
    CITY OF CHICAGO, ILLINOIS, et al., Petitioners, v. FEDERAL POWER COMMISSION, Respondent, Pipeline Production Group et al., Intervenors.
    No. 23740.
    United States Court of Appeals, District of Columbia Circuit.
    Argued Nov. 2, 1970.
    Decided Dec. 2, 1971.
    Certiorari Denied April 17, 1972.
    See 92 S.Ct. 1495.
    
      Mr. Charles F. Wheatley, Jr., Washington, D. C., with whom Messrs. George E. Morrow, Memphis, Tenn. and Reuben Goldberg, Washington, D. C., were on the brief, for petitioners.
    Mr. Peter H. Schiff, Solicitor, Federal Power Commission, at the time of oral argument, with whom Messrs. Gordon Gooch, Gen. Counsel, Abraham R. Spalter, Asst. Gen. Counsel, and Joseph J. Klove-korn, Atty., Federal Power Commission, were on the brief, for respondent.
    Mr. Raymond N. Shibley, Washington, D. C., with whom Messrs. James J. Flood, Jr., and Wm. Warfield Ross, Houston, Tex., were on the brief, for intervenor, Pipeline Production Group.
    Messrs. J. C. Ohrt and William B. Cassin, Houston, Tex., were on the brief for intervenor, Pennzoil Producing Co.
    Mr. Melvin Richter, Washington, D. C., was on the brief for intervenor, Tennessee Gas Pipeline Co. Mr. Harold L. Talisman, Washington, D. C., also entered an appearance for intervenor, Tennessee Gas Pipeline Co.
    Mr. Norman A. Flaningam, was on the brief for intervenors, Consolidated Gas Supply Corporation et al.
    Messrs. John E. Watson, and Barclay D. McMillen, were on the brief for in-tervenor, Tenneco Oil Co.
    Messrs. John T. Ketcham, and Vernon W. Woods, Shreveport, La., entered appearances for intervenor, Mid Louisiana Gas Co.
    Before MacKINNON, ROBB and WILKEY, Circuit Judges.
   MacKINNON, Circuit Judge:

This case is before us on a petition under Section 19(b) of the Natural Gas Act to review a decision issued by the Federal Power Commission on October 7, 1969 directing that gas produced by natural gas pipeline companies from leases acquired after October 7, 1969 and which is used on-system should be valued for ratemaking purposes at the area rate applicable to independent producers. For reasons to be discussed below, we affirm the Commission’s decision with two reservations.

I.

Background

In order to place the instant controversy in its proper perspective, a brief discussion of the FPC’s recent regulatory effort with respect to natural gas is necessary. Three sections of the Natural Gas Act give the Commission its primary tools for regulating natural gas rates. Under Section 7(e), a producer of natural gas must obtain from the Commission a certificate of convenience and necessity before it can make sales in interstate commerce. In the so-called CATCO case, the Supreme Court held that before such certificates are issued, the Commission must insure that the rates to be charged by the producer are “in line” with those being charged for gas sold by other producers and extracted from the same general area. The Commission thus has some measure of responsibility for the initial prices a producer sets for his gas. When price increases are effected, the second of the Commission’s three major tools comes into play. Under Section 4(e) of the Act, the Commission has the power to suspend any proposed rate increases for a maximum of five months while it conducts an investigation to determine whether the proposed rates will be “just and reasonable”. If five months elapse before the investigation is completed, the new rate goes into effect, but the producer must post a bond conditioned upon refunds being made in case the increase is held unlawful and a refund is ordered by the Commission. Finally, under Section 5(a), the Commission may at any time commence an investigation into whether a given rate is “just and reasonable.” If it finds that the rate does not meet this standard, it may fix an appropriate rate for the future, but Section 5(a) dobs not'empower the Commission to order refunds.

The Natural Gas Act became law in 1938 and was initially applied by the Commission only to pipeline companies, i. e., those companies which were engaged in the interstate transmission of natural gas. While the methods used by the Commission to determine which rates were just and reasonable underwent some changes over the years, the concept that rates should be based on each individual company’s “cost of service” remained at the heart of the regulatory scheme.

[I]n essence [cost of service] includes, in addition to operating costs, depreciation, etc., the “return” to the company which the Commission calculates by providing a fair rate of return on a rate base equal to the amount prudently invested in utility property, and the “expense” of Federal income tax payable on the allowed return.

In 1954, however, in the case of Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1954), the Supreme Court held that the Natural Gas Act applied to all independent producers of natural gas who made sales in interstate commerce. This was the first application of the regulatory features of the Act to independent producers. The effect of this decision on the Commission’s regulatory effort was both immediate and spectacular, for Phillips, in effect, recognized that 3000 additional companies were under the Act. The practice of making independent cost-of-service calculations for each of these companies rapidly proved to be so time-consuming that for a while it appeared that the regulatory process itself would be brought to a halt.

In addition to the length of time required for the necessary calculations, rates based on individual company cost of service exhibited certain other deficiencies. First of all, largely speculative cost allocations made the rates obtained somewhat unrealistic. Secondly, because oil and gas wells were typically the product of joint ventures in which several independent producers had an interest, rates based on individual company cost-of-service resulted in great anomalies in the prices paid to producers for gas by both pipeline companies and consumers. Finally, unlike the case with the “traditional” public utilities, there was little relationship between an individual producer’s expenditures and his income, for luck is an important factor in the discovery of gas as a result of any particular exploratory effort. Together, the above factors made questionable the wisdom of attempts to regulate the natural gas industry on the traditional basis of cost of service in a test year.

Recognizing the above deficiencies and spurred by the increasingly large administrative burden with which it was faced, the Commission announced in a statement in 1960 that in the future all natural gas produced and sold by independent producers would be priced at the just and reasonable “area rate”. It divided the country into twenty-three geographic areas and set initial or “guideline” prices for all gas produced from wells within each of the areas. Full hearings were to be held to determine the just and reasonable rate for each area and the guideline prices were to be used until such determinations were made.

In the Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968), the Supreme Court reviewed the Commission’s first area rate determination, giving approval to both the area rate method of regulation and the prices which had been set. As developed in the Permian proceeding, an area rate is essentially a rate predicated on a composite rather than an individual cost-of-service. Cost data are gathered from all producers engaged in natural gas production in a given area and weighted average costs plus an appropriate rate of return are used to derive a price for gas produced in that area and sold in interstate commerce. In addition to alleviating many of the problems associated with individual company cost of service, area rates were designed to spur the search for new deposits of natural gas. To this end, higher rates were allowed for “new” gas than were allowed for “old” or “flowing” gas.

In the Permian case, and in the Southern Louisiana Area Rate Cases which followed, area rates were applied only to gas produced and sold in interstate commerce by independent producers. Pipeline companies which produced gas and used it on-system were not permitted to value such gas for rate making purposes at the area rates. Instead, the expenses incurred in production were included in the pipeline company’s cost of service, along with the expenses incurred in obtaining the compression, transmission and other facilities needed for transporting the gas to market.

The instant proceeding began as a part of the Hugoton-Anadarko Area Rate Proceeding when the Commission issued an order enlarging the issues in that proceeding to include the question of whether on-system gas produced by a pipeline company or its affiliate should be valued for ratemaking purposes on an area rate basis. This issue was included in the Hugoton-Anadarko proceeding because the Commission believed that the area was one of considerable pipeline production activity and that the proceeding would thus be an “appropriate vehicle” for examination of the issue. It soon became apparent, however, that pipeline production in the Hugoton-Anadarko area was not typical of pipeline production throughout the United States. Accordingly, on motion of the Commission’s staff, the pipeline question was severed from the proceeding, and a new inquiry, divided in two phases, was instituted. The precise issue presented in Phase I, the only phase presently before us, was articulated by the Commission:

What is the most appropriate pricing method to be applied to natural gas utilized in a pipeline’s interstate system which is produced by the pipeline or its affiliated producing company from leases acquired after the date of determination of this issue.

Thirty-seven pipeline companies, all those involved in the production of natural gas in more than an “incidental” way, were made respondents, and several pipeline affiliates were added at a later date.

Following extensive hearings, the examiner issued his initial opinion holding that full application of area rates to pipeline production was not warranted at the present time. He found that

the present regulatory method of cost-of-service for gas produced by pipelines and of area rates for gas produced by independent producers causes a disequilibrium in rates for future reserves of jurisdictional gas.

He also found that

[t]he advent of area rates for independent producers which is to eventually encompass most of the Continental United States is creating diverse economic and competitive factors which will influence the supply and demand of new jurisdictional gas .... [making] it very difficult to maintain the rigid cost-of-service regulation indefinitely.

Nevertheless, he concluded that

a gas rate increase must not be brought about prematurely. The record . . . contains evidence to warrant only an interim balancing of equities, rate changes of only minor proportions.

The Examiner therefore attempted to strike a balance which he felt would protect the public interest but which fell short of applying area rates to pipeline production. Essentially, however, his decision represented an intermediate step in the transition from cost-of-service regulation to area rates, a transition which he thought would be necessary at some time in the future.

The Commission disagreed with the examiner and decided that now was an appropriate time to make the change. It found that most of the anomalies resulting from cost-of-service pricing of gas sold by independent producers also resulted from use of this method to value gas produced by pipeline companies. It also found that pipeline-owned reserves of natural gas were declining at a time when there were substantial indications of an impending gas shortage, and concluded that, to the extent an increased stimulus was needed to spur the search for new deposits of natural gas, both independent producers and pipeline companies should be stimulated alike. Finally, the Commission concluded that utilization of an area pricing concept was the only way to stimulate gas production by pipeline companies and at the same time to protect consumers from bearing the full cost of unsuccessful or inefficient exploratory efforts. Accordingly, it promulgated a rule providing that gas produced by pipeline companies from leases acquired after October 7, 1969 would be valued for rate-making purposes at the same area rate applicable to independent producers in the area within which the lease was located.

Following a denial by the Commission of a motion for rehearing, petitioner filed the instant petition for review in support of which it advanced four main arguments: (1) The Commission improperly relied on evidence not contained in the record in reaching its decision; (2) the Commission, in light of the record before it, improperly abandoned cost-of-service valuation of gas produced by pipeline companies; (3) assuming area rates were appropriate for regulation of pipelines, the Commission erred in allowing such companies the same rate of return it allowed independent producers; and (4) the Commission did not give proper recognition to certain facets of the law applicable to income tax benefits.

II

Jurisdiction and Scope of Review

Before turning to the merits of petitioner’s specific contentions, it is important to discuss briefly our jurisdiction and scope of review. This discussion is particularly in order because the parties are not in agreement as to the nature of the proceeding which led to the order presently before us. Petitioner claims that the proceeding was intended by the Commission, and understood by the parties, to be an “adjudicatory” one but that the Commission impermissibly changed it to a rule-making proceeding at the last minute. The Commission and inter-venors, on the other hand, claim that the proceeding was intended as, and understood to be, a “rule-making” proceeding from the outset. From the premises thus advanced, both groups would have us draw certain allegedly inevitable conclusions.

In many cases, it is unnecessary, and even unwise, to classify a given proceeding as either adjudicatory or rule-making. The line between the two is frequently a thin one and resolution of a given problem will rarely turn wholly on whether the proceeding is placed in one category or the other. Moreover, obsession with attempts to place agency action in the proper category may often obscure the real issue which divides the parties and requires our resolution.

The instant case is an example of the potential for confusion that may be caused by attempts at classification. It is quite clear to us that we are not faced with a borderline case and that the instant proceeding was both intended by the Commission to be and was conducted as a rule-making proceeding from the date it was severed from the Hugoton-Anadarko proceedings. As required by the Administrative Procedure Act; notice of the proceedings was published in the Federal Register. Comments were invited from interested parties and the issue before the Commission was succinctly described. That issue involved the most appropriate method for valuing much of the gas produced by all pipeline companies in the future, the type of broad issue which particularly lends itself to rule-making proceedings. The regulation, as adopted by the Commission, was published in the Federal Register. From all indications, then, the proceeding fits into the category of rule-making, as even petitioner itself recognized in early arguments addressed to the Commission.

Having determined that what we have before us is quite clearly a rule, it might appear that we have no jurisdiction to review the Commission’s action at this point. Section 19(b) of the Natural Gas Act gives this court jurisdiction to review “orders” issued by the Commission in proceedings under the Act. In United Gas Pipe Line Co. v. F. P. C., 86 U.S.App.D.C. 314, 181 F.2d 796, cert. denied, 340 U.S. 827, 71 S.Ct. 63, 95 L.Ed. 607 (1950), the court held that not all “orders” issued by the Commission were reviewable under Section 19(b). Faced there with a rule promulgated after non-evidentiary proceedings held in accordance with Section 4 of the Administrative Procedure Act, the court pointed to the wording of Section 19(b) and concluded that

[o]n its face, the Act contemplates review of a decision based on evidence presented in a quasi-judicial proceeding before the Commission.

It then went on to hold that since it had before it “a rule directed to all companies similarly situated” and since it had “the Commission’s binding assurance that the regulations will operate only prospectively . . there is at the very least a strong presumption that the Commission has merely promulgated regulations of general applicability and not orders reviewable under Section 19(b).”

Though the sentence last quoted might give rise to a contrary impression, the decision in United Gas Pipe Line did not turn on the fact that the Commission had promulgated a rule rather than an order following an adjudicatory hearing. The determining factor was the absence of an evidentiary record which would allow meaningful review. The heavy weight placed on this factor is manifested both by the manner in which the court discussed Section 19(b) and by its suggestion that if petitioners were harmed by the rule itself, they could seek relief in the District Court where an appropriate record could be compiled. The Court’s primary concern, then, was not with whether the order could be reviewed but with where.

Whatever the continuing vitality of the United Gas Pipe Line case in situations where no evidentiary record has been compiled, it does not control here, for we do have before us a full and complete evidentiary record of extensive hearings before the Commission. When the Commission’s action is otherwise sufficiently “final”, United Gas PipeLine does not preclude our review under Section 19(b) when we are presented with such a record, whether the proceedings were adjudicatory or rule-making.

The next question which arises concerns our scope of review. Here again the conclusion that we have a rule before us is likely to engender some confusion. There is some support for the proposition that the scope of judicial review of rules is much narrower than is the scope of review of an order stemming from an adjudicatory proceeding. One ease which contains a clear expression of this view is Superior Oil Co. v. F.P.C., 322 F.2d 601 (9th Cir. 1963), cert. denied, 377 U.S. 922, 84 S.Ct. 1219, 12 L.Ed.2d 215 (1964). In that case, Superior sought review of an order denying, without a hearing, its application for an amendment to its certificate of public convenience and necessity. The Commission’s asserted basis for the denial was a regulation it had issued sometime previously, without an evidentiary hearing, which prohibited certain pricing provisions in contracts for the sale of natural gas. Superior advanced two arguments in support of its petition for review: (1) that the Commission had no authority to reject its petition for an amendment to its certificate without a hearing and (2) that the Commission’s promulgation of the regulation was arbitrary and capricious.

The court held that, if the regulation were valid, the Commission was not required to give Superior a hearing before rejecting its petition. It then held that the regulation was not arbitrary and capricious, but in so doing, prescribed for itself a severely limited scope of review:

. . . In determining the propriety of rules of general application, only a legal question is presented — whether on the factual premise upon which the Commission acted, the rule promulgated is unreasonable, arbitrary, capricious or discriminatory. If the factual premise itself were open to review, then it would be necessary for all general rule-making to include a trial-like hearing.

Other cases have seemed to prescribe a similar scope of review. From these, it would follow that the scope of our review would turn on whether the instant order prescribed a rule of general applicability — which it does — or, at the very least, on whether an evidentiary hearing was required before it could be promulgated. Faced with a general rule, or a rule which required no evidentiary hearing before its promulgation, we would simply accept as true the premises asserted by the Commission as the basis for its action and then seek to determine whether the action bore some rational relationship to the regulatory objectives of the Natural Gas Act.

We decline to follow this course for several reasons. In the first place, review would be a relatively futile exercise in formalism if no inquiry were permissible into the existence or nonexistence of the condition which the Commission advances as the predicate for its regulatory action. A regulation perfectly reasonable and appropriate in the face of a given problem may be highly capricious if that problem does not exist. Secondly, rule-making is frequently spoken of as a “quasi-legislative” function. While this is an accurate description, it means that, although the process leading to the promulgation of a rule frequently resembles the legislative process and although a rule frequently has an impact similar to that of a statute, rule-making is not fully equivalent to the action of the legislature. Clearly, rule-making is the action of a body subordinate to the legislature. That the same deference accorded “findings” of the legislature is not to be given the findings of the Commission is implicit in the law governing legislative delegation of authority. Were “findings” of the Commission in a rule-making proceeding automatically exempt from judicial review, the law governing delegation would also become little more than formalistic mutterings, for it makes little sense to require that the legislature articulate intelligible standards to govern agency action if realistic inquiry into whether those standards are being followed were foreclosed. Thirdly, the Commission has broad discretion to seek a given objective either through ad hoc adjudicatory proceedings or through rule-making. To argue that, if the latter route is followed, judicial inquiry into the factual basis for the agency’s action is impermissible, is to say that in large measure the agency itself has the discretion to determine whether its action will be subject to meaningful review.

We conclude, then, that some inquiry into the factual predicate for rules promulgated by the Commission is required when review of those rules is sought here. We further conclude that the nature of that inquiry depends not on whether the Commission has issued a rule or an adjudicatory order, but on the nature of the record presented to us for review.

As we mentioned at the outset, Sections 4, 5 and 7 of the Natural Gas Act provide the Commission with its primary tools for regulating the natural gas industry. All three sections contemplate action by the Commission after an eviden-tiary hearing primarily involving specific rates, charges or facilities. Section 16 of the Act, however, confers on the Commission broad power to “prescribe, issue, make, amend, and rescind such orders, rules, and regulations as it may find necessary or appropriate to carry out the provisions of” the Act, and many of the same regulatory objectives which can be attained through ad hoc proceedings under Sections 4, 5 and 7 can also be attained through the issuance of general rules under Section 16. As in the case of many similar statutes, the procedures to be used in exercising the powers contained in Section 16 are not mentioned in the Act. The Administrative Procedure Act, however, does contain the appropriate procedures. In particular, Section 4 (5 U.S.C. § 553) contains the minimum requirements which the Commission must meet before exercising its power under Section 16 of the Natural Gas Act. Section 4, inter alia and with certain exceptions not here relevant, provides for notice of the issues with which the Commission intends to deal and for participation by interested persons in the proceedings leading to promulgation of the rule. Standing alone, Section 4 only requires that interested persons be given an opportunity to participate “through submission of written data, views, or arguments with or without opportunity for oral presentation.”

As stated, however, Section 4 prescribes only the minimum procedural requirements for the Commission’s exercise of power under Section 16. If it so chooses, the Commission may conduct, as it did here, a full evidentiary hearing of the type contemplated by Sections 7 and 8 of the Administrative Procedure Act, or may use any variant of such procedures. Whatever procedure is utilized, a primary objective is the acquisition of information which will enable the Commission to carry out effectively the provisions of the Natural Gas Act. The ability to choose with relative freedom the procedure it will use to acquire relevant information gives the Commission power to realistically tailor the proceedings to fit the issues before it, the information it needs to illuminate those issues and the manner of presentation which, in its judgment, will bring before it the relevant information in the most efficient manner.

Thus while an important purpose of all proceedings before the Commission is the acquisition of information, it is quite obvious that the form the acquired information assumes may be vastly different depending on the procedures used by the Commission to gather it. The record in a Section 4 proceeding ordinarily will contain more generalized than specific information, may not contain information tested by cross-examination and will frequently contain much conclusory information based on data gathered by the interested parties. For this reason, application of the substantial evidence test, defined and conceptualized as it frequently is in terms of whether or not a directed verdict should be granted in a jury trial, to findings resulting from a Section 4 proceeding would be of scant utility. Juries are not often, if ever, called upon to deal with the kinds of generalized factual data which parties in a Section 4 proceeding present to a Commission which over the years has accumulated great quantities of information and acquired a recognized expertise upon the subject.

It does not follow, however, that review of an evidentiary record of proceedings before the Commission should be fundamentally distinguishable in objective from review of the record in proceedings where evidentiary hearings have not been held, for the availability of alternative routes to the same destination requires that all be charted with similar precision. Even in the absence of an evidentiary hearing, the reviewing court? must canvass the “whole record” com-j piled before the Commission. Its inquiry into the factual predicate for the action is to be “searching and careful”, though, as in all cases, the court cannot substitute its judgment for the Commission’s. In sum, review of a non-evidentiary record must be “thorough, probing, [and] in depth.”

Application of no simple formula can avoid the process of judgment. In every case, the object of review is to determine whether a reasoned conclusion from the record as a whole could support the premise on which the Commission’s action rests. The substantial evidence test is essentially an application of this general principle to a particular kind of record, but, in all cases, reasoned conclusions are the hallmark of regularity.

The foregoing makes it unnecessary for us to determine whether an evidentiary hearing was required in this case, for the scope of our review does not turn on the answer to that question. Once we have satisfied ourselves that the minimum procedural requirements have been met by the Commission, our “searching and careful” review of its action must take full account of the record actually compiled before that body. When we have determined that the factual predicate for the Commission’s action could be a reasoned conclusion from the record as a whole, that the factual predicate is one with which the Natural Gas Act permits the Commission to be concerned and that the Commission’s action on that predicate is within its statutory authority, our function is at end. With these principles in mind, we turn to the specific arguments advanced by petitioner.

Ill

Reliance on Extra-Record Information

Petitioner’s first argument is that the Commission impermissibly relied on evidence not contained in the record in order to reach its decision. Specifically, petitioner claims that there was no evidence in the record to support the Commission’s conclusion that a natural gas “shortage” was impending. It further claims, as was mentioned above, that the proceeding was “adjudicatory” and that the Commission was required to base its decision only on data contained in the record. From these two propositions, petitioner contends that the Commission’s order is invalid.

The Commission referred to the gas supply situation at two points in its discussion. At the outset, it said that its decision in this case marked

a turning point in the regulation of pipelines owning their own reserves, but it follows closely upon the development of area regulation for independent producers and a changing picture in the gas supply situation as shown by the record and other facts coming to our attention. In light of an apparent gas shortage we are concerned whether the pipelines will make an increased effort to explore for and develop new gas reserves. We are also concerned whether new gas supplies will be available to the consumers of gas served by the long pipelines. To attain these ends it may be incumbent upon us to modify traditional approaches to regulation with respect to pipeline production in order to provide a regulatory climate conducive to an aggressive pipeline exploration program.

After discussing other factors which led it to conclude that area rates should be applied to pipeline production, the Commission again adverted to the gas supply situation:

We arrive at this conclusion at a time when there are indications of a shortage of gas and a threat of a greater shortage in the future. For instance, for the first time the American Gas Association reported that in 1968 net gas production exceeded the reserves added resulting in a decline in total proved reserves from 292.9 trillion cubic feet to 287.3 trillion cubic feet by the end of 1968.8
8. AGA Committee on Annual Gas Reserves; Report issued April 7, 1969.
While the 1968 figures are not in the record, the present trend is reflected by the record. Preeminent are the reserve-production ratios showing the ratios of reserves to production during the year. This ratio, for the United States, with some slight ups and downs, has trended downward from 22.1 in 1955 to 14.8 in 1968.’ Of course, the reserves owned by pipeline producers are only a portion of the whole but pipeline production has not been progressing satisfactorily. In fact, the owned reserves of pipeline producers have declined 29.9 percent between 1958 and 1966, and, as a percentage of total reserves, have declined from 25 percent in 1958 to 13 percent in 1966. In spite of this trend, as argued by the Pipeline Production Group and other parties, the pipeline producers are capable of making a significant contribution to new gas supplies.

From these remarks, it is apparent that the Commission did refer to some statistical material outside the record, although the precise nature of the material to which it referred is not clear.

It by no means follows, though, that what the Commission has done is impermissible. We have already rejected the notion advanced by petitioner that the instant proceeding was an adjudicatory one, a notion which constitutes the major premise in its syllogism. In light of what we have said above, however, we decline to deal with this issue solely in terms of a dichotomy between rule-making and adjudication. In our view, the Commission’s use of extra-record statistical data did not in any way unfairly deprive petitioner of any substantial right.

In the first place, there is in the record information concerning the steady decline in the overall reserve-production ratio as well as the decline both relative and absolute in reserves of natural gas owned by pipeline companies. The significance of these data, of course, is not self-evident. Petitioner, for example, argues that movement of the reserve-production ratio is of little aid in predicting anything, while the Commission attaches somewhat more significance to it. Recently, the Commission’s staff completed a study which indicates that the ratio is a useful, if somewhat rough, measure of the adequacy of gas supplies.

Interpretation of, and assignment of weight to, data such as these is a task which particularly calls for expert judgment. In interpreting such data and in making predictions based on them, the Commission must be expected to make use of the experience it has gained through years of dealing with the problem of the supply of natural gas. Frequently, statistics, scientific reports and studies will be amenable to various interpretations and effective regulation requires that the Commission bring to bear the full range of its knowledge, garnered from whatever source, in making the interpretation on which it bases important policy decisions.

As we read the Commission’s discussion, the extra-record material on which it relied was used chiefly to give some meaning to data concerning the supply situation which was contained in the record. In our view, this was not only permissible, but was action fully necessary to enable the Commission to carry out its statutory role.

In the second place, the question of whether existing gas supplies are adequate is not a novel one. As petitioner itself points out, the issue has been raised in numerous rate proceedings over the past fifteen years. To the extent that the two-price approach to area rates utilized in the Permian case is designed to stimulate the search for natural gas, the question of the adequacy of present supplies is necessarily involved in every proceeding which deals with area rates. Many issues which the parties agreed to explore in the instant proceeding implicitly involved the adequacy of existing supplies of gas. The issue thus was clearly present in the case and petitioner was not deprived of the opportunity to present relevant information by lack of notice that the issue was there.

Finally, it must be remembered that the sole issue here involves the proper method to be followed in placing a value for rate-making purposes on much of the new gas to be produced by pipeline companies. The actual value permissible for such gas will be determined by future rate proceedings for individual producing areas. In the context of these future proceedings, petitioner and others will have an opportunity to explore in some detail the extent of the anticipated gas shortage as well as the precise amount of incentive needed to combat it. The order currently before us represents only the Commission’s determination that, to the extent a gas shortage is threatened, increased exploration and production will be needed from both independent producers and pipeline companies alike, and that the area rate concept is the most efficient method of stimulating such increases and at the same time protecting consumers from bearing the full cost of some unsuccessful exploratory efforts. Thus, the precise magnitude of the possible gas shortage was not fully explored, was not necessary to determine before the Commission reached its decision and both can and should be examined by parties to future area rate proceedings. For the above reasons, we conclude that petitioner’s claim that the Commission erred in referring to data not contained in the record is without merit.

IV

Departure from Cost of Service Pricing

Petitioner’s next argument is that “on this record existing legal standards compel the continuance of cost-of-service regulation of the [on-system] gas produced by interstate pipeline companies or acquired from their affiliates.” Though petitioner spends much time discussing the decisions of various courts which have held that individual cost-of-service regulation is appropriate, we do not understand the main thrust of the argument to be that employment of this method of regulation is compelled either by the Natural Gas Act or by the Constitution. Rather, the argument is that the decision of this court in City of Detroit v. P.P.C., 97 U.S.App.D.C. 260, 230 F.2d 810 (1955), cert. denied, Panhandle Eastern Pipeline Co. v. City of Detroit, 352 U.S. 829, 77 S.Ct. 34,1 L.Ed.2d 48 (1956), places a heavy burden on the Commission to justify its departure from individual cost-of-service regulation, a burden which it has not met in this case.

In the City of Detroit case, this court reviewed an order issued by the FPC following an investigation into the lawfulness of rates charged by Panhandle Eastern Pipeline Company. Insofar as its action is here relevant, the Commission held that gas produced by Panhandle and used on-system would be valued for rate-making purposes at its “field price” instead of through the cost of service method. The effect of this determination was twofold: (1) It substituted the forces of the market for producer costs as the basis on which the “justness” and “reasonableness” of given rates would be determined and (2) it raised the price being charged for gas by Panhandle 1.3 cents per Mcf over what it would have been under cost-of-service regulation. The Commission justified its departure from the traditional method of regulation on several grounds, among them that the old method did not sufficiently encourage the discovery and development of natural gas by pipeline companies.

This court reversed. After mentioning that “the primary aim of the [Natural Gas] Act ... is ‘to protect consumers against exploitation at the hands of natural gas companies’ ”, the court said:

The [increase] here allowed is not brought into relationship by the evidence and findings with the purposes for which it is granted except that it affords a larger revenue to Panhandle than otherwise it would have. This is not an adequate basis for bringing the resulting rates within the “just and reasonable” standards of the Act. . . When the [field price] method is used the evidence and findings must show that the increase in rates thus caused is no more than is reasonably necessary for the purposes advanced for any increase.

Petitioner contends that the Commission has not made the showing required by the emphasized language from City of Detroit.

In order to properly evaluate petitioner’s contention in this regard, we look first to the court’s own explanation of the position it took in City of Detroit and to its definition of “increase”.

[W]hen we refer to an “increase” we mean an increase in the rates above those which would result from use of the conventional rate-base method. For, though we hold that method not to be the only one available under the statute, it is essential in such a case as this that it be used as a basis of comparison. It has been repeatedly used by the Commission, and repeatedly approved by the courts, as a means of arriving at lawful — “just and reasonable” — rates under the Act. Unless it is continued to be used at least as a point of departure, the whole experience under the Act is discarded and no anchor, as it were, is available by which to hold the terms “just and reasonable” to some recognizable meaning.

The necessity for an anchor to “hold the terms ‘just and reasonable’ to some recognizable meaning” is plain, for the words themselves have no intrinsic meaning applicable alike to all situations. Moreover, a rate which is just and reasonable to a producer of natural gas is not necessarily one which is just and reasonable to the consumer. When the inquiry is on whether the rate is reasonable to a producer, the underlying focus of concern is on the question of whether it is high enough to both maintain the producer’s credit and attract capital. To do this, it must, inter alia, yield to equity owners a return “commensurate with returns on investments in other enterprises having corresponding risks,” as well as cover the cost of debt and other expenses. These standards can be used to evaluate the justness and reasonableness of a given rate to the producer regardless of the method used to determine what the rate will be. As has been indicated, however, the primary-purpose of the Natural Gas Act is to protect consumers. Thus when the inquiry is whether a given rate is just and reasonable to the consumer, the underlying concern is whether it is low enough so that exploitation by the producer is prevented. Accordingly, the Commission must weigh the sometimes conflicting interests of both producer and consumer before it can say that a particular rate is “just and reasonable” within the meaning of the Natural Gas Act.

The main concern of the court in City of Detroit was that wholesale abandonment of a cost-oriented approach to rate regulation would also be the abandonment of the long utilized point of departure for analysis of the reasonableness of a given rate to the consumer. While rather concrete factors such as the ability to maintain and attract capital are available to gauge whether a rate is just and reasonable to a producer, no factors apart from producer costs are available to guide efforts to make that determination from the standpoint of the consumer. Thus the court feared that, if a rate based on market prices were not compared to one based on producer costs, the entire framework for evaluation of the reasonableness of the rate from the standpoint of the consumer would be lost, leaving without protection the segment of society which was supposedly the prime beneficiary of the Natural Gas Act’s system of regulation.

The same problems are not present when area rates are substituted for individual cost-of-service. As we indicated earlier, area rates are essentially rates based on composite cost of service for all producers in a given geographic area. Producer costs thus remain at the heart of the regulatory system. Moreover, a composite cost system of regulation has provided a workable method of setting rates just and reasonable to both producers and consumers in other areas of regulated industry. Finally, the Commission found that use of area rates would permit firmer control over the rates charged by pipeline companies than was possible under cost-of-service regulation and at the same time would provide a stimulus for increased production.

In sum, this case is not a “case such as” City of Detroit, for abandonment of cost oriented regulation is not here proposed. Thus, while it remains true that rates must be “just and reasonable”, we see no necessity for defining those terms by the relationship that an area rate bears to a rate computed under individual cost-of-service. Since no actual rates are before us at this time, what we have said disposes of petitioner’s contention in this regard.

V

Rate of Return Component

Petitioner next contends that, even if area rates may be employed by the Commission to regulate the price of gas produced by pipeline companies, the same rate-of-return component cannot be used to set the actual rates for gas produced by independent companies and pipeline companies. If the same component is used, petitioner argues, pipeline companies will receive an enormous and unreasonable yield on the equity capital invested in their pipeline operations.

On the surface, at least, petitioner’s argument has some appeal. Petitioner points first to the fact that in both the Permian Basin and Southern Louisiana cases, cases which dealt only with rates applicable to independent producers, the Commission fixed a rate of return on capitalized investment at 12%. Petitioner then indicates that the record in this case shows that independent producers employ, on the average, a much higher percentage of equity capital than do pipeline companies. From this it follows, in petitioner’s view, that a 12% overall rate of return results in a far greater yield on equity to a pipeline company than to an independent producer. This same result will allegedly occur each time the same rate of return is used for both pipeline companies and independent producers.

Petitioner also maintains that application of a 12% rate of return to pipeline companies would be circular. As it points out, in the Permian Basin case the Commission determined that the average pipeline company received an overall rate of return of 6.5% which yielded 12% on equity. Considering this yield, the somewhat greater risks inherent in production activity alone and the larger percentage of equity capital employed by the average independent producer, the Commission determined that a 12% overall rate of return, yielding about 13.5% on equity, would be appropriate for independent producers. Petitioner thus argues that 12% was chosen as an appropriate rate of return in Permian Basin in part to place independent producers on a parity with pipeline companies. To now apply a 12% rate of return to pipeline production activity under the guise of placing the return from such activity on a parity with that received by independent producers, is, in petitioner’s view, to move in circles.

A close look at what the Commission has done, however, makes the surface anomalies disappear. In the first place, under the instant rule, area rates will apply to pipeline companies only with regard to gas produced from leases acquired after October 7, 1969. The cost of such production must therefore be borne largely by “new” money. That pipeline companies may have been able to finance their production activities with a large percentage of low-cost debt in the past is no assurance that they will be able to do so in the future. It is a matter of common knowledge that interest rates on new money have risen sharply in the last few years. Therefore, past financing experience is not a factor which is entirely determinative of the issue before us. What is relevant is the amount it will cost the pipelines in the future to produce gas from new leases.

The Commission was not convinced that the production of natural gas in the future could be accomplished more cheaply by pipeline producers than it could be by independents. While conceding that certain elements of pipeline production tended to be less expensive than corresponding elements of independent producer operations, the Commission concluded that aggregate costs, including costs of capital, would be similar. The record supports this conclusion. Many out-of-pocket expenditures are the same for both independent producers and pipeline companies and many wells are the product of joint ventures between the two groups. In addition, as just noted, the cost of debt capital has been rising over the past few years, making somewhat doubtful the proposition that future production operations can be accomplished through the use of “lost cost” debt. In fact, there was evidence to indicate that recent debt issues for both independent producers and pipeline companies had similar rates of interest and other terms. Moreover, there was also evidence to indicate that pipeline companies with large percentages of debt in their capital structures might be in a less advantageous position with regard to raising more capital through the use of debt than were independent producers which did not have such high percentages of debt.

Even if total costs for the two groups are not precisely similar, however, the actual rates set in area rate proceedings are based on data gathered from both independent producers and pipeline companies. Thus, any differences in cost, including costs of capital, between the two groups, like differences within them, will be taken into account before the rates are set. Naturally some independent producers and some pipeline companies will benefit from the rate so determined more than will others but disparity in benefit does not preclude use of a single area price structure for all.

The circles petitioner seeks to draw are broken largely by changed circumstances, for the Commission has determined that the past experience of pipeline companies does not paint a wholly accurate picture of the future cost of producing gas from new leases. As is evident from the above comments, however, the Commission’s decision to allow pipeline producers the same rate of return on production investment allowed independent producers is based on its prediction that both groups will have similar costs in the future. Similarly, the record before the Commission largely emphasized an upward trend which would extend into the future. If future costs for the two groups are significantly different — if the Commission’s prediction turns out to be unfounded — then the premise for its decision with regard to the appropriate rate of return will not exist. In that event, costs incurred by independent producers cannot be averaged with those incurred by pipeline companies to derive a just and reasonable rate for both. See United States v. Abilene & Southern Ry., 265 U.S. 274, 290-291, 44 S.Ct. 565, 68 L.Ed. 1016 (1924); cf. I.C.C. v. Mechling, 330 U.S. 567, 583, 67 S.Ct. 894, 91 L.Ed. 1102 (1947); The New England Divisions Case (Akron, C. & Y. Ry. Co. v. United States et al.), 261 U.S. 184, 43 S.Ct. 270, 67 L.Ed. 605 (1923).

Thus the Commission must continually re-evaluate its prediction as experience accumulates. In an actual area rate proceeding, the Commission may start from the premise that the same rate of return should be applied to the production investment of both independent producers and pipeline companies in the area under consideration. However, our decision does not preclude any proper party from showing that production costs for the two groups are significantly different and that, as a result, each group should receive a different rate of return on its production investment. Essentially, then, we conclude that the Commission’s decision to allow pipeline producers the same rate of return on new production as it allows independent producers can be a starting point only and that the propriety of actually allowing the two groups a single rate of return will have to be determined on the basis of the facts developed in an actual area rate case.

VI

Treatment of Income Tax Benefits

Petitioner’s final argument concerns the treatment by the Commission of certain income tax benefits emanating from pipeline production activity. Petitioner argues that the Commission’s failure to modify the area rates by applying separate income tax components to each pipeline company violates the “actual taxes paid” principle.

For purposes of ratemaking, income taxes are treated as costs incurred in the operation of the enterprise. Those engaged in the production of natural gas for a long time argued before both the Commission and the courts that the proper tax element of their rates was the tax that would have been paid but for certain deductions provided by the Internal Revenue Code, chiefly those for depletion, intangible expenses and accelerated depreciation. The reasoning behind these arguments was that, in granting such deductions, Congress sought to provide an incentive for participation in the production of a wasting asset. Only if the companies engaged in production of natural gas were allowed to retain the tax savings accruing from these provisions, the argument continued, would the congressional purposes be given full effect.

Almost uniformly, this reasoning was rejected. While it could not be contested that Congress intended to provide incentives through the above deductions, neither could it be contested that the Commission itself had the duty under the Natural Gas Act of setting rates which were just and reasonable. Widely accepted principles of ratemaking provided that an allowance both for incentive and for depletion of a wasting asset be included as an element of cost on which the rate was based regardless of the tax laws. From this, it followed that the proper tax element in a rate was the amount of taxes actually paid. Savings stemming from depreciation, depletion and intangible expense deductions were thus required to “flow through” the company to the purchaser in the form of lower rates. In addition, where such deductions were greater than a pipeline company’s net income from production activity, the company was required to use the excess deductions to reduce the taxes payable on income from transmission activity. Were this not done, the producer would receive, in effect, the same incentives twice.

Petitioner claims that application of area rates to pipeline companies would violate this “actual taxes paid” principle. Under the area rate concept, it argues, the tax element of the rate is calculated on an area and not on an individual basis. As a result, a company which pays less taxes than the average company producing gas in the area retains for itself tax savings which petitioner argues must flow through to the consumer.

In our view, the answer to petitioner’s contention is to be found in the principle mentioned above that, for rate-making purposes, taxes are considered nothing more and nothing less than a cost of doing business. No hypothetical taxes can be included in cost of service just as no other hypothetical expenses can be included. Thus, the “actual taxes paid” principle is in reality a particular application of what might be called the “actual costs incurred” principle applicable to all elements of cost on which a rate is based. That there has been extensive litigation focused on the tax element of overall expenses is primarily due to the problems of reconciling the actual costs incurred principle with the congressional purposes embodied in the sections of the Internal Revenue Code discussed above.

When a company’s rates are set under individual cost-of-service, then, only actual costs — tax and other — can be included. When area rates are used, however, all elements of cost on which the rate is based are to some degree hypothetical, for they are derived from average costs incurred by producers within the relevant area. Regardless of the category of costs, some producers will actually spend more and some will actually spend less than is attributed to that category in the composition of the area rate. We conclude, therefore, that the tax element of the area rate should not be Singled out for special treatment simply because area rates are applied to pipeline production. As with all other elements of cost, we believe that the average amount expended by a producer in the area is the appropriate amount for inclusion in the rate.

One further point calls for attention, however. In discussing the tax issue, the Commission stated that

in the pipeline’s rate case [its own] production will be allowed an area rate in which the presence or absence of a tax component will depend upon whether it has been shown that, under the tax laws then in effect, gas production operations of the industry as a whole on the average result in the payment of any Federal income taxes. But regardless of this determination, it is to be expected that some pipelines (like some independent producers) will be able to show that they paid taxes on their production activities, while others (also like some independent producers) will have tax credits which can serve to reduce the taxes upon their other operations.

In the Permian Basin and Southern Louisiana rate cases, the Commission fixed the tax element of the rate at zero. It appears to us, however, that this figure represents only the Commission’s determination that the average producer would pay no taxes on income from production activity; it does not represent a determination that the average producer would neither pay taxes nor have a net tax loss which could be used to reduce other tax liability. Thus, a zero tax element in an area rate may in fact be too high.

The propriety of the actual amount set for any element of an area rate is not presently before us and we raise the above issue only because petitioner has indicated that use of area rates will result in the absence of savings to the consumer stemming from tax savings “spilled over” from pipeline production activity to transmission activity. In the case of an independent producer, it may well be that the Commission has not considered as within its area of concern the spill-over benefits of a net tax loss on production activity. Such producers may have no other jurisdictional activities in which the spilled over benefits could be used, and the Commission may have considered that its function was at end when it concluded simply that consumers should pay nothing for taxes because no tax liability would be incurred. In the case of pipeline production, however, there is another jurisdictional activity in which spilled-over benefits could be used, namely pipeline transmission activity. There would thus be some force to an argument that the Commission cannot simply stop when it has determined that pipelines, on the average, will pay no taxes on their production activity but must then go on to determine whether they will have a net tax loss and should reflect that loss by including a negative tax element in the area rate.

The record does not reflect whether the Commission has fully explored the problem outlined immediately above. Ordinarily, under such circumstances, we would remand the case to the Commission so that it could supply this omission. However, we believe that that evaluation would be most appropriately undertaken in the context of an actual area rate proceeding in which the Commission gathers before it all relevant financial data concerning producers in the area. Since resolution of the instant problem requires, in our view, careful examination of just such data, a remand for further exploration in the context of these proceedings would eventually result in great duplication of effort.

Accordingly we affirm the Commission’s decision to include the same tax element in the area rates applicable to independent producers and to pipeline companies with one caveat: If the data compiled in an actual area rate proceeding support the conclusion that the average income tax paid by all affected producers in the area under consideration is less than zero, and if it is impossible to include a negative tax element in the area rate applicable to independent producers, our decision does not preclude any proper party from contending that the area rates applicable to independent producers and to pipeline companies should contain different, though not necessarily individualized, tax elements.

With that caveat and our comments concerning the rate of return in mind, we affirm the order of the Federal Power Commission here under review.

Judgment accordingly.

APPENDIX A

The Commission, acting pursuant to the authority of the Natural Gas Act, as amended, particularly Sections 4, 5, 8 and 16 thereof (52 Stat. 822, 823, 825, 830; 76 Stat. 72; 15 U.S.C. 717c, 717d, 717g, 717o), orders:

(A) Effective upon issuance of this statement, Part 2, Subchapter A, General Rules, Chapter 1 of Title 18 of the Code of Federal Regulations, is amended by adding a new Section 2.66 to read as follows:

§ 2.66 Pricing of New Gas Produced, by Pipelines and Pipeline Affiliates.
(a) As a matter of policy in future pipeline rate proceedings, gas produced by pipelines or by their affiliates from leases acquired after the date of this order will be priced for rate making purposes at the just and reasonable area rate applicable to gas of a vintage corresponding to the date of completion of the first well on the lease, otherwise at the “in-line” price, or, if there is no in-line price, on the basis of the guideline price set forth in Section 2.56 of our Rules, with the following exceptions:
(1) If a pipeline or pipeline affiliate acquires a developed lease from which jurisdictional sales are being made, the applicable price of gas shall be the lower of (a) the contract price applicable to the gas, or (b) the applicable area price (or inline or guideline price);
(2) If a pipeline or pipeline affiliate acquires a developed lease from which non jurisdictional sales are being made, gas produced from the lease will be priced at the just and reasonable area price applicable to gas of the vintage corresponding to the date of lease acquisition (or in-line or guideline price);
(3) If the pipeline is able to show in a rate proceeding that special circumstances exist which justify different treatment, such a showing should be made by means of a special schedule and supporting evidence filed in addition to the material otherwise required by Section 154.63 of the Regulations.
(b) Pipelines acquiring production leases subsequent to the date of this opinion either on their own part or through affiliates should:
(1) Where they have their own production maintain separate subdivisions of their plant and expense accounts related to production properties and production activities, so as to show separately costs related to production from present leases and costs related to production from leases acquired after the date of this opinion;
(2) In making a rate filing provide additional detail in subdivisions within the production function, i. e., as between gas from present leases and gas from leases acquired after the date of this opinion with respect to their own production and also with respect to any production of their affiliates.

42 F.P.C. 738, 753 (1969).

The Commission, acting pursuant to the authority of the Natural Gas Act, as amended, particularly Sections 4, 5, 8 and 16 thereof (52 Stat. 822, 823, 825, 830; 76 Stat. 72; 15 U.S.C. 717c, 717d, 717g, 717o), orders:

(A) The applications for rehearing filed by the Municipal Group, California and El Paso are denied.

(B) Effective upon issuance of this statement Section 2.66(a), promulgated by our order of October 7, 1969, Part 2, subehapter A, General Rules, Chapter 1 of Title 18 of the Code of Federal Regulations is amended as follows:

§ 2.66 Pricing of New Gas Produced by Pipelines and Pipeline Affiliates
(a) * * *
(1) If a pipeline or pipeline affiliate acquires a developed lease from which jurisdictional sales are being made and Paragraph (3) below does not apply, the applicable price of gas shall be the lower of (a) the contract price applicable to the gas, or (b) the applicable area price (or in-line or guideline price);
(2) If a pipeline or pipeline affiliate acquires a developed lease from which non jurisdictional sales are being made and Paragraph (3) below does not apply, gas produced from the lease will be priced at the just and reasonable area price applicable to gas of the vintage corresponding to the date of lease acquisition (or in-line or guideline price);
(3) If a pipeline or pipeline affiliate acquires a developed or undeveloped lease, either directly or through intermediaries, from another pipeline or affiliate which owned the lease prior to the date,of Opinion No. 568, the lease so acquired after the date of Opinion No. 568 shall be subject to cost-of-service treatment for ratemaking purposes, subject to further determinations in Phase II of these proceedings.
(4) If the pipeline is able to show in a rate proceeding that special circumstances exist which justify different treatment, such a showing should be made by means of a special schedule and supporting evidence filed in addition to the material otherwise required by Section 154.63 of the Regulations.

42 F.P.C. 1089, 1093 (1969). 
      
      . Natural Gas Act of 1938, ch. 556 § 19(b), 52 Stat. 831, 15 U.S.C. § 717r(b) (1970).
     
      
      . Pipeline Production Area Rate Proceeding (Phase I), 42 F.P.C. 738, reh. denied, 42 F.P.C. 1089 (1969).
     
      
      . “On-system” gas, as the term is here used, means that gas which is produced by a pipeline company or its affiliate and transported by the pipeline company through its own pipelines to the purchaser. “Off-system” gas, is gas produced by pipeline companies and sold to other pipeline companies. No questions involving the price of off-system gas are presented by the instant petition for review.
     
      
      . Independent producers are those producers of natural gas which do not “engage in the interstate transmission of gas from the producing fields to consumer markets and [are] not affiliated with any interstate natural-gas pipeline company.” Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 675, 74 S.Ct. 794, 795, 98 L.Ed. 1035 (1954).
     
      
      . 15 U.S.C. § 717f(e) (1970).
     
      
      . Atlantic Ref. Co. v. Public Service Comm’n, 360 U.S. 378, 79 S.Ct. 1246, 3 L.Ed.2d 1312 (1959).
     
      
      . 15 U.S.C. § 717c(e) (1970).
     
      
      . 15 U.S.C. § 717d(a) (1970).
     
      
      . City of Chicago v. F.P.C., 128 U.S.App.D.C. 107, 110, 385 F.2d 629, 632 (1967), cert. denied, Public Service Comm. v. F.P.C., 390 U.S. 945, 88 S.Ct. 1028, 19 L.Ed.2d 1133 (1968). See also J. Bonbright, Principles of Public Utility Rates, 66-81 (1961); E. Nichols, Ruling Principles of Utility Regulation 1-9 (1955).
     
      
      . Permian Basin Area Rate Cases, 390 U.S. 747, 758, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968); Phillips Petroleum Co., 24 F.P.C. 537, 545-46 (1960). The problem was compounded by the fact that the Commission apparently declined to act on many rate increases pending the outcome in Congress of several bills designed to remove its jurisdiction over independent . producers. The bills were vetoed. .T. Landis, Report on Regulatory Agencies to the President-Elect, printed for use of the Senate Judiciary Committee, 86th Cong., 2d Sess. 7 (1960).
     
      
      . Prior to 1961, natural gas was primarily a by-product of oil production. Technology prior to that time was insufficient to allow producers to search for gas alone with any degree of success. See generally Permian Basin Area Rate Proceeding, 34 F.P.C. 306, 325-329 (1964) (presiding examiner’s decision). For that reason, it was difficult and somewhat unrealistic to attempt to allocate to gas production a portion of the total expenditure required for drilling an oil well, just as it would be to try to separate the costs of growing apple seeds from the costs of growing apples. See Permian Basin Area Rate Cases, 390 U.S. 747, 761 & n. 25, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968); 34 F.P.C. 306, 338 (1964) (presiding examiner’s decision); Phillips Petroleum Co., 24 F.P.C. 537, 543-544 (1960). Though the Commission has recently conceded that cost allocation is never an exact science, Texas Gulf Coast Area Rate Proceeding, F.P.C. slip op. at 10-11 (No. 595, decided May 6, 1971), use of area rates does reduce the problems inherent in the process. Moreover, since some 80% of the income from production from a given well was attributable to oil, the rates set for gas were unlikely to have a significant effect on exploratory activity. 34 F.P.C. 306, 311 (1964) (presiding examiner’s decision).
     
      
      . If, for example, four different companies, each with a different cost-of-service, were producing gas from a single well, purchasers could pay four different prices for gas emanating from that single well. Phillips Petroleum Co., 24 F.P.C. 537, 544 (1960). While the desire to create a symmetrical price structure might not by itself permit the Commission to set any given rates, see City of Detroit v. F.P.C., 97 U.S.App.D.C. 260, 266 n. 9, 230 F.2d 810, 816 n. 9 (1955), elimination of such anomalies would seem to be a desirable end provided that it can be accomplished by means which fully comport with the aims of the Natural Gas Act.
     
      
      . See generally Permian Basin Area Rate Cases, 390 U.S. 747, 756 & n. 11, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968); Sunray Mid-Continent Oil Co. v. F.P.C., 364 U.S. 137, 160, 80 S.Ct. 1392, 4 L.Ed.2d 1623 (1960) (Harlan, J., dissenting); F.P.C. v. Hope Natural Gas Co., 320 U.S. 591, 649, 64 S.Ct. 281, 88 L.Ed. 333 (1944) (Jackson, J., dissenting).
     
      
      . Statement of General Policy No. 61-1, 24 F.P.C. 818 (1960). Three of the initial areas were consolidated at the commencement of the Permian Basin proceeding. 24 F.P.C. 1122 (1960). The prices contained in the Statement applied to both initial and increased prices. The Commission indicated that no certificate would be issued under § 7 of the Act if the proposed prices for sale of the gas exceeded the guideline prices and that all increases in existing prices would be suspended under § 4(e) if, as increased, the guideline prices were exceeded.
     
      
      . Since the Permian Basin case, one other rate proceeding has completed the course of judicial review. Southern Louisiana Area Rate Cases, 40 F.P.C. 530 (1968); aff’d, 428 F.2d 407 (5th Cir.), cert. denied, Municipal Distributor Group v. F.P.C., 400 U.S. 950, 91 S.Ct. 241, 27 L.Ed.2d 257 (1970). At least two other proceedings have readied a decision by the Commission. Texas Gulf Coast Area Rate Proceeding, 39 U.S.L.W. 2653 (May 6, 1971); Hugoton-Anadarko Area Rate Proceeding, 44 F.P.C. 761 (1970).
     
      
      . The rate, expressed in terms of cents per thousand cubic feet (Mcf) represents the cost of finding and producing new reserves of natural gas. 34 F.P.C. at 340-342. In the Permian case, both maximum and minimum permissible prices for new gas were fixed. In addition, certain adjustments to these prices were required depending on the quality of the gas produced. Permian Basin Area Rate Cases, 390 U.S. 747, 762-763, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968).
     
      
      . Gas produced after January 1, 1961 was considered “new” gas because much of the data concerning the cost of gas received by the Commission involved 1960 costs, because guideline policies had been established in 1960 and because 1961 marked the time at which it became possible to engage in directional searches, i. e., searches for either oil or gas alone. 34 F.P.C. at 188-189. In the Southern Louisiana Area rate proceeding, a three-price system was established 40 F.P.C. 530, 636 (1968).
     
      
      . 40 F.P.C. 530 (1968), aff’d, 428 F.2d 407 (5th Cir.), cert. denied, Municipal Distributor Group v. F.P.C., 400 U.S. 950, 91 S.Ct. 241, 27 L.Ed.2d 257 (1970).
     
      
      . About 70% of all gas produced for marketing in the United States is sold in interstate commerce. 34 F.P.C. 172-173. See generally FPC Annual Report 49-50 (1970).
     
      
      . Pipeline Production Area Rate Proceeding (Phase I), 42 F.P.C. 738, 745 (1969). Gas produced by an affiliate of a pipeline is treated for ratemaking purposes as if it were produced by the pipeline company itself. Id. at 754, 784-785. This accords with the treatment with such affiliates generally. See Mississippi River Fuel Corp. v. F.P.C., 102 U.S.App.D.C. 238, 241, 252 F.2d 619, 622, cert. denied, 355 U.S. 904, 78 S.Ct. 331, 2 L.Ed.2d 260 (1957); Union Prod. Co., 31 F.P.C. 41, 43-44 (1964). But see Panhandle Eastern Pipeline Co., 40 F.P.C. 98, 101 n. 2 (1968); Union Prod. Co., 31 F.P.C. 503, 504 n. 1 (1964). As used in the discussion which follows, the term pipeline company includes affiliates of pipeline companies.
     
      
      . 30 F.P.C. 1354 (1963).
     
      
      . 31 F.P.C. 1595 (1964).
     
      
      . 35 F.P.C. 497 (1966).
     
      
      . An additional reason for severance was that testimony and exhibits in the Hugo-ton-Anadarko proceeding had produced no evidence concerning the impact on consumers of valuing pipeline production on the basis of area rates. 35 F.P.C. 498.
     
      
      . 35 F.P.C. 499. The proceeding was divided into two phases primarily because of the functional role played by area rates in eliciting future supplies of natural gas. Different issues are thus presented when the question is whether area rates should be applied to future production activity than are present when the question is whether such rates should be applied to production from existing leases. See note 17, supra. Thus Phase II would relate to existing leases. 42 F.P.C. at 746.
     
      
      . 35 F.P.C. 501 (1966).
     
      
      . 35 F.P.C. 806 (1966).
     
      
      . 42 F.P.C. 797. Jurisdictional gas is gas sold in interstate commerce. See note 19, supra. Pipeline comjmnies produce approximately 14% of all jurisdictional gas, or about 9.8% of all gas produced for marketing in the United States. See 42 F.P.C. 745.
     
      
      . 42 F.P.C. 797.
     
      
      . Id.
      
     
      
      . The examiner’s compromise solution involved allowing pipeline companies to retain some of the tax benefits which formerly inured to the benefit of consumers and allowing affiliates to make 10% of their on-system sales of gas at area rates. 42 F.P.C. 802.
     
      
      . 42 F.P.C. 746; see notes 11-13, supra.
      
     
      
      . The decline was both relative and absolute. The amount of gas reserves owned by pipeline companies declined 29.9% between 1958 and 1966. The percentage of total reserves owned by pipeline companies declined from 25% to 13% during the same period. 42 F.P.C. 747—18; see notes 63, 64 infra.
      
     
      
      . 42 F.P.C. 754, modified, 42 F.P.C. 1093 (1969). The Commission’s order is reprinted at Appendix A, infra.
      
     
      
      . 42 F.P.C. 1089 (1969).
     
      
      . The two types of proceeding are distinguished in the Administrative Procedure Act, 5 U.S.C. §§ 551(5), (7) (1970). As the following discussion indicates, however, the definitions contained in Section 551 are not always easily applied to a given fact situation.
     
      
      . See N.L.R.B. v. Wyman-Gordon Co., 394 U.S. 759, 770-771, 89 S.Ct. 1426, 22 L.Ed.2d 709 (1969) (opinion of Black, J.); Capitol Airways, Inc. v. CAB, 110 U.S.App.D.C. 262, 265, 292 F.2d 755, 758 (1961). See generally 1 K. Davis, Administrative Law Treatise § 5.01 (1958); Shapiro, The Choice of Rule-making or Adjudication in the Development of Administrative Policy, 78 Harv.L.Rev. 921 (1965); Robinson, The Making of Administrative Policy, 118 U.Pa.L.Rev. 485 (1970).
     
      
      . 31 Fed.Reg. 6075, amended, 31 Fed.Reg. 7926 (1966). See generally 5 U.S.C. § 553(b) (1970). In its notice, the Commission stated that
      [a] separate proceeding entitled “Pipeline Production Area Rate Proceeding, Docket No. RP66-24, [sic] is hereby instituted, pursuant to sections 4, 5, 10, 14, 15, and 16 of the Natural Gas Act, to determine the proper method to be used by the Commission in pricing natural gas produced by pipelines and/or acquired by them from their affiliated producers.
      31 Fed.Reg. at 6076.
     
      
      . See 5 U.S.C. § 551(4) (1970); American Airlines, Inc. v. CAB, 123 U.S.App.D.C. 310, 316, 359 F.2d 624, 630 (en banc), cert. denied, 385 U.S. 843, 87 S.Ct. 73, 17 L.Ed.2d 75 (1966); cf. F.P.C. v. Texaco, Inc., 377 U.S. 33, 84 S.Ct. 1105, 12 L.Ed.2d 112 (1964).
     
      
      . 34 Fed.Reg. 17803 (1969), amended, 35 Fed.Reg. 1104 (1970); 5 U.S.C. § 553(d).
     
      
      . II Joint Appendix 571 n. 4. After the notice mentioned in note 38, supra, was promulgated, various pipeline companies moved to have the proceedings go forward on the basis of written data and exhibits submitted by the parties to the Commission. The Commission denied the motion, citing the need for a full evi-dentiary record. 36 F.P.C. at 956. We do not read this denial of the companies’ request for informal rulemaking as a statement that the proceeding was to be an “adjudication”. See generally Automotive Parts & Accessories Ass’n, Inc. v. Boyd, 132 U.S.App.D.C. 200, 202-206, 407 F.2d 330, 332-336 (1968). At any rate, it is the substance of what the Commission has done that is controlling. See Citizens Communication Center v. F.C.C., 447 F.2d 1201 at 1204, n. 5 (decided June 11, 1971); American Airlines, Inc. v. CAB, 123 U.S.App.D.C. 310, 317, 359 F.2d 624, 631 (1966, en banc). In substance, the Commission has promulgated a rule.
     
      
      . See also F.P.C. v. Metropolitan Edison Co., 304 U.S. 375, 58 S.Ct. 963, 82 L.Ed. 1408 (1938); Shell Oil Co. v. F.P.C., 334 F.2d 1002, 1007 (3rd Cir. 1964); Amerada Petroleum Corp. v. F.P.C., 231 F.2d 461 (10th Cir. 1956).
     
      
      . Nor did it turn on whether the order was “final.” Compare Phillips Petroleum Co. v. F.P.C., 227 F.2d 470 (10th Cir. 1955). Here, also, there is little question that the Commission’s action is “final” for purposes of review. For all practical purposes, it determines the method to be used in placing a value on gas produced by pipeline companies in all future pipeline rate cases. True it is that no impact in terms of increased or decreased rates will be felt until further action based upon the instant order is taken by either the Commission or a pipeline company. Nevertheless, the Commission has indicated that waiver of the instant rule which it has promulgated by order will be infrequently granted. 42 F.P.C. at 1091; see Southern Louisiana Area Rate Cases, 428 F.2d 407, 420 n. 24 (5th Cir. 1970). See generally 18 C.F.R. §§ 1.7(b), 2.66(a) (4) (1971). The controlling nature of the rule, the predominantly legal nature of the questions presented and the necessity for swift determination of the questions involved, all combine to make the order promulgating the rule final for purposes of review at this time. See generally Abbott Labs. v. Gardner, 387 U.S. 136, 87 S.Ct. 1507, 18 L.Ed.2d 681 (1967); C.B.S., Inc. v. United States, 316 U.S. 407, 62 S.Ct. 1194, 86 L.Ed. 1563 (1942); Air Line Pilots Ass’n v. D.O.T., 446 F.2d 36 (5th Cir. 1971); Atlantic Seaboard Corp. v. F.P.C., 201 F.2d 568 (4th Cir. 1953); L. Jaffe, Judicial Control of Administrative Action 418-23 (1965).
     
      
      . See also Robertson v. F.T.C., 415 F.2d 49 (4th Cir. 1969); Division of Production, American Petroleum Institute v. Halaby, 307 F.2d 363 (5th Cir. 1962).
     
      
      . As recent cases have indicated, there is a record available for review even when no evidentiary hearings have been held. Automotive Parts & Accessories Ass’n, Inc. v. Boyd, 132 U.S.App.D.C. 200, 206, 407 F.2d 330, 336 (1968). Compare Texaco, Inc. v. F.P.C., 317 F.2d 796, 806 (10th Cir. 1963), reversed, 377 U.S. 33, 84 S.Ct. 1105, 12 L.Ed.2d 112 (1964) with Pan American Petroleum Corp. v. F.P.C., 352 F.2d 241, 243 (10th Cir. 1965) (Texaco on remand). This court itself has expressly called into question the continuing vitality of United Gas Pipe Line. Environmental Defense Fund, Inc. v. Hardin, 138 U.S.App.D.C. 391, 397 & n. 27, 428 F.2d 1093, 1099 & n. 27 (1970). See also Environmental Defense Fund, Inc. v. Ruckelshaus, 142 U.S.App.D.C. 74, 79, 439 F.2d 584, 591 (1971). In both of these cases a result was reached contrary to the one reached in United Gas Pipe Line although a similar judicial review statute was under consideration. Compare 15 U.S.C. § 717r(b) (1970) with 7 U.S.C. § 135b(d) (1970).
     
      
      . 322 F.2d at 619.
     
      
      . See, e. g., Pacific States Box & Basket Co. v. White, 296 U.S. 176, 186, 56 S.Ct. 159, 80 L.Ed. 138 (1935); United States v. George S. Bush & Co., 310 U.S. 371, 60 S.Ct. 944, 84 L.Ed. 1259 (1940); Flying Tiger Line, Inc. v. Boyd, 244 F.Supp. 889, 892 (D.D.C.1965).
     
      
      . 322 F.2d at 619.
     
      
      . See Corn Prod. Co. v. Dept. of Health, Education and Welfare, F.D.A., 427 F.2d 511, 517 (3rd Cir. 1970); Air Line Pilots Ass’n v. Quesada, 276 F.2d 892, 896 (2d Cir. 1960); 1 K. Davis, supra note 37, § 5.01.
     
      
      . Willapoint Oysters, Inc. v. Ewing, 174 F.2d 676, 693 (9th Cir.), cert. denied, 338 U.S. 860, 70 S.Ct. 101, 94 L.Ed. 527 (1949) (“Rule-making is legislation on the administrative level, i. e., legislation within the confines (standard) of the granting statute as required by the Constitution and its doctrines of non-delegability and separability of powers.”); see United States v. Robel, 389 U.S. 258, 274-275, 88 S.Ct. 419, 429, 19 L.Ed.2d 508 (1967) (Brennan, J., concurring):
      Congress ordinarily may delegate power under broad standards . . . No other general rule would be feasible or desirable. Delegation of power under general directives is an inevitable consequence of our complex society, with its myriad, ever changing, highly technical problems . . . It is generally enough that, in conferring power upon an appropriate authority, Congress indicates its general policy, and act in terms or within a context which limits the power conferred. . . . Given such a situation, it is possible for affected persons, within the procedural structure usually established for the purpose, to be heard by the implementing agency and to secure meaningful review of its action in the courts, and for Congress itself to review its agent’s action to correct significant departures from Congress’ intention.
      
        See also American Power & Light Co. v. S.E.C., 329 U.S. 90, 104-106, 67 S.Ct. 133, 91 L.Ed. 103 (1946). Whether Congress has delegated power with the requisite precision
      depends not upon the breadth of the definition of the facts or conditions which the administrative officer is to find but upon the determination whether the definition sufficiently marks the field within which the Administrator is to act so that it may be known whether he has kept within it in compliance with the legislative will.
      Yakus v. United States, 321 U.S. 414, 425, 64 S.Ct. 660, 668, 88 L.Ed. 834 (1944).
     
      
      . Alabama-Tennessee Natural Gas Co. v. F.P.C., 359 F.2d 318, 343 (5th Cir.), cert. denied, 385 U.S. 847, 87 S.Ct. 69, 17 L.Ed.2d 78 (1966); see F.P.C. v. Texaco, Inc., 377 U.S. 33, 84 S.Ct. 1105, 12 L.Ed.2d 112 (1964). See generally S.E.C. v. Chenery Corp., 332 U.S. 194, 203, 67 S.Ct. 1575, 91 L.Ed. 1995 (1947); American Airlines, Inc. v. CAB, 123 U.S.App.D.C. 310, 316 n. 16, 359 F.2d 624, 630 n. 16 (1966, en banc).
      
     
      
      
        . This conclusion is implicit in various decisions of the Supreme Court and of this court. E. g., American Trucking Ass’ns, Inc. v. United States, 344 U.S. 298, 310, 73 S.Ct. 307, 97 L.Ed. 337 (1953); National Broadcasting Co. v. United States, 319 U.S. 190, 224-225, 63 S.Ct. 997, 87 L.Ed. 1344 (1943); Pacific & Southern Co. v. F.C.C., 132 U.S.App.D.C. 101, 405 F.2d 1371 (1968) (relying on WBEN, Inc. v. United States, 396 F.2d 601, 610-614 (2d Cir.), cert. denied, King’s Garden, Inc. v. F.C.C., 393 U.S. 914 (1968)); Automotive Parts & Accessories Ass’n v. Boyd, 132 U.S.App.D.C. 200, 407 F.2d 330 (1968). Whether such an inquiry is mandated, or even possible, in situations where minor agency action is taken without notice or hearing of any kind is a question not here decided, but such situations will probably arise only infrequently. See Texaco, Inc. v. FPC, 412 F.2d 740 (3rd Cir. 1969).
     
      
      . 15 U.S.C. § 717o (1970).
     
      
      . Superior Oil Co. v. F.P.C., 322 F.2d 601, 608 (9th Cir. 1963), cert. denied, 377 U.S. 922, 84 S.Ct. 1219, 12 L.Ed.2d 215 (1964); see Texaco, Inc. v. F.P.C., 412 F.2d 740 (3rd Cir. 1969); F.P.C. v. Texaco, Inc., 377 U.S. 33, 84 S.Ct. 1105, 12 L.Ed.2d 112 (1964).
     
      
      . 5 U.S.C. § 553 (1970).
     
      
      . 5 U.S.C. § 553(c) (1970). Where other specific statutes require an eviden-tiary hearing, the procedures contained in §§ 7 & 8 of the APA apply. Id.; see Siegel v. Atomic Energy Commission, 130 U.S.App.D.C. 307, 314-315, 400 F.2d 778, 785-786 (1968).
     
      
      . Alabama-Tennessee Natural Gas Co. v. FPC, 359 F.2d 318, 343, (5th Cir. 1966); Legislative History of the Administrative Procedure Act, S.Doc. 248, 79th Cong., 2d Sess. 250, 373 (1946); cf. American Airlines, Inc. v. C.A.B., 123 U.S.App.D.C. 310, 318, 359 F.2d 624, 633 (1966, en banc) (“It is part of the genius of the administrative process that its flexibility permits adoption of approaches subject to expeditious adjustment in the light of experience.”) See generally Shapiro, supra note 37, at 936-37.
     
      
      . See Administrative Procedure in Government Agencies, S.Doc. No. 8, 77th Cong., 1st Sess. 118 (1941); Automotive Parts & Accessories Ass’n, Inc. v. Boyd, 132 U.S.App.D.C. 200, 208, 407 F.2d 330, 338 (1968). See generally 1 K. Davis, supra note 37, at § 6.06.
     
      
      . See Citizens to Preserve Overton Park, Inc. v. Volpe, 401 U.S. 402, 419, 91 S.Ct. 814, 28 L.Ed.2d 136 (1971); Administrative Procedure Act § 10, 5 U.S.C. § 706 (1970).
     
      
      . Citizens to Preserve Overton Park, Inc. v. Volpe, 401 U.S. 402, 416, 91 S.Ct. 814, 28 L.Ed.2d 136 (1971).
     
      
      . Id. at 415, 91 S.Ct. 814; Automotive Parts & Accessories Ass’n, Inc. v. Boyd, 132 U.S.App.D.C. 200, 208, 407 F.2d 330, 338 (1968). Both cases illustrate the dose nexus between review of an evidentiary and of a non-evidentiary record. In neither was an evidentiary record required as a predicate to agency action, but in both exacting scrutiny of the record actually compiled was found to be a necessary ingredient of judicial review.
     
      
      . See generally Universal Camera Corp v. N.L.R.B., 340 U.S. 474, 71 S.Ct. 456, 95 L.Ed. 456 (1951); Corn Prod. Co. v. Dept. of Health, Educ. and Welfare, F.D.A., 427 F.2d 511, 514 (3rd Cir. 1970); L. Jaffe, Judicial Control of Administrative Action 600-604 (1965). The final report of the Attorney General’s Committee on Administrative Procedure indicated that judicial review should take into account the nature of the evidence that it was practical to obtain on the issue under consideration. Administrative Procedure in Government Agencies, supra note 58, at 119. In large part, however, the procedural requirements which relevant statutes impose as a precedent to agency action reflect these practicalities. If, therefore, the minimum procedures required by statute have been fulfilled, it is not the function of the court to determine whether a different procedure or a different kind of evidence would have been better, but whether, on the basis of the record actually compiled, a reasoned conclusion could support the agency’s action. Cf. American Airlines, Inc. v. C.A.B., 123 U.S.App.D.C. 310, 313-314, 359 F.2d 624, 627-628 (1966, en banc). Compare, e. g., Pollack v. Simonson, 121 U.S.App.D.C. 362, 350 F.2d 740 (1965).
     
      
      . 42 F.P.C. at 745.
     
      
      . 42 F.P.C. at 747-748; see II Joint App. 498, 500.
     
      
      . The discussion which follows makes unnecessary any inquiry into whether the Commission’s reliance on extra-record statistical data was permissible simply because this was a rule-making proceeding, compare, California Citizen’s Band Ass’n, Inc. v. United States, 375 F.2d 43, 54 (9th Cir.), cert. denied, 389 U.S. 844, 88 S.Ct. 96, 19 L.Ed.2d 112 (1967), or whether the Commission was taking into account “legislative” as opposed to “ajudicative” facts. See generally American Airlines, Inc. v. C.A.B., 123 U.S.App.D.C. 310, 359 F.2d 624, 633 (1966); 1 K. Davis, supra note 37, § 15.03.
     
      
      . This is the ratio of total known reserves of natural gas to annual production. Permian Basin Area Rate Cases, 390 U.S. 747, 816-818, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968). The ratio has declined from 29.6 in 1950 to 13.3 in 1969, with the rate of decline accelerating over the past few years. FPC Annual Report 51 (1970). See also II Joint Appendix 465. It reached 11.9 in 1970. Texas Gulf Coast Area Rate Proceeding, FPC Slip Op. 12 (No. 595, decided May 6, 1971). A recent staff report predicts a further decline to 10.3 by 1973. FPC, Staff Report on Natural Gas Supply and Demand 11 (1969).
     
      
      . See note 33, supra.
      
     
      
      . Southern Louisiana Area Rate Proceeding, 40 F.P.C. 530, 552 (1968); Permian Basin Area Rate Proceeding, 34 F.P.C. 159, 183-84 (1965). See also Southern Louisiana Area Rate Cases, 428 F.2d 407, 437-439 (5th Cir. 1970).
     
      
      . FPC, Staff Report on Natural Gas Supply and Demand 7 (1969). The Staff gave more significance to the “critical” reserve-production ratio than it did to reserve-production ratios generally. The “critical” ratio is “the ratio at which increasing production can no longer be sustained at historical rates. The significance of the critical [reserve-production ratio] is that when it is reached an area can no longer be relied on to deliver its share of increasing U.S. production requirements.” Id. at 15. The Staff also indicated that the most important ratio for an early determination of whether future supplies of natural gas will be adequate is the findings-produetion ratio, i. e., the ratio of new gas found to gas produced during a given year. As long as that ratio is 1.0 or higher, the Commission apparently feels that some decline in the reserve-production ratio is not of critical importance. See Permian Basin Area Rate Proceeding, 34 F.P.C. 159, 184 (1965); Permian Basin Area Rate Cases, 390 U.S. 747, 817 n. 102, 88 S.Ct. 1244, 20 L.Ed.2d 312 (1968). Significantly, then the Commission in the instant case indicated that the finding-production ratio dropped below 1.0 for the first time in 1968. Text at note 64, supra. It has remained below 1.0 since that time. Texas Gulf Coast Area Rate Proceeding, FPC Slip Op. at 11 n. 7 (No. 595, decided May 6, 1971). In addition, the levels of annual exploratory drilling have also been declining over the past decade, FPC Annual Report 45 (1969) , although 1969 marked what may be the beginning of a reversal of this trend. FPC Annual Report 51 (1970).
     
      
      . N.L.R.B. v. Seven-Up Bottling Co., 344 U.S. 344, 348-349, 73 S.Ct. 287, 97 L.Ed. 377 (1953); Universal Camera Corp. v. N.L.R.B., 340 U.S. 474, 490, 71 S.Ct. 456, 95 L.Ed. 456 (1951). See generally United States v. Pierce Auto Freight Lines, 327 U.S. 515, 529-530, 66 S.Ct. 687, 90 L.Ed. 821 (1946); Interstate Power Co. v. F.P.C., 236 F.2d 372, 385-386 (8th Cir. 1956); Director, United States Bureau of Mines v. Princess Elkhorn Coal Co., 226 F.2d 570 (6th Cir. 1955); 2 K. Davis, supra note 37, at 342.
     
      
      . Reply Brief for Petitioner at 28. See also Southern Louisiana Area Rate Cases, 428 F.2d 407, 438 nn. 97-98 (5th Cir. 1970). Compare Moss, Is a Gas Shortage in Prospect, Public Utilities Fortnightly, October 14, 1965, at 30 with Russell, The Adequacy of Natural Gas Reserves, id. at 60.
     
      
      . See Southern Louisiana Area Rate Cases, 428 F.2d 407, 434-444 (5th Cir. 1970) . To the extent that projected supplies are sufficient to meet foreseeable demand, there would seem to be no need for stimulating a greater search for new supplies. Yet the Commission has indicated its concern with future supply in all of the area rate proceedings which have been concluded to this date. Texas Gulf Coast Area Rate Proceeding, Slip Op. at 11-19 (No. 595, decided May 6, 1971); Hugoton-Anadarko Area Rate Proceeding, Slip Op. at 19-22 (No. 586, decided September 18, 1970); Southern Louisiana Area Rate Proceeding, 40 F.P.C. 530, 632-36 (1968); Permian Basin Area Rate Proceeding, 34 F.P.C. 159, 185 (1965).
     
      
      . E. g., 42 F.P.C. 813:
      Should pipelines be encouraged to engage in greater exploration and development activities or, in the alternative, to purchase acreage of proven reserves?
      Assuming that pipeline exploration and development of production should be encouraged, would that policy objective be best furthered by pricing pipeline production on an area rate basis or by continuing regulation on traditional cost of service principle [sic] ?
      If pipeline (and affiliate) production is to be neither encouraged nor discouraged, what is the most appropriate pricing method to be used for such production.
      42 F.P.C. 814:
      To what extent, and in what respects, do pipelines operate their production properties in a different manner than do independent producers with respect to: (a) reserve to production ratio. . . ."
      In addition, the supply issue was discussed by several of the witnesses in the proceeding before the examiner. E. g., I Joint Appendix 87-88, 199-200.
     
      
      . See Permian Basin Area Rate Cases, 390 U.S. 747, 808 n. 89, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968); Alabama-Tennessee Natural Gas Co. v. F.P.C., 359 F.2d 318, 341 (5th Cir. 1966); Mississippi River Fuel Corp. v. F.P.C., 82 U.S. App.D.C. 208, 211, 163 F.2d 433, 436 (1947). Oompwre American Louisiana Pipe Line Co. v. F.P.C., 120 U.S.App.D.C. 140, 143, 344 F.2d 525, 528 (1965).
     
      
      . Permian Basin Area Rate Proceeding, 43 F.P.C. 899, 901 (1970); Offshore Southern Louisiana, Federal Domain & Disputed Areas Area Rate Proceeding, 41 F.P.C. 378 (1969).
     
      
      . Two cases relied upon by petitioner are inapposite. In Cinderella Career & Finishing Schools, Inc. v. F.T.C., 138 U.S.App.D.C. 152, 425 F.2d 583 (1970), the Commission completely disregarded the record of the proceedings before the examiner and proceeded to examine the issues before it de novo. Even if we were to assume that the procedural standards articulated in Cinderella fully applied to this case, it is evident that the Commission here did not disregard the record compiled before the examiner. The second case, Public Serv. Comm’n of New York v. F.P.C., 141 U.S.App.D.C. 174, 436 F.2d 904 (1970), was one in which the court remanded to the Commission because it had failed to articulate fully the basis for its decision. Here petitioner is not contending that the Commission failed to articulate the reasons for its actions. The contention is that the Commission’s action was based on information which it had no right to consider. As the foregoing discussion indicates, we disagree with that contention.
     
      
      . Such an argument, at this late date, would be difficult to maintain. See generally Permian Basin Area Rate Cases, 390 U.S. 747, 776-777, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968); Colorado Interstate Gas Co. v. P.P.C., 324 U.S. 581, 589, 65 S.Ct. 829, 89 L.Ed. 1206 (1945); F.P.C. v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 88 L.Ed. 333 (1944); F.P.C. v. Natural Gas Pipeline Co., 315 U.S. 575, 586, 62 S.Ct. 736, 86 L.Ed. 1037 (1942); Southern Louisiana Area Rate Cases, 428 F.2d 407, 423 n. 34 (5th Cir.), cert. denied, 400 U.S. 950, 91 S.Ct. 241, 27 L.Ed.2d 257 (1970). As was observed by the Court of Appeals for the Fifth Circuit, “[f]rom start to finish, the Permian Basin litigation occupied eight years and caused every conceivable criticism of the area regulatory process, of whatever merit, to be presented and considered.” Hunt Oil Co. v. F.P.C., 424 F.2d 982 at 984 (decided April 21, 1970).
     
      
      . A subsidiary argument advanced by petitioner is that statistics in the record indicate that costs for each pipeline company incurred in production activity diverge from median costs to a far greater extent than do costs for independent producers. See I Joint Appendix at 66, 352-353; II Joint Appendix at 431, 516-524. Petitioner argues that for this reason also area rates should not be applied to pipeline companies. The Commission rejected this argument, holding that these statistics reflected to a large extent the different costs prevailing during the different historical periods when pipelines entered the field of gas production. It concluded that future costs for both pipeline companies and independent producers would be similar and there was therefore little reason to suppose that historical cost divergences would continue. 42 F.P.C. at 748. It is, of course, true that “[t]he premise of group proceedings ... is that evidence pertaining to a group is typical of its individual members.” Chicago & North Western Ry. v. Atchison, T. & S. F. Ry., 387 U.S. 326, 342, 87 S.Ct. 1585, 1595, 18 L.Ed.2d 303 (1967); see New England Divisions Case, 261 U.S. 184, 199, 43 S.Ct. 270, 67 L.Ed. 605 (1923). Assuming that the data to which petitioner refers means that median costs are not “typical”, the Commission properly refused to accept them at face value and relied instead on other data which suggested that future costs would be very similar. Compare Southern Louisiana Area Rate Cases, 428 F.2d 407, 442 & n. 113 (5th Cir. 1970).
     
      
      . The field price was computed from the “ ‘weighted average arm’s length prices’ established by federally unregulated bargaining for similar gas in the fields.” City of Detroit v. F.P.C., 97 U.S.App.D.C. 260, 263, 230 F.2d 810, 813 (1955).
     
      
      . Other reasons included the Commission’s conclusion that cost-of-service regulation tended to accelerate unduly consumption of natural gas and that pipelines should be given incentives to develop their own reserves so that they would not be forced to rely completely on others for needed supplies. City of Detroit v. F.P.C., 97 U.S.App.D.C. 260, 266, 230 F.2d 810, 816 (1955). Presumably the second factor was also intended to allow the pipelines to bargain with other suppliers to obtain the best possible prices for gas. Apparently such bargaining has not been extensive. Permian Basin Area Rate Cases, 390 U.S. 747, 793 & n. 63, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968).
     
      
      . City of Detroit v. F.P.C., 97 U.S.App.D.C. 260, 265, 230 F.2d 810, 815 (1955); accord, Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 685, 74 S.Ct. 794, 98 L.Ed. 1035 (1954) (Frankfurter, J., concurring); F.P.C. v. Hope Nat. Gas Co., 320 U.S. 591, 610, 64 S.Ct. 281, 88 L.Ed. 333 (1944); Cities Service Gas Co. v. F.P.C., 424 F.2d 411, 417 (10th Cir. 1969), petition for cert. dismissed, 400 U.S. 801, 91 S.Ct. 9, 27 L.Ed.2d 33 (1970).
     
      
      . 97 U.S.App.D.C. at 268, 230 F.2d at 818 (emphasis added).
     
      
      . Id. at 268-269, 230 F.2d at 818-819 (emphasis added). Noteworthy is that here, unlike the case in City of Detroit, there is no conclusive evidence that the shift to area rates will definitely produce a price increase.
     
      
      . F.P.C. v. Hope Nat. Gas Co., 320 U.S. 591, 603, 64 S.Ct. 281, 288, 88 L.Ed. 333 (1944). See generally Leventhal, Vitality of the Comparable Earnings Standard for Regulation of Utilities in a Growth Economy, 74 Yale L.J. 989 (1965).
     
      
      . Cases cited note 81, supra.
      
     
      
      . This is not to say that non-cost factors are an impermissible ingredient of a rate structure. See Permian Basin Area Rate Cases, 390 U.S. 747, 815-816, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968). In limited circumstances, non-cost factors may themselves be adequate to protect the public interest. See United Gas Improvement Co. v. Callery Properties, Inc., 382 U.S. 223, 227-230, 86 S.Ct. 360, 15 L.Ed.2d 284 (1965); Atlantic Ref. Co. v. Public Serv. Comm’n, 360 U.S. 378, 391, 79 S.Ct. 1246, 3 L.Ed.2d 1312 (1959). In most circumstances, however, costs provide a framework within which non-cost factors can be considered and it is this framework which normally gives the terms “just and reasonable” some meaning from the standpoint of the consumer.
     
      
      . See Permian Basin Area Rate Cases, 390 U.S. 747, 769, 88 S.Ct. 1344, 20 L.Ed. 2d 312 (1968). The Supreme Court found little difficulty in harmonizing the Oity of Detroit case with the concept of area rates. Wisconsin v. F.P.C., 373 U.S. 294, 310 n. 16, 83 S.Ct. 1266, 10 L.Ed.2d 357 (1963).
     
      
      . In both the Permian Basin Area Rate Cases, 390 U.S. 747, 792, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968) and the Southern Louisiana Area Rate Cases, 428 F.2d 407, 435 & n. 87 (5th Cir. 1970), the courts indicated that in the future the Commission should indicate more precisely the consequences its orders would have on the natural gas industry. In this case, we think that the Commission has been as precise as the nature of its inquiry permits and the scope of its rule requires for it is difficult in the context of this case to determine the precise consequences of the shift to area rate valuation of pipeline produced new gas. More thorough consideration of the expected consequences will be possible in the context of an actual rate case, for it is the price level actually reached rather than the method of computing it that has the most effect on both the effectiveness of incentives and the pocketbooks of consumers. Cf. Permian Basin Area Rate Cases, 390 U.S. 747, 797-798, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968).
     
      
      . Petitioner contends that if the 12% overall rate of return component included in the Permian Basin and Southern Louisiana area rates is applied to pipeline companies, the yield to equity owners on the capital invested in production activity will range from 20% to 40%. Brief for Petitioner at 45. We do not understand this contention to be that any equity shareholder will actually receive anything approaching this yield on his actual investment since, among other things, a pipeline company’s investment in production activity is only a part of its total investment. See, e. g., I Joint Appendix 329; II Joint Appendix 512 (about 10%).
     
      
      . II Joint Appendix 537 contains a table providing one comparison of the yield on equity to pipelines and independent producers engendered by the same overall rate of return. Prepared by the Pipeline Production Group, the table indicates that a 12% overall rate of return on the rate base would yield 17.71% to equity of a “typical” pipeline company and 13.86% to equity of a “typical” independent producer.
     
      
      . The Commission’s staff essentially agreed with this position and urged the Commission to apply area rates to pipelines but to use a separate rate-of-return component in calculating those rates. 42 F.P.C. at 749.
     
      
      . 34 F.P.C. at 201.
     
      
      . 34 F.P.C. at 845 (presiding examiner’s decision).
     
      
      . 34 F.P.C. at 204. The Supreme Court noted with seeming approval this method of arriving at a 12% figure, holding that the resulting return would be sufficient to maintain the financial integrity of the producers and would not exceed their proper financial requirements. Permian Basin Area Rate Cases, 390 U.S. 747, 806-808, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968). It noted, however, that this so-called comparable earnings test was not the only one available for setting rates. Id. at 806, 88 S.Ct. 1344. See also Southern Louisiana Area Rate Cases, 428 F.2d 407, 424 n. 38 (5th Cir. 1970); Leventhal, supra note 84.
     
      
      . Exceptions were made for leases acquired from other pipelines or affiliates after the date of the Commission’s decision. 42 F.P.C. at 1093. The Commission also provided that pipeline companies could make a showing of “special circumstances” justifying an exemption from area rate treatment. Id. at 1093-1094. While it did not specify what such special circumstances might be, it did indicate that simple inability to recover expenses under the area rate method would not be such a circumstance. 42 F.P.C. at 1091. See also Permian Basin Area Rate Cases, 390 U.S. 747, 770-772, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968); Southern Louisiana Area Rate Proceeding, 40 F.P.C. 530, 614-619.
     
      
      . While much of the embedded debt is relatively low cost, one may expect that some of the oldest and cheapest will have to be replaced in the next few years at higher rates. See Panhandle Eastern Pipe Line Co., 40 F.P.C. 98, 105 (1968); Natural Gas Pipeline Co., 40 F.P.C. 81, 88 (1968). The Commission has noted the recent rise in interest rates. FPC Annual Report 50 (1970).
     
      
      . In this connection, the examiner concluded :
      Historical costing methods, which roll in new and old production expenses distort the almost certain fact that pipeline produced new gas for all companies . . . is about as costly as average independent production.
      42 F.P.C. at 799.
     
      
      . There was testimony in the record to the effect that capital will usually cost a pipeline company less than it will cost an independent producer because the return from transmission activity makes the former investment a safer one. E. g., I joint Appendix 17, 29, 32, 81, 133-134, 168; II Joint Appendix 436. However, there was also evidence from which the contrary conclusion could be drawn. E. g., I Joint Appendix 138-139, 329; II Joint Appendix 534.
     
      
      . There may be some question concerning whether it is accurate to refer to taxes as “costs”. Nevertheless, they do have the same effect on rates as other costs incurred in carrying on the enterprise. See City of Chicago v. F.P.C., 128 U.S.App.D.C. 107, 111, 385 F.2d 629, 633 (1967), cert. denied, Public Service Comm. v. F.P.C., 390 U.S. 945, 88 S.Ct. 1028, 19 L.Ed.2d 1133 (1968).
     
      
      . Internal Revenue Code of 1954, §§ 611-613, as amended, Tax Reform Act of 1969, Pub.L. No. 91-172, § 501, 83 Stat. 629.
     
      
      . Internal Revenue Code of 1954, § 263 (c).
     
      
      . Internal Revenue Code of 1954, § 167, as amended, Tax Reform Act of 1969, Pub.L. No. 91-172, §§ 441, 521(d), 83 Stat. 625, 653.
     
      
      . E. g., Cities of Lexington, Ky. v. F.P.C., 295 F.2d 109 (4th Cir. 1961); El Paso Nat. Gas Co. v. F.P.C., 281 F.2d 567 (5th Cir. 1960), cert. denied, State of California v. F.P.C., 366 U.S. 912, 81 S.Ct. 1083, 6 L.Ed.2d 236 (1961).
     
      
      . Initially, savings resulting from depletion and intangible deductions were distinguished from savings resulting from accelerated depreciation under § 167(b) (2) on the ground that the former were true savings while the latter were only deferrals. See City of Detroit v. F.P.C., 97 U.S.App.D.C. 260, 230 F.2d 810 (1955); cases cited note 103, supra. The Commission later changed its views on accelerated depreciation, holding that, in an expanding industry, savings resulting from accelerated depreciation were true savings and not simply deferrals. City of Chicago v. F.P.C., 128 U.S.App.D.C. 107, 385 F.2d 629 (1967); Alabama-Tennessee Natural Gas Co. v. F.P.C., 359 F.2d 318 (5th Cir. 1966).
     
      
      . Petitioner does not object, as it probably cannot, to the fact that area rates mean that some pipeline companies will pay more taxes than they are allowed under the area rate.
     
      
      . See, e. g., Panhandle Eastern Pipe Line Co. v. F.P.C., 113 U.S.App.D.C. 94, 97-98, 305 F.2d 763, 766-767 (1962); cases cited note 96, supra.
      
     
      
      . 42 F.P.C. at 750-751.
     
      
      . Southern Louisiana Area Rate Proceedings, 40 F.P.C. 530, 581-586 (1968); Permian Basin Area Rate Proceedings, 34 F.P.C. 159, 206-207 (1965).
     
      
      . The Commission’s staff has itself raised this possibility. II Joint Appendix 730: “It may be correct that the independent producer area rate is overstated insofar as it does not allow for a negative tax credit or consideration of tax losses generated by the production function in the area rate of return component.” The staff, however, would solve this problem by fixing a separate tax component for each pipeline company.
     