utilities.” Yet, whatever the intention of its framers, the system of regulation and regulatory standards established by the Natural Gas Act, appropriate enough for the pipelines themselves, was, in Justice Harlan’s phrase, “ill-suited” to anything other than the regulation of public utilities and of the processors or transporters of otherwise freely priced commodities. In establishing the statutory scheme, Congress simply did not advert to the difficulties that regulating the field price of natural gas would pose, difficulties brought into full relief in the course of the Commission’s regulatory attempts.

We rehearse, therefore, the history of judicial review of Commission rate orders under the Act not only to define the legal standards that must guide our decision, but also because this history demonstrates with full clarity the dilemma in which we now find ourselves. The touchstones of review in the Act itself are, as we have noted, derived from traditional regulatory statute formulae. Section 19(b), which authorizes review of Commission rate orders by the courts of appeals, provides that the Commission’s findings of fact, “if supported by substantial evidence, shall be conclusive.” Section 4(a) requires that the rates of natural gas companies subject to the Act “shall be just and reasonable .section 5(a) directs the Commission to “determine the just and reasonable rate” to be observed and to “fix the same by order.” The terms “just” and “reasonable” are not, of course, self-defining. Since the passage of the Act the courts have attempted to infuse them with some content that would at once preserve the integrity of the judicial review process and, at the same time, free the Commission to confront the peculiar problems of the natural gas market.

In FPC v. National Gas Pipeline Inc., the Supreme Court identified the lowest rate permissible under the just and reasonable standard with the lowest rate that may be fixed without being confiscatory in the constitutional sense. The Court observed that there exists a “zone of reasonableness within which the Commission is free to fix a rate varying in amount and higher than a confiscatory rate.” Within this zone, the Commission may make “the pragmatic adjustments which may be called for by particular circumstances.” Two years later, in FPC v. Hope Natural Gas Company, the Court reiterated the expressions of Natural Gas Pipeline and amplified the regulatory discretion allowed. Hope established a permissive constitutional approach, the most important consequence of which was to permit the use of original cost, rather than reproduction cost, in computing a rate base. More broadly, however, Hope freed regulation from the use of traditional legal accounting methods in arriving at just and reasonable rates: “Under the statutory standard of ‘just and reasonable’ it is the result reached not the method employed which is controlling .... It is not theory but the impact of the rate order which counts.” Natural gas ratemaking, the Court said, involves the balancing of investor and consumer interests, and, from the investor side, it is important that there be sufficient revenue to cover both operating and capital costs. To protect this interest, “the return to the equity owner should be commensurate with returns on investments in other enterprises having corresponding risks.”

The criteria that the Court advanced were, perhaps, easy enough to apply in the context of Hope itself, which concerned an individual company with an excellent earnings record. But the concerns voiced by Justice Jackson in his separate opinion have increasingly come to the fore. Justice Jackson observed that Hope’s business comprised two elements. The first element — the pipeline — was “essentially a transportation enterprise . . . not differing substantially from many other utility operations;” to this element traditional cost of service rate making might appropriately be applied. But the second element of Hope’s business — -“to reduce to possession an adequate supply of natural gas” — differed radically:

The heart of this problem is the elusive, exhaustible, and irreplaceable nature of natural gas itself. Given sufficient money, we can produce any desired amount of railroad, bus, or steamship transportation, or communications facilities, or capacity for generation of electric energy, or for the manufacture of gas of a kind. In the service of such utilities one customer has little concern with the amount taken by another, one’s wáste will not deprive another, a volume of service can be created equal to demand, and today’s demands will not exhaust or lessen capacity to serve tomorrow. But the wealth of Midas and the wit of man cannot produce or reproduce a natural gas field.

Because, in Justice Jackson’s view, the natural gas market involves a wasting resource, the exploration for and production of which are “more erratic and irregular and unpredictable in relation to investment than any phase of any other utility business,” its regulation cannot ultimately rely on the traditional eostof-service methodology. Instead, the central problem of natural gas regulation must involve the functional use of price to elicit a supply of gas adequate to meet demand, and to allocate supply to those uses most efficient and valuable for society:

The function which an allowance for gas in the field should perform for society . . . is to be enough and no more than enough to induce private enterprise completely and efficiently to utilize gas resources, to acquire for public service any available gas or gas rights and to deliver gas at a rate and for uses which will be in the future as well as in the present public interest.

The concerns expressed by Justice Jackson have come to pervade the Commission’s area rate decisions. When, in 1954, the Supreme Court held that the Federal Power Commission has jurisdiction under the Natural Gas Act to regulate the prices at which independent producers sell gas to interstate pipelines, the Commission at first struggled manfully to regulate individual companies on a cost of service basis. But the attempt proved unsuccessful, both because of the large number of independent producers requiring individual attention and, equally important, because of the conceptual difficulties involved in determining, on an individual basis, the costs of gas production and the appropriate rate of return. In 1960, the Commission decided to abandon the individual cost of service approach and to institute area rate proceedings instead, a decision affirmed by the Supreme Court in Phillips II. In setting area rates, the Commission said, “[0]ur ultimate objectives will be to set prices in all producing areas which will be adequate to maintain the gas supplies needed by the consumers of the nation, but at prices that are no higher than are necessary to accomplish that purpose.”

To achieve these objectives, the Commission devised a “two-tiered” rate system, a system of which the one before us is a variant. This system involves determining two different prices or sets of prices for each geographically identifiable producing area. The Commission establishes one ceiling price for new gas from gas wells and a second, lower ceiling price for both old, or flowing, gas from gas wells and all gas produced in conjunction with oil. The theory underlying this two-tiered system and its variants is that the market for new gas, because it is still in various stages of development, is responsive to price, while the market for flowing gas and for oil well gas is not. In theory, therefore, the Commission can achieve the best of two worlds: the price for new gas can be set at a level sufficiently high to ensure continued development of new supplies and their dedication to the interstate market, thus preventing shortages, while the lower rates on flowing gas will result in lower prices to the consumer.

In Permian Basin, the first area rate case, the Supreme Court gave explicit approval to the Commission’s two-tiered system. The Court said that, within a zone of reasonableness, the Commission may “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.” Indeed, the Court indicated that it might well be essential for the Commission to take non-cost factors into account if it is effectively to fulfill its statutory duty to protect the public interest in a supply of natural gas adequate to meet present and future needs.

The Commission has computed the two maximum prices for Permian Basin directly from costs of service; it assumed that the differential between the prices for new and flowing gas resulting from differences in the time periods and geographical areas used to compute costs would serve as a sufficient incentive to production, without introducing noncost factors. Despite its doubts on some points, the Court approved the system of rates that the Commission had established, rejecting challenges to both particular elements in the Commission’s calculations and to the rate schedule’s overall effects. In his opinion for the majority, Justice Harlan defined the responsibilities that a reviewing court must exercise:

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.

At the same time, the Court fully recognized the “intensely practical difficulties” faced by the Commission in its attempt to regulate the field price of natural gas, and said that the Commission must be given “every reasonable opportunity” to devise regulatory methods appropriate to their solution. Justice Harlan emphasized that the first area rate proceeding was something of an experiment, a fact to which the Court was obliged to give weight in its review of the Commission’s order. But he went on to warn that “this weight must significantly lessen as the Commission’s experience with area regulation lengthens.”

It is important, then, that we understand some of the problems that area price regulation confronts, particularly when it is undertaken within the structure created by Congress in the Natural Gas Act. The rates that the Commission sets for new gas must be sufficiently high to pay the costs of developing new supply sufficient to meet demand, a demand certain to be increased by the lower prices on flowing gas. To do this, the Commission must attempt to determine the marginal cost of future gas production, an attempt that necessarily involves some guesswork. Second, as the Court noted in Permian; there is a forceful argument that, in the context of an industry like the development and production of natural gas, calculation of rates on the basis of costs is in any event “hopelessly circular”: if, on the basis of predicted costs, the Commission sets the price at a certain amount, the industry will invest resources in new production worth up to that amount but no more; in other words, the Commission’s rate per unit of production will elicit costs, including return, equal to it. Third, under the Act, the Commission has jurisdiction to regulate only the prices at which the producers sell in interstate commerce; it has no power to regulate the prices at which the producers sell intrastate within the production region. As a result, to avoid shortage in the interstate market, the Commission must set rates at a level sufficiently high to bid supplies away from intrastate, and primarily industrial, purchasers. Finally, these problems are aggravated by the fact that the Commission must work in an extended time-frame; because of the complexity of area rate proceedings, the Commission must establish a rate structure that it believes will be reasonably efficacious for a substantial period of time.

Because of these considerations, non-cost factors directed to the problem of supply have, since Permian Basin, played an increasingly central role, not only in the structure of the area rate systems decreed by the Commission, but also in the calculation of the rates themselves. All of the Commission’s subsequent area rate orders have been approved. But we sense in the opinions of our sister circuits at least some degree of uncertainty about the methods that the Commission has employed and the results at which it has arrived. In the first Southern Louisiana Area Rate Case, the Fifth Circuit expressed disappointment that the Commission had failed explicitly to explain what effect its rate order could be expected to have on the supply shortage problem. In accordance with the Supreme Court’s opinion in Permian, the court held that non-cost factors may properly be considered in establishing a rate structure, but that such factors must be clearly labeled and justified on the basis of substantial evidence in the record as a whole. The court concluded that “the Commission here, having calculated the dangers involved in allowing the gas supply to lapse, and the probabilities that its estimates might be too low, is justified in having added the small noneost factors it thought were necessary.” It warned, however, that “use of non-cost factors to allow for possible inaccuracies is not favored. Inaccuracy, if that is really the concern (and not higher costs), can result in a windfall to producers as easily as in a loss.”

In the second Southern Louisiana Rate Case, which involved rates that, in most essential respects, were closely similar to those involved here, the Fifth Circuit repeated the concerns it had voiced earlier; but once again it concluded that the Commission’s order must be enforced. The Court said that area rate regulation remains an experiment and, therefore, continues to warrant “kid glove review”: “No one can honestly say that judges have been any more sure than commissioners, as all struggle with a problem that grows out of the peculiar mixture of a simultaneous service and exhaustion of a depletable asset. All have been groping. The day for groping is not yet over.” The Court’s decision rested heavily on its recognition that there exists a supply shortage problem — a problem that, the court said, “can only be described as a crisis.” The Court concluded that, given this fact, the Commission must “swing the pendulum towards the incentive, supply-eliciting side of rates. And so it has done.”

Most recently, in the Other Southwest Area Rate Case, the Fifth Circuit observed that, as in Southern Louisiana 11, the Commission was “unable or unwilling to quantify the relationship between the rates it established and the likely response of market forces.” Furthermore, the court recognized that the Commission’s upward adjustments in rates in response to the supply problem have become significant factors — perhaps, of necessity, the significant factors — in the level of rates that the Commission has established. And it said that “[w]e must decide whether FPC has erred in including, excluding, or evaluating components of the rate structure to determine if the particular error washes out in the ‘zone of reasonableness,’ or has such significance that the result is unacceptable.” Yet, despite its doubts on several points, the court felt compelled to enforce the Commission’s order.

Ill

There is no essential disagreement as to the purpose of regulation under the Natural Gas Act. As the Supreme Court said in Phillips I, the primary aim of the Act is the “protection of consumers against exploitation at the hands of natural-gas companies . . . . ” More broadly put, the purpose of regulation is to ensure that natural gas be distributed at the lowest possible price, that its private producers and distributors not reap windfall profits at the expense of the consuming public, and that allocation of this valuable resource be dictated by the interest of the public, rather than by the interest of its holders in private gain. At the same time, the public interest requires some assurance that, both now and in the future, the supply of natural gas will be sufficient to meet those uses for which, relative to other fuels, it is most valuable.

In most regulatory contexts, perhaps, regulation on a cost of service basis can provide a reasonable approximation of these goals. But, as we hope to have shown, in the context of natural gas regulation, the traditional methodology has simply proved inadequate. By the same token, the fact that rates are “anchored” in costs might once have been enough to ensure that they fall within the zone of reasonableness. But we think this no longer the case. There can be no question that, in this order, non-cost factors —the problem of present and possible shortage — were vital determinants of the rate levels the Commission has set. We fully recognize that the Commission may take such factors into account in performing its statutory duty. But recognizing that this is so cannot solve the problem before us.

The statute imposes on us, as the reviewing court, the responsibility of determining whether the rates the Commission has devised are just and reasonable. And this has come to mean, in effect, whether the Commission has arrived at a reasonable accommodation between protecting the consumer against exploitation in the price he must pay and protecting him against possible shortages in supply. Judge Leventhal accuses us of demanding the platonic ideal in rate regulation, of seeking an unachievable perfection. If insisting on demonstrable rationality is equivalent to demanding perfection, then perhaps his accusation is correct. But we think our goal less exalted. We assume that the Commission had some reasons for concluding that its choice from within the variable range of costs and the increment it has added to the rate for flowing gas are preferable to possible alternatives, whether those alternatives are higher or lower. But on the basis of the record before us, we have no way of knowing what these reasons might have been; we have no idea why the Commission thought these upward adjustments adequate to meet the need to encourage exploration and development and to bid supplies away from the intrastate market. Indeed, for all we know they may be more than adequate. We simply do not have, and are not given, sufficient information to make this judgment. We decline to join the Commission in what' looks like a flight of faith, even though it has begun its ascent from the familiar terrain of cost.

The problem in this case is essentially the same as that which I discussed in International Harvester Company v. Ruckelshaus. In that case I was convinced that Congress did not intend the courts “to delve into the substance of the mechanical, statistical, and technological disputes” involved in setting automobile exhaust emission standards. Our proper role, instead, was “to see to it that the agency provides ‘a framework for principled decision-making.’ ” Such a framework necessarily includes “the requirement that the agency set forth with clarity the grounds for its rejection of opposing views” and the reasons it has arrived at its results. This principle applies here. Unless the Commission can supply some reasoned justification of the relationship between the causes and dimensions of the supply problem and the magnitude of the adjustments it has made in response to it —adjustments that are by no means de minimis — then it is impossible for the parties to confront and challenge the bases for its actions. And it is impossible for us to perform even our narrow review function in any meaningful way. In the absence of such explicit justification, we cannot say with any assurance that the rates decreed in this order are just and reasonable, or that the Commission has reasonably concluded that it is necessary for consumers to bear a substantial increase in the price of this essential fuel. In short, we have no way of knowing what the zone of reasonableness might be.

It may be that the Commission is unable to supply the evidentiary basis and reasoned justification we think the Act requires, that it has neither the methodological tools necessary for the regulation in which it is engaged nor the means of acquiring the information necessary to their exercise. Indeed, it may be that regulation simply cannot meet the statutory goals set for it. Some commentators have argued that the field market in natural gas is essentially competitive, and that the inefficiencies resulting from regulation greatly exceed whatever beneficial income distribution effects it may have. On the other hand, there are indications that present natural gas reserves are controlled by a small number of companies, and it has been suggested that deregulation would result in enormous windfall profits for a few large producers, while the supply shortage problem would remain at least as serious as it is now. If Congress should decide that neither the present nor some revised scheme of regulation, possibly joined with some form of subsidy for exploration, is capable of protecting the public interest, perhaps deregulation would be appropriate; if it decides that deregulation would result in unacceptable consequences, it might even wish to consider some form of nationalization.

It is, of course, for Congress, not for us, to make this choice and attempt to find a way out of the natural gas crisis. But until it does so, it remains our duty to review the actions taken by the Commission under this anachronistic statute. Congress could also, of course, decide to give the Commission, within constitutional limitations, entirely unfettered discretion and to exempt its orders from judicial review. We assume, however, that Congress would not have provided the form of judicial review without intending that review to be conseionably exercised. We can agree with the Fifth Circuit that natural gas regulation is still in the experimental stage. The costs of the experiment, however, are borne by the consumer; he has, at least, a right to some assurance that the experiment is justified. If judicial review is to deserve the name, if it is to be something more than a formal rite of passage that Commission orders must endure merely for the appearance of propriety, then we as the reviewing court must be given the means of divining what experiment it is that the Commission is conducting and why it has chosen to conduct it in the manner that it has. We cannot place our imprimatur on a Commission order, announcing to the public that we find it just and reasonable, when we have no way of knowing that it is.

With respect to the base area rates, this opinion will govern further proceedings under the court’s mandate. 
      
      . Opinion No. 595, Area Rate Proceeding, et al. (Texas Gulf Coast Area), Docket No. AR64-2, et al., 45 FPC 674 (May 6, 1971) ; Opinion No. 595-A, Area Rate Proceeding, et al., Order Modifying and Clarifying Prior Order and Denying Rehearing, 46 FPC 827 (October 18, 1971).
     
      
      . Section 4(a) of the Natural Gas Act, 15 U.S.C. § 717c, provides :
      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.
      Section 5(a), 15 U.S.C. § 717d, provides:
      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: Provided, however, That the Commission shall have no power to order any increase in any rate contained in the currently effective schedule of such natural-gas company on file with the Commission, unless such increase is in accordance with a new schedule filed by such natural-gas company ; but the Commission may order a decrease where existing rates are unjust, unduly discriminatory, preferential, otherwise unlawful, or are not the lowest reasonable rates.
     
      
      . The area was defined in the FPC order commencing this proceeding, Docket No. AR64-2, 28 Fed.Reg. 12,645 (Nov. 27, 1963).
     
      
      . The background of area rate regulation is well summarized in Southern Louisiana Area Rate Cases (Austral) v. FPC, 428 F.2d 407, 415-418 (5th Cir. 1970), cert. denied, Municipal Distributor Group v. FPC, 400 U.S. 950, 91 S.Ct. 241, 27 L.Ed.2d 257 (1970). Currently proceedings are pending before the Commission in Permian II, Docket No. AR70-1; the decision of the Presiding Examiner issued on December 20, 1972. Since Austral and Permian, Hugoton-Anadarko Area, Docket No. AR64-1, Opinion No. 586, 44 FPC 761 (1970), was affirmed by the Ninth Circuit in California v. FPC, 466 F.2d 974 (1972) ; Rocky Mountain Area, Order No. 435, Establishing Initial Rates, 46 FPC 68 (1971), is on appeal to this court (No. 71-1812) ; Southern Louisiana Area II, Opinion No. 589, 46 FPC 86 (1971), was affirmed by the Fifth Circuit sub nom. Placid Oil Co. v. FPC, 483 F.2d 880 (1973) ; and Other Southwest Area, Opinion No. 607, 46 FPC 900 (1971), was affirmed by the Fifth Circuit sub nom. Shell Oil Co. v. FPC et al., 484 F.2d 469 (1973). No appeal was taken in Appalachian and Illinois Basin Area, Docket No. R-371, Opinion No. 411, 44 FPC 1112 (1970).
     
      
      . 45 FPC at 718.
     
      
      . Id. at 720.
     
      
      . Id. at 709.
     
      
      . Id. at 710.
     
      
      . Id. at 719.
     
      
      . Id. at 687. This estimate was based on a study of the Future Requirements Committee, “Future Gas Requirements for the United States by 1975” (Vol. 3, 1969). Also, see generally Federal Power Commission, Natural Gas Supply and Demand 1971-1990, Staff Report No. 2 (1972) ; Federal Power Commission, A Staff Report on National Gas Supply and Demand (1969).
     
      
      . FPC S-207, The Gas Supplies of Interstate Natural Gas Pipeline Companies (1969), Table 11, at 29.
     
      
      . 45 FPC at 689.
     
      
      . Id.
      
     
      
      . 15 U.S.C. § 717(b).
     
      
      . 45 FPC at 689.
     
      
      . Data on Total Proven Reserves and Reserves Available for sale by large producers was compiled in Docket No. R-405, a proposed Rulemaking with respect to developing Emergency Plans in connection with reliability of electric and gas service in the United States. Data was compiled on the basis of a Commission Questionnaire. Total Proven Reserves are “The current estimated quantity of natural gas which analysis of geologic and engineering data demonstrate with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.” Proved Natural Gas Reserves Available for Sale are “those which are not covered by gas purchase contracts and are not reserved for direct industrial contracts, company use-warranty or company use-fuel' and feedstock.” As of December 31, 1969, Total Proven Reserves, as reported by the American Gas Association, were approximately 67 trillion cubic feet. As of December 31, 1969 Large Producers Reserves Available for sale were approximately 1 trillion cubic feet, and as of October 1, 1970, .7 trillion.
     
      
      . 390 U.S. at 767, 88 S.Ct. at 1360.
     
      
      . Id.
      
     
      
      . Id. at 791-792, 88 S.Ct. at 1373.
     
      
      . Id.
      
     
      
      . See, e. g., Southern. Louisiana I, Initial Decision of the Presiding Examiner, 40 PPC 703, 847-872 (1968) ; Opinion of the Commission, No. 546, 40 FPC 530, 625-626 (1968) ; Austral, supra, 428 F.2d at 436 n. 91.
     
      
      . In briefs and argument before this court, Associated Gas Distributors support the position of the Commission in its entirety. New York Public Service Commission takes the position that the prices in the rate order are high enough, but opposes the Commission on other features of the order, including the non-cost incentives. The producers take various positions. Some, such as Humble Oil, argue that the prices are not high enough, but support the Commission’s action on incentives. Others, such as Mobil, argue for higher prices but oppose the use of incentives. Still other producers, such as Blanco, attack the effect of the order on outstanding refund obligations. Following the suggestion of the Supreme Court in Permian, 390 U.S. at 766 n. 32, 88 S.Ct. 1344, counsel, upon invitation of this court, engaged in a pre-argument conference, in which significant efforts were made to focus and consolidate argumentation with a view to clarifying the positions of various parties on the issues involved in this case.
     
      
      . Blanco Oil v. F. P. C., 158 U.S.App.D.C. 257, 485 F.2d 1036.
     
      
      . This information was taken from the record of another FPC proceeding and was not before the Commission at the time of their Opinion Nos. 595 and 595-A in the instant case, issued May 6 and October 18, 1971. See FPC Docket No. R-389A, Report of the Investigating Officer, November 8, 1971.
     
      
      . See Brief For Indicated Producer Petitioners, Appendix D, The Railroad Commission of Texas, Annual Summary of Texas Natural Gas, for the division of gas between the intrastate and interstate markets. The 28.7 trillion cubic feet figure is taken from data compiled in Reports by the American Gas Association Committee on Natural Gas Reserves. See Brief of Indicated Producer Petitioners, Appendix C, updating Record evidence at 39,273.
     
      
      . 45 FPC at 706.
     
      
      . See text at note 5 sxipra.
      
     
      
      . This point is more fully discussed at text and notes infra.
      
     
      
      . 390 U.S. at 815 & n. 97, 88 S.Ct. 4344.
     
      
      . 428 F.2d at 426. The Fifth Circuit has reaffirmed its position that supply considerations can be broadly reflected in cost-based pricing in its recent opinion affirming the Commission’s Southern Louisiana II opinion. Placid Oil Co. v. F.P.C., 483 F.2d 880 (1973). This approach was also approved in the Ninth Circuit’s review of the Hugoton-Anadarko Area Rate Proceeding, 466 F. 2d 974, 985 (1972).
     
      
      . See City of Chicago v. FPC, 147 U.S. App.D.C. 312, 331, 458 F.2d 731, 750 (1971), cert. denied, 405 U.S. 1074, 92 S.Ct. 1495, 31 L.Ed.2d 808 (1972) ; City of Detroit v. FPC, 97 U.S.App.D.C. 260, 230 F.2d 810 (1955), cert. denied, 352 U.S. 829, 77 S.Ct. 34, 1 L.Ed.2d 48 (1956). Also see Texaco, Inc. v. FPC, 154 U.S.App.D.C. 168, 474 F.2d 416 (1972).
     
      
      . Texaco, Inc. et al. v. FPC, 154 U.S.App. D.C. 168, 474 F.2d 416 et seq. (1972). Judge Wilkey stated:
      Whatever the wisdom of the policy at this critical juncture of our national energy source problems, we cannot hold that non-regulation is the statutory equivalent of regulation. Only Congress can knowingly prescribe nonregulation for small producers in lieu of the existing statutory scheme of regulation found by the Supreme Court in Phillips to be mandatory under the Natural Gas Act for all producers.
      
        See also Other Southwest Area Rate Case, supra note 4, slip op. at 18.
      We reaffirm the principle that regulation cannot be conducted on a premise tantamount to nonregulation. We are not called upon to consider whether, or to what extent, exemptions may be provided when accompanied by an express determination that they will, by removing an administrative burden from the pertinent agency, improve its capacity to further the legislature’s regulatory objectives, and that the exemptions will not undercut the affirmative accomplishments of the regulatory program.
     
      
      . The Order, as yet unreported, was issued on August 3, 1972, and was later supplemented by Order 455-A, denying applications for rehearing and stay and making certain clarifications, which issued on September 8, 1972.
     
      
      . Order 455, mimeograph at 27.
     
      
      . The question of the authority of the FPO to promulgate such a rule is before the court in Docket No. 72-1837, Moss v. FPC. We do note, however, that the questions involved in that case are not the same as those raised by Texaco v. FPC, supra, as that opinion clearly indicated in 474 F.2d at page 421 note 21. Order 428, reviewed in Texaco, proposed no direct review of the negotiated contracts under Sections 4 and 7, and suggested that the contracts would be insulated from subsequent section 5 determination of “just and reasonable” rates. Order 455, on the other hand, contemplates Commission scrutiny of the negotiated rates. Presently, a number of contracts are being reviewed in Commission hearings. See, e. ff., McCulloch Oil Corp., 38 Fed.Reg. 1600; Texas Production Co. et al., 38 Fed.Reg. 1765.
     
      
      . The higher prices made possible by the Order, and the more significant departure from cost-based pricing, should elicit increased supply, if supply is at all price elastic. See E. Kitcli, Field Market for Natural Gas, 11 J. Law and Economics 243, 277 (1968).
     
      
      . Austral, supra note 4, 428 F.2d at 433.
     
      
      . The Examiner, as indicated supra priced pre-1961 gas at 13.7 cents per Mcf, and post-1961 gas at approximately 18 cents. The Commission took, instead, a base price of 15 cents for pre-1961 gas, and an 18 cents base price for 1961-1968 gas, but with escalations depending on date of delivery. See text at note 5 supra.
      
     
      
      . FPC v. Hope Natural Gas, 320 U.8. 591, 603, 64 S.Ct. 281, 88 L.Ed. 333 (1944).
     
      
      . 45 FPC at 832-835.
     
      
      . Updated costs had been calculated for successful well costs in the context of the “new gas” rate. For new gas, the FPC set up a variable range of 2.70 to 4.10 cents per Mcf, as compared with the Examiner’s figure of 2.77, and took the high side, out of concern with the need for increased supply. See 45 FPC at 704. But even a 2.70 cent cost, lower than the Examiner’s calculation, would have been within the range. The impact of increases in costs subsequent to those put into the Examiner’s calculation would be relatively modest as to “flowing gas”. Drilling costs liave already been incurred, the leases involved in the production of flowing gas have already been acquired. The last component of production investment (other than drilling costs and lease acquisition costs) is “other production facilities,” a modest — almost de minimis — item, in the range of only .33 to .73 cents per Mcf even as to new gas. While an increase in production costs may have occurred for flowing gas, it plainly could not have materially increased the FPC’s price on flowing gas.
     
      
      . In the Hugoton-Anadarko Area Rate Case, supra, 460 F.2d at 982-984, the Ninth Circuit took the position that it was not necessary for the Commission to make an express finding on rate of return, or that the court be able to estimate, on the basis of substantial evidence, in what range that rate fell. Circuit Judge Hamley believed that rate of return within the context of area rates, where actual rates of return would differ among producers, was inescapably imprecise and “not necessarily an indispensable or controlling factor.” Id. at 983. We note, however, that all costs in the rate base are subject to the same imprecision.
     
      
      . The effective average rate of return on flowing gas will depend (a) on how much of the price increment allowed by the Commission is not traceable to increased costs, and (b) the effective increase that will result from the escalation provisions.
     
      
      . I-I. Leventhal, Vitality of the Comparable Earnings Standard For Regulation of Utilities in a Growth Economy, 74 Yale L.J. 989 (1965).
     
      
      . Other specific challenges to features of the rate order are so insubstantial as not to require comment.
     
      
      . 45 FPC at 693.
     
      
      . See 45 FPC at 857.
     
      
      . 45 FPC at 861 (Examiner), as adopted by the Commission generally, 45 FPC at 708-709.
     
      
      .Brief of Respondent at 37 n. 29. For the use of the “modified BTU method” in Permiam by the Commission, see 34 FPC 159, 217 (1965), and in Southern Louisiana I, see 40 FPC 530, 592-95 (1968), as aff’d in Austral, supra, 428 F.2d at 422. For the acceptance of the direct assignment method by the Commission, in Southern Louisiana II, in an opinion based on a settlement proposal, see 46 FPC 86, 136 (1971). We note that the argument on the basis of precedent has been “lifted” from the Commission’s opinion in Southern Louisiana II, 46 FPC at 136-137, and does not appear in the Commission’s decision in the instant case.
     
      
      . 463 F.2d at 265.
     
      
      . 40 FPC 608-10.
     
      
      . 40 FPC at 555.
     
      
      . See opinion of Chief Judge Bazelon in International Harvester Co., et al. v. Ruckelshaus, 155 U.S.App.D.C. 411, 478 F.2d 615, 650, 1973.
     
      
      . Reserves dedicated for refund reduction are not to be counted toward new dedications needed to trigger the contingent escalation on flowing gas.
     
      
      . 45 FPC at 680.
     
      
      . 45 FPC at 709.
     
      
      . 46 FPC at 830.
     
      
      . Rocky Mountain, Order No. 435, 46 FPC 68 (1971), adopted a rule-making proceeding, and this procedure was approved in Phillips Petroleum Co. v. FPC, 475 F.2d 842 (1973, 10th Cir.). The Appalachian-Illinois Order No. 411, 44 FPC 1112 (1970), to similar effect, was not appealed. A case currently before this court, American Public Gas Association v. FPC, No. 71-1812, raises similar questions.
     
      
      . As noted in the text, we believe that the “substantial evidence” standard requires a decision on the record but not necessarily with adjudicatory procedures. However, under the Administrative Procedure Act, 5 U. S.C. §§ 553, 556 and 706, a “substantial evidence” standard of judicial review is usually the handmaiden of § 556 procedures, whereas rule-making proceedings are reviewed under the more narrow “arbitrary and capricious” standard. This may not always be the case, since § 556(d) contemplates the limiting of adjudicatory procedures even when § 556 clearly applies. It is this type of hybrid which would be created by permitting rule-making under the Natural Gas Act.
     
      
      . 410 U.S. 224, 93 S.Ct. 810, 35 L.Ed.2d 223 (1973).
     
      
      . See Universal Camera Corp. v. Labor Board, 340 U.S. 474, 71 S.Ct. 456, 95 L.Ed. 456 (1951).
     
      
      . 475 F.2d at 850.
     
      
      . 46 FPC 128-132.
     
      
      . This is not to say that the Commission does not have the authority to promulgate national rates, but that approach is certainly inconsistent with the approach taken by the Commission in this proceeding.
     
      
      . “[In] any situation in which the Commission wishes to incorporate evidence from another proceeding, it must give the interested parties notice and an opportunity to comment on such evidence. » * * The Commission would not be free to incorporate as evidence mere conclusions reached by the Commission in other proceedings. By like token, the Commission would not be free to adopt factual assertions (such as settlement offers) which had not been subject to examination and testing by opposing parties.” Mobil Oil Corporation v. FPC, 157 U.S. App.D.C. 235, at p. 260, 483 F.2d 1238 at p. 1263 note 93.
     
      
      . Burlington Truck Lines v. United States, 371 U.S. 156, 168-169, 83 S.Ct. 239, 9 L.Ed.2d 207 (1962) ; Braniff Airways, Inc. v. CAB, 126 U.S.App.D.C. 399, 411, 379 F.2d 453, 465 (1967) ; International Harvester et al. v. Ruckelshaus, 155 U.S.App.D.C. 411, 478 F.2d 615 (1973).
     
      
      . Morgan v. United States, 304 U.S. 1, 58 S.Ct. 773, 82 L.Ed. 1129 (1938) ; Greater Boston TV v. FCC, 143 U.S.App.D.C. 383, 392, 444 F.2d 841, 850, cert. denied, 403 U. S. 923, 91 S.Ct. 2229, 29 L.Ed.2d 701 (1971).
     
      
      .The Commission merely stated, 46 FPC at 830:
      The rate and rate design issues raised in this proceeding are in many respects analogous to those raised on rehearing in Southern Louisiana II ... We find it unnecessary to repeat what we said in that opinion, which is generally controlling and dispositive of similar issues raised here. We thus incorporate by reference in this opinion our decision in Opinion No. 598-A, issued September 9, 1971.
     
      
      . See cases cited note 31 supra.
      
     
      
      . In its brief, at 14, n.7, the New York Public Service Commission estimates that there are 15 trillion cubic feet which will be entitled to the two cent bonus if and when the producers find the necessary new gas. This, they go on to estimate, will equal $300,000,000 payable for finding the new gas, or an extra three cents per Mcf. The Brief For Indicated Producer Intervenors, at 7 n.3, states that this calculation is based on pure speculation.
     
      
      . NY Public Service Commission Brief at 22.
     
      
      . Chase Manhattan Bank: Annual Financial Analysis Petroleum Industry Reports, 1954-1963, and Annual Financial Analysis of 32 Petroleum Companies (33 in years prior to 1963).
     
      
      . The Examiner, 45 FPC at 824-35 assumed that the “comparable earnings” rate of return looked to statistical data of companies, as would seem appropriate for the equity investor in assessing the risk of investing in stock.
     
      
      . See E. Solomon, Theory of Financial Management 51-53 (1963).
     
      
      . See Joint Appendix, Part II, Vol. 3, at 18, R. 1,832.
     
      
      . Whether retained earnings may be a cheaper source of financing, raises a different question than whether they are the exclusive source. See Solomon, supra note 73, at 27 where he states that an investment will be made if “the rate of return it promises (correctly computed from expected outlays and benefits) exceeds the cost of capital.”
     
      
      . 46 FPC at 833.
     
      
      . See note 2 supra.
      
     
      
      . 390 U.S. at 792, 88 S.Ct. at 1373.
     
      
      . 428 F.2d at 439.
     
      
      . 428 F.2d at 440.
     
      
      . 390 U.S. at 792, 88 S.Ct. at 1373. We note that in the Hugoton-Anadarko Area Rate Case, 466 F.2d 974 (9th Cir. 1972), there were no contingent escalations or “refund work-off” incentives.
     
      
      
        . See Pipeline Production Area Rate Case 42 FPC 738 (1969), aff’d sub. nom. City of Chicago v. FPC, supra note 31.
     
      
      . Permian, supra, 390 U.S. at 793-95, 88 S. Ct. 1344; FPC v. Hope Natural Gas Co., 320 U.S. 591, 628, 64 S.Ct. 281, 88 L.Ed. 333 (1944) (Jackson, J., concurring).
     
      
      . City of Lafayette, Louisiana v. FPC, 147 U.S.App.D.C. 98, 105, 454 F.2d 941, 948 (1971), affirmed sub. nom. Gulf States Utilities Co. v. FPC, 411 U.S. 747, 93 S.Ct. 1870, 36 L.Ed.2d 635 (1973). The Supreme Court assumed, and even the Commission admitted, in requiring consideration of anti-competitive practices of a utility issuing securities under § 204 of the Federal Power Act, 16 U.S.C. § 824c, that “allegations of anticompetitive conduct properly may be raised and fully considered in other proceedings related to . . . rates and rate-making practices under §§ 205 and 206, 16 U.S.C. §§ 824d and 824e. . . .’’At 757, 93 S.Ct. at 1877. This applied even though, in the same term, the Court decided that gas companies are not shielded from all antitrust liability because of FPC regulation. Otter Tail Power Co. v. United States, 410 U.S. 366, 93 S.Ct. 1022, 35 L.Ed.2d 359 (1973).
     
      
      . 15 U.S.C. § 717c.
     
      
      . This benefit is analogous to the “free-rider” problem in economic analysis where one not participating in the cost of a good, nonetheless derives a benefit. Indeed, the avoidance of “free riders” is a primary impetus for the patent system. See H. Demsetz, Toward A Theory of Property Rights, 57 Am. Econ.Rev. 347 (1967).
     
      
      . 45 FPC at 723.
     
      
      . 390 U.S. at 827, 88 S.Ct. 1344.
     
      
      . Atlantic Rfg. Co. v. Public Serv. Comm’n (CATCO), 360 U.S. 378, 388, 79 S.Ct. 1246, 3 L.Ed.2d 1312 (1959).
     
      
      . See Mesa Petroleum Co. v. FPC, 441 F.2d 182, 186-192 (5th Cir. 1971) ; Continental Oil Co. v. FPC, 378 F.2d 510 (5th Cir. 1967) ; Niagara Mohawk Power Corp. v. FPC, 126 U.S.App.D.C. 376, 379 F.2d 153 (1967) ; Public Serv. Comm’n of State of N. Y. v. FPC, 117 U.S.App.D.C. 287, 329 F.2d 242 (1964), cert. denied sub nom. Prado Oil and Gas Co. v. FPC, 377 U.S. 963, 84 S.Ct. 1644, 12 L.Ed.2d 735 (1964).
     
      
      . Continental Oil Co., supra, 378 F.2d at 522.
     
      
      . Mesa Petroleum, supra, 441 F.2d at 192.
     
      
      . Order 455 at 27 (mimeograph). Also on the horizon, if deregulation does not occur, or as an alternative, is the possibility of uniform rates for the nation as a whole, see Notice of Proposed Rulemaking (April 11, 1973), Docket No. 389B, 38 Fed.Reg. 10014 (April 23, 1973).
     
      
      . Lorain Journal Co. v. FCC, 122 U.S.App. D.C. 127, 133, 351 F.2d 824, 830 (1965). Whether present conditions of supply shortage require a new statutory framework, see S. Breyer and P. MacAvoy, The Natural Gas Shortage and the Regulation of National Gas Producers, 86 Harv.L.Rev. 941 (1973), is a concern for Congress.
     
      
      . Our remand to the FPC to reconsider the incentive provisions in light of Part VII of our opinion, will require that the agency’s record and reasons be supplemented on points relevant to the incentives, if the Commission decides to retain them, and on the inter-relationship with the effects of Order 455.
     
      
      . 45 FPO at 704.
     
      
      . Based on data from an earlier period.
     
      
      . See 701, 715 [of 45 PPC] for discussion of ranges for the separate components.
     
      
      . While an individual cost component might fall within the range indicated for it, it is improbable that either the high or low limit of every range would properly be cumulated to produce a total equal to the highest or lowest range of cost, so no total range may be derived upon which royalty or production taxes might be computed. Both royalty and production taxes are percentages of the total price of the gas.
     
      
      . The decision of Examiner Taylor is reported at 45 FPC 758 (1971).
     
      
      . 45 FPC at 693-695 (Commission) ; 45 FPC at780-782 (Examiner).
     
      
      . The approach of the Examiner did not altogether ignore the problem of deriving current cost estimates, since he found that the 1963 Census figure for drilling costs approximated the average for the 1958-1965 period. 45 FPC at 781.
     
      
      . See 45 FPC at 782.
     
      
      . 45 FPC at 697-699 (Commission), 801-835 (Examiner).
     
      
      . Neither the Commission nor Examiner adopted an alternative basis for calculating rate of return, the DCF (discounted cash flow) project accounting method, urged by producers. DCF discounts cash outflows and inflows to the present, to equate the present value of investments and benefits. The Examiner believed that the book value method adopted was “wholly compatible with those achieved by application of the more complex, though no more reliable, DCF project method.” 45 FPC at 808.
     
      
      .The derivation of the 4.24 and 6.86 figures are from the sum of the Examiner’s costs for production investment (Successful Well Costs + Lease Acquisitions + Other Production facilities) and the sum of the high side of the variable range of the Commission’s costs for production investment.
     
      
      . 45 EPC at 705.
     
      
      . 45 EPC at 793-94.
     
      
      . See Table at p. 1081 supra.
      
     
      
      . 45 EPC at 705.
     
      
      . Id.
      
     
      
      . See footnote c, Table at p. 1081, supra.
      
     
      
      . There is no direct translation from cost determinations to ceiling price. In the proceeding before the Examiner, his 16.42 cents per Mcf cost figure was adjusted to reflect certain additional costs associated with bringing gas up to pipeline quality. The Examiner, therefore, recommended a price of 17.4 cents for ungathered gas and 17.8 cents for gathered gas. 45 FPC at 867.
     
      
      . 45 FPC at 706.
     
      
      . Id.
      
     
      
      . 45 FPC at 865-868.
     
      
      . 45 FPC at 780.
     
      
      . 45 FPC at 873.
     
      
      . See text of opinion at note 5, supra.
      
     
      
      . 45 FPC at 707.
     
      
      . 45 FPC at 707.
     
      
      . See generally 45 FPC at 842-865 (Examiner’s discussion of flowing gas costs).
     
      
      . 45 FPC at 708.
     
      
      . These include provisions allowing credits on existing refund obligations and contingent escalations in the rates applied to flowing gas. See Opinion of Judge Leventhal, supra, at 1068ff.
     
      
      . The defects that Judge Leventhal rightly finds in those portions of the Commission’s order dealing with the system of incentives include both the lack of adequate justification relating the incentives to the objective of increased supply and the discrimination among producers and consumers that the incentives involve.
     
      
      . 45 F.P.C. 674, 705 (May 6, 1971) ; see Appendix, supra, at 1083.
     
      
      . Appendix, supra, at 1084. The Commission concluded:
      Our finding that 24 cents per Mcf is the just and reasonable rate for new gas is within the range or zone of reasonableness which we find to exist and our selection of this price represents our judgment as to the level necessary to elicit additional supplies from this area. We have taken into account the relationship of other pricing areas, because in setting rates for the future, we cannot limit our consideration to one area, and ignore the nationwide situation. We find that 24 cents is consistent with nationwide costs of new gas, and calculated to permit the interstate market to make some inroads into the' trend of gas sales to seek the intrastate market in the Texas Gulf and other competitive market areas, nationwide.
      45 F.P.C. at 705.
     
      
      . 45 F.P.C. at 707.
     
      
      . Appendix, supra, at 1086.
     
      
      . See City of Chicago v. FPC, 147 U.S.App. D.C. 312, 458 F.2d 731, 750-752 (1971) ; City of Detroit v. FPC, 97 U.S.App.D.C. 260, 230 F.2d 810 (1955), cert. denied, 352 U.S. 829, 77 S.Ct. 34, 1 L.Ed.2d 48 (1956).
     
      
      . Permian Basin Area Rate Cases, 390 U.S. 747, 767, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968) ; FPC v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 88 L.Ed. 333 (1944) ; FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 585, 62 S.Ct. 736, 86 L.Ed. 1037 (1942). See text and notes at notes 28-33, 44-45 infra.
      
     
      
      . Judge Leventhal declines to reach the adequacy of the Commission’s reasons in support of the upward adjustments in the base area rates on the ground that no such objection was presented in the applications for rehearing submitted to the Commission. Natural Gas Act § 19(b), 15 U.S.C. § 717r(b). We cannot agree. The problem we deal with here was specifically raised as to both the base area rates and the system of incentives, by both the Public Service Commission of the State of New York and by the producers. Referring to the requirements established by the Fifth Circuit in Southern Louisiana I (see text and notes at notes 55-56 infra), the Public Service Commission objected that:
      The Commission here has sought to discharge its responsibility by a few eonclusory statements to the effect that it doesn’t know what supply will be elicited at this price but believes that there will not be any enhancement of supplies with a lesser allowance (mimeo. p. 33). The Commission’s discussion is totally inadequate, failing to explain liow it arrived at its conclusion. Sympathetic though we are to the difficult responsibilities placed upon the Commission by the Fifth Circuit’s decision, the Commission cannot simply allow that a problem is complex and then ignore it. Of course, definite figures could not be given, but estimates giving the Commission’s best judgment of what it believes will be the result of its orders must be given and explained.
      Petition for Rehearing of the New York State Public Service Comm’n, Joint Appendix at 821. It is true, of course, that the Public Service Commission had satisfied itself, on the basis of its independent analysis of the problem, that the 24 cents rate for new gas-well gas is not too high; therefore, despite its objection to the Commission’s methodology and the lack of reasons for the Commission’s conclusions, the Public Service Commission has not contested the base rate portion of the order in its petition to this court.
      There can be no question, however, that the issue of the reasonableness of the base rates is before us in this case: a number of the producers have challenged the overall adequacy of the rates to meet the supply problem. E. g., Application of Humble Oil Co. et al. for Rehearing, Joint Appendix at 675-79. And a substratum of this challenge is that the Commission has failed to make a sufficient “assessment of the consequences of [its] order upon the industry and, most importantly, the industry’s probable conduct and performance as a result of the order . . . . ” Id. at 679-80. Moreover, in its separate application, one of the producers raised the precise question that concerns us here:
      In summary, it is apparent that the Commission has failed to explain the relationship between level of service, the demand for service and the price established. A reviewing court cannot satisfy itself from the Commission’s opinion that the “end-result” test has been met.
      Application of Mobil Oil Co. for Rehearing, .Toint Appendix at 770.
      We are confronted here with the producers’ contention that, even within the variable range of costs, the Commission’s choice of rate is too low, and that the upward adjustments it has made are unreasonable responses to the supply problem. We by no means conclude that the producers’ contention is correct. We do conclude, however, that in order to deal with the challenge to the Commission’s order in a responsible way, we must be supplied with the Commission’s reasons for doing what it lias done. The purpose of § 19(b)’s “urged ... in the application for rehearing” requirement is to ensure that the Commission has been afforded the opportunity to consider objections to its orders and to make whatever corrections it deems necessary before these objections are urged to the reviewing court — thus preserving the Commission’s primary jurisdiction. See City of Pittsburgh v. FPC, 99 U. S.App.D.C. 113, 237 F.2d 741, 749 (1956). We think that the Commission has been afforded this opportunity here. Furthermore, we think it necessary to recognize that the system of incentives and the schedule of base area rates are, as a practical matter, inextricably intertwined. The public interest can only be furthered by remanding both parts of the order to the Commission for reconsideration and for a reasonable explanation of their relationship to the supply problem and to each other.
     
      
      . 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968).
     
      
      . Id. at 790-792, 88 S.Ct. at 1372-1373.
     
      
      . 45 F.P.C. at 689. The Commission continued :
      We continue to hope for more precision, but for the purposes of our decision here, we can be no more precise than to say that although we cannot forecast the quantum of new supplies which will be elicited by our pricing determinations, we can state with some certainty that we do not believe that there will be any enhancement of supplies with any lesser allowance than we have decided upon.
      Id. at 703. So far as we can tell, however, the Commission nowhere states with any clarity the evidence or the reasoning from which this “certainty” is derived.
     
      
      . The obviousness, however, is somewhat superficial. The Commission itself seems to have recognized that increasing rates will not necessarily increase exploratory efforts and, hence, available supply. Nonetheless, it observed that “[t]he possible truth of this argument does not detract from the fact that failure to increase revenues will predictably result in no increase in exploratory effort.” 45 F.P.C. at 703-04. Furthermore, it seems possible, and perhaps likely, that an increase in interstate prices will simply lead to a corresponding increase in the competitive intrastate price — a price that, of course, the Commission is without jurisdiction to regulate. In short, unless there is reason to believe that the rates the Commission has set and the price in the intrastate market will be, at least for some time in the future, in equilibrium, then we can see no reason for supposing that these rates will be adequate to bid supply away from the intrastate market. In fact, they may merely contribute to an upward price spiral, forcing consumers to pay more, while not diminishing the supply problem. Gf. Kitch, The Permian Basin Area Rate Cases and the Regulatory Determination of Price, 116 U.Pa.L.Rev. 191, 206-207 (1967). We can see no basis in the Commission’s report for concluding that such a reason exists; on the contrary, the Commission has said that the trend of intrastate prices is upward. 45 F.P.C. at 706.
     
      
      . See Note, FPC Regulation of Independent Producers of Natural Gas, 75 Ilarv.L.Rev. 54Í) (1902).
     
      
      . Hearing Before a Subcomm. of the House Comm, on Interstate and Foreign Commerce, on II.R. 11662 to Regulate the Transportation and Sale of Natural Gas in Interstate Commerce and for Other Purposes, 74th Cong., 1st Sess. 10-12, 48-52 (1936).
     
      
      . By 1936, four holding company groups controlled more than 55 percent of the total pipeline mileage in the nation. Id. at 12, 49. The use of holding companies to control companies that sold to one another along the chain of distribution placed the states in the position of attempting to determine the reasonableness of prices not reached at arms’ length. Attempts to inquire into out-of-state pipeline companies’ rates were frustrated first by the obstinance of the companies, see Hearings Before the House Comm, on Interstate and Foreign Commerce, on II. R. 400S to Regulate the Transportation and Sale of Natural Gas in Interstate Commerce and for Other Purposes, 75th Cong-., 1st Sess. 93 (1937), 1936 Hearings, supra, at 93, 87-89; later by the costs of conducting investigations, 1937 Hearings, supra, at 50; and finally by Supreme Court decisions holding that such assertion of regulatory power went beyond the limitations placed on the authority of the states by the Interstate Commerce Clause, e. fir., Peoples Natural Gas Co. v. Public Service Comm’n of Penna., 270 U.S. 550, 46 S.Ct. 371, 70 L.Ed. 726 (1926).
     
      
      . 1937 Hearings, supra, at 90 ff.
     
      
      . 1937 Hearings, supra, at 47, S9-91, 101-103 ; 1936 Hearings, supra, at 17.
     
      
      . 1937 Hearings, supra, at 70-73; 1936 Hearings, supra, at 62.
     
      
      . Compare 49 U.S.C. §§ 1 et seq.
     
      
      . E. g., 1937 Hearings, supra, at 84-87.
     
      
      . See, e. fir., Kitch, Regulation of the Field Market for Natural Gas by the Federal Power Commission, 11 J. of Law and Econ. 243, 248-57 (1968) ; Note, Legislative History of the Natural Gas Act, 44 Geo.L.J. 695 (1956).
     
      
      . Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1954).
     
      
      . 390 U.S. at 756, 88 S.Ct. at 1354.
     
      
      . 15 U.S.C. § 717r(b).
     
      
      . 15 U.S.C. § 717c(a).
     
      
      . 15 U.S.C. § 717cl(a).
     
      
      . 315 U.S. 575, 62 S.Ct. 736, 86 L.Ed. 1037 (1942).
     
      
      . Id. at 585, 62 S.Ct. at 743.
     
      
      . 320 U.S. 591, 64 S.Ct. 281, 88 L.Ed. 333 (1944).
     
      
      . See Kitch, supra note 13, at 203.
     
      
      . 320 U.S. at 602, 64 S.Ct. at 287.
     
      
      . Id. at 603, 64 S.Ct. at 288.
     
      
      . See Kitch, supra note 13, at 202.
     
      
      . 320 U.S. at 647, 64 S.Ct. at 309.
     
      
      . Id. at 629, 64 S.Ct. at 300.
     
      
      . Id. at 647, 64 S.Ct. at 309.
     
      
      . Id. at 652-653, 64 S.Ct. at 311, see Colorado Interstate Gas Co. v. ETC, 324 U.S. 581, 612, 65 S.Ct. 829, 89 L.Ed. 1206 (1945) (Jackson, J., concurring).
     
      
      . Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1954).
     
      
      . See Permian Basin, 390 U.S. at 756-757, 88 S.Ct. 1344; Breyer and MacAvoy, The Natural Gas Shortage and the Regulation of Natural Gas Producers, 86 Harv.L.Rev. 941, 952-58 (1973).
     
      
      . Wisconsin v. FPC, 373 U.S. 294, 83 S.Ct. 1266, 10 L.Ed.2d 357 (1963).
     
      
      . Phillips Petroleum Co., 24 F.P.C. 537, 547 (1960).
     
      
      . See Kitch, supra note 13, at 191-92.
     
      
      . 390 U.S. at 797, 88 S.Ct. at 1376.
     
      
      . The Court said :
      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.”
      
        Id. at 791, 88 S.Ct. at 1372; and it continued :
      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 interest 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.
      
        Id. at 815, 88 S.Ct. at 1385.
     
      
      . Id. at 799-800, 88 S.Ct. 1344.
     
      
      . Id. at 791-792, 88 S.Ct. at 1373.
     
      
      . Id. at 790, 88 S.Ct. 1344.
     
      
      . Id. at 792, 88 S.Ct. at 1373.
     
      
      . See Breyer and MacAvoy, supra note 40, at 962-63.
     
      
      . 390 U.S. at 816 n. 99, 88 S.Ct. 1344.
     
      
      . See Kitch, supra note 13, at 195-96.
     
      
      . See Breyer and MacAvoy, supra note 40, at 960-61.
     
      
      . Austral Oil Co. v. FPC, 428 F.2d 407, rehearing en banc, 444 F.2d 125 (5th Cir.), cert. denied, 400 U.S. 950, 91 S.Ct. 241, 27 L.Ed.2d 257 (1970).
     
      
      . 428 F.2d at 426 n. 46.
     
      
      . Id.
      
     
      
      . Placid Oil Co. v. FPC, 483 F.2d 880 (5th Cir. 1973).
     
      
      . Id. at 889.
     
      
      . Id. at 894.
     
      
      . Id. at 895 n. 13. See also Hugoton-Anadarko Area Rate Proceeding, California v. FPC, 466 F.2d 974 (9th Cir. 1972).
     
      
      . Shell Oil Co. et al v. FPC, 484 F.2d 469 (5th Cir. 1973).
     
      
      . Id. at 475. Indeed, the Commission had included in its Other Southwest report a statement concerning this relationship that is substantially similar to that which it included in its report in this case. Compare id. at 475 with text at note 8 supra.
     
      
      . Id. at 478.
     
      
      . 347 U.S. at 685, 74 S.Ct. at 800.
     
      
      . 155 U.S.App.D.C. 411, 478 F.2d 615 (1973) (Bazelon, C. J., concurring in the result) .
     
      
      . Id. 478 F.2d at 651.
     
      
      . See K. C. Davis, 2 Ad.Law Treatise 476-84 (1958).
     
      
      . See Breyer and MacAvoy, supra note 40; Kitch, supra note 22.
     
      
      . Testimony of former FPC Chairman Joseph C. Swidler, reported in the Washington Post, June 27, 1973, at 7, col. 1. See Douglas, The Case for the Consumer of Natural Gas, 44 Geo.L.J. 566, 589 (1955) ; “Is the Natural Gas Industry Competitive?”, N.Y. Times, July 1, 1973, see. F, at 2, col. 1. We note also recent reports that the reserves of natural gas held by producers may be much larger than had previously been thought. See the Washington Post, June 29, 1973, at 1 (describing a Federal Trade Commission Report to a Senate Antitrust Subcommittee).
     
      
      . 45 FPC at 857.
     