Skelly Oil Co. v. Federal Power Commission

375 F.2d 6, 26 Oil & Gas Rep. 237, 1967 U.S. App. LEXIS 7708

Opinion

BREITENSTEIN, Circuit Judge.

The first area rate decision of the Federal Power Commission is before us for review. It relates to prices for jurisdictional sales of natural gas produced in the Permian Basin, a famous petroleum area where oil and gas are found in hundreds of reservoirs and thousands of wells. The states of Texas and New Mexico, the nation’s oil and gas industry, and several related associations attack the decision. The State of California, the cities of San Francisco, Los Angeles, and San Diego, various local distributors, and an organization of such distributors support it. The rejection of the individual company cost-of-serviee approach to the regulation of independent producers and the adoption of the area rate method raise many novel issues which have been extensively and ably argued. We hold that neither the United States Constitution nor the Natural Gas Act bars the regulation of natural-gas prices on an area basis; that the Commission did not abuse its discretion in adopting the area method; and that the cases must be remanded because the actions of the Commission do not comply with the end result test established in Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 602-603, 64 S.Ct. 281, 88 L.Ed. 333, and other decisions.

The petitions for review, all brought under § 19(b) of the Natural Gas Act,¹ attack Opinions Nos. 468 and 468-A of the Commission fixing just and reasonable rates under §§ 4 and 5 of the Act for natural gas produced in the Permian Basin and sold to interstate pipeline companies.

1. Background.

The Permian Basin, as defined by the Commission, includes Texas Railroad Commission Districts Nos. 7-C, 8, and 8-A and the New Mexico counties of Chaves, Eddy, and Lea. Nationally, it accounts for about 11% of all the gas sold in interstate commerce. The Commission joined 336 producers as respondents in the consolidated proceedings. Sales by them are made to three interstate pipelines, none of which appear here.² About 85% of the Permian gas moving interstate goes to California.

Nearly two-thirds of the Permian gas production comes from oil-well gas, that is, gas produced in conjunction with oil. Because of impurities much of the gas must be processed before introduction to an interstate pipeline. Until El Paso began its purchases, Permian oil-well gas was generally vented or flared because of the lack of a market.

The natural-gas industry has three main parts, the producers, the interstate pipelines, and the distributors. The last are under state or local regulation exclusively. The Commission began federal regulation of the interstate pipelines after the passage of the Natural Gas Act of 1938. It did not attempt to regulate independent producers³ until the 1954 decision of the Supreme Court in Phillips Petroleum Co. v. State of Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (First Phillips) which held that the Act applied to them.

Section 7 of the Act forbids the sale of natural gas subject to Commission jurisdiction without a certificate of public convenience and necessity granted after notice and hearing. Temporary certificates, issued without notice and hearing, are authorized. Our recent decision in Sunray DX Oil Company v. Federal Power Commission, 10 Cir., 370 F.2d 181, discusses § 7 procedures and problems. These are not present here because the § 7 applications considered in the consolidated proceedings before the Commission were disposed of in a separate order.

Section 4 requires that all rates shall be just, reasonable, and nondiscriminatory. No change shall be made in a rate without 30 days’ notice. When a schedule containing a changed rate is filed, the Commission on its own initiative or on complaint may suspend the rate and set the matter for hearing. The suspension may be for not longer than five months. If no decision is reached within that period, the increased rate becomes effective but the Commission may require a bond conditioned upon the refund of that portion of the increased rate found not to be justified. The instant proceedings involve a number of increased rate filings which were suspended under § 4 and which were disposed of by Opinions Nos. 468 and 468-A.

Section 5 provides that whenever the Commission, after hearing had on its own motion or on complaint, finds that a rate is “unjust, unreasonable, unduly discriminatory, or preferential” it shall determine “the just and reasonable rate.” In the proceedings at bar the Commission pursuant to § 5 established “the future rates for jurisdictional sales of gas by producers in the area.”

After the First Phillips decision the Commission received thousands of certificate applications from producers. The situation was complicated by the need of pipelines for a committed source of supply sufficient to justify financing. To obtain such supply, long-term contracts, commonly for 20 years, were made with the producers. They in turn, because they could not file unilaterally for an increased rate contrary to contract and because they desired protection against the unforeseeable economic conditions of the future, insisted on escalation clauses of various types.⁴ A general price rise occurred. As the escalation provisions became operative the producers filed under § 4 for increased rates and the Commission suspended many of them. Section 7 applications were under contracts calling for rates comparable to those which the Commission had suspended. This trend was ended by the 1959 decision in Atlantic Refining Co. v. Public Service Commission of New York, 360 U.S. 378, 79 S.Ct. 1246, 3 L.Ed.2d 1312 (CATCO) which directed the Commission in certificate cases to keep initial prices in line.

After the remand in First Phillips, the Commission proceeded with the consideration of just and reasonable rates required by §§ 4 and 5 on the individual company cost-of-service basis which it had long applied in the regulation of electric power companies and interstate pipelines. The first case to reach the decisional stage was that relating to Phillips. On September 28, 1960, the Commission entered Opinion No. 338⁵ in which it held that the regulation of independent producers under the Act could be accomplished more appropriately by the establishment of area rates than by the establishment of producer rates on individual cost-of-service findings. Contemporaneously with this Phillips decision, the Commission promulgated its Statement of General Policy No. 61-1⁶ which established 23 rate areas and, with unimportant exceptions, announced maximum rates for each area. Two price standards were set, one for initial prices in new contracts and one for escalated prices in existing contracts. For the Permian Basin area the prices were 16 cents and 11 cents respectively.

Opinion No. 338 was affirmed by the Court of Appeals for the District of Columbia Circuit⁷ and by the Supreme Court in State of Wisconsin v. Federal Power Commission, 373 U.S. 294, 310, 83 S.Ct. 1266, 1275, 10 L.Ed.2d 357, (Second Phillips) wherein the Court observed that it shared “the Commission’s hopes that the area approach may prove to be the ultimate solution” to the problem of regulating the independent producers.

The first area rate proceeding was that for the Permian Basin and was initiated on December 23, I960.⁸ It was followed by a similar proceeding for the South Louisiana area,⁹ for the Hugo-ton-Anadarko area,¹⁰ and for the Texas Gulf Coast area.¹¹ The last three are in the hearing stage. The Permian Basin proceeding was decided by Opinions Nos. 468 and 468-A to which we turn

2. The Decision of the Commission.

The 131-page original opinion, No. 468, followed by the 23-page opinion denying rehearing, No. 468-A, need only be summarized at this point. The Commission found the area rate principle free from constitutional and statutory objections and adopted it. Contract prices were rejected as a basis for regulation and the reserves to production ratio was declared to be an inappropriate regulatory standard. The Commission set up a two-price system. It differentiated between gas produced as the sole product of a well, referred to as gas-well gas, and gas produced in association with oil, known as oil-well gas or casinghead gas. One price was established for new gas-well gas and the residue therefrom sold under contracts made on or after January 1, 1961. A second price was established for flowing gas which was defined to include gas-well gas sold under contracts executed before the mentioned date, casinghead gas, and residue gas derived from either source. The January 1,1961, date of division between new gas-well gas and old gas-well gas was adopted because that was the approximate date when the industry became able to direct its exploration efforts toward finding gas-well gas as distinguished from finding gas as a by-product in the search for oil. For new gas-well gas the Commission fixed a rate of 16.5 cents per Mcf for the Texas Railroad Districts inclusive of state and local taxes and a rate of 15.5 cents per Mcf for the New Mexico counties exclusive of applicable state and local production taxes. For flowing gas the respective rates were 14.5 cents and 13.5 cents.

In determining these rates the Commission gave consideration to composite costs but treated the two categories of new gas-well gas and flowing gas differently. It said that the price of the former “was geared to the cost of finding and producing future gas supplies and as such was built up primarily from nationally published statistics and the questionnaire data.” For flowing gas it said “our touchstone is the historical cost of gas being produced in the Permian Basin area.”

The Commission required adjustment on an individual company basis from the stated prices to reflect differentials from the quality standards. These downward adjustments are determined “by the net cost of processing the gas to bring it up to standard.” A downward adjustment is also required if the Btu content is less than 1,000 per Mcf and an upward adjustment is permitted if that content is above 1,050.

Small producers, defined as those making less than 10 million Mcf of jurisdictional sales annually, are exempt from the quality adjustments and from certain filing requirements.

The Commission set a minimum price of 9.0 cents per Mcf. Provision is made for special exemption from area rates. Refunds of excess collections are required on an individual company basis. The possibility of changes in area rates is recognized. A moratorium, until January 1, 1968, is declared on rate increases and indefinite escalation clauses are prohibited.

Three commissioners filed separate opinions. With one exception Commissioner O’Connor approved the results reached but said that “the contract price at which most producers are able and willing to operate is just and reasonable” and that “composite costs best serve as a check on average field prices to preclude significant price departures.” He disapproved the Btu adjustment saying that an upward adjustment should be applied for all gas having a Btu content in excess of 1,000. Commissioner Ross was critical of accounting methods used and pointed out the need for simplification. He dissented from the division date between new and old gas-well gas. In his view the new gas-well gas price should apply to gas sold after the date of the Commission decision. Commissioner Black said that the allowed 12% rate of return on net investment “is very probably a generous one” but was justified by the special risk of finding substandard gas in the Permian Basin.

3. Disqualification of Two Commissioners.

The Continental Group of petitioners urges that Commissioner Black was disqualified to participate in the decision. The Independent Petroleum Association of America, (IPAA) complains of the participation of both Commissioners Swidler and Black. The claim is that each of them had prejudged the issue of whether substantial competition existed among producers. Additionally, Commissioner Black is accused of personal . bias against the producers. The charges stem from public addresses made in 1964.¹² No claim is made that either commissioner prejudged the ultimate issue of a just and reasonable rate. In our opinion no basis for disqualification arises from the fact or assumption that a member of an administrative agency enters a proceeding with advance views on important economic matters in issue. Nothing in the record disturbs the assumption that the two commissioners are “men of conscience and intellectual discipline, capable of judging a particular controversy fairly on the basis of its own circumstances.”¹³ The cases cited by Continental and IPAA are not in point.¹⁴

4. Objections of Texas and New Mexico.

The states of Texas and New Mexico, besides adopting the briefs and arguments of the Continental Group, assail the Commission decision on grounds peculiar to them in their governmental capacity. They say that the public interest, which the Commission is required to protect, includes the producing states as well as the consuming states; that the prices which the Commission has set will cause a cessation or curtailment of exploration and development activities to the serious injury of the economy of the Permian Basin; that waste rather than conservation of a natural resource will result; and that the states and their public entities will suffer severe losses in taxes and royalty payments.¹⁵ Similar arguments were made by West Virginia in Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 607-614, 64 S.Ct. 281, 293, 88 L.Ed. 333, and were rejected by the Supreme Court which said that when Congress passed the Natural Gas Act it “was quite aware of the interests of the producing states in their natural gas supplies” and that nothing in the Act intimates that high prices should be maintained so that “the producing states obtain indirect benefits.” The rejection of the state’s contentions in Hope requires the rejection of the same contentions here.

Texas and New Mexico also argue that the Commission has unlawfully interfered with their power of taxation. The Commission fixed the rates of gas produced in Texas to include all state taxes and in New Mexico to exclude such taxes. It said that: “In the event of any increase in taxes in Texas or New Mexico, the Commission will consider whether ceiling prices shall be increased and, if so, to what extent.” The states’ arguments are premature. The Commission has allowed all present taxes as a cost item. Nothing in the Commission decision inhibits the states from increasing those taxes. The Commission has said that if they do, it will determine whether such increases should be passed on to the consumer or remain on the shoulders of the producers. The question of whether increased state taxes will unreasonably burden interstate commerce is hypothetical at this stage.

New Mexico complains that the establishment of a ceiling price plus existing taxes for gas produced in its por tion of the Permian Basin denies to it the power to provide a tax incentive to producers by reducing the tax. The argument is not persuasive. If the New Mexico tax was reduced, the Commission could properly consider a rate decrease to reflect the tax decrease.

5. Legality of Area Rates for Permian Basin.

The problems confronting federal regulation' of the natural-gas business, and particularly the independent producers, have been discussed several times¹⁶ and need be only summarized. The interstate gas business is concerned with a wasting, nonreplenishable natural resource subject to production after discovery. At the point where the gas enters interstate commerce there are few buyers and thousands of sellers. The producers range from the financially powerful integrated oil companies to the wildcatters who operate on a shoestring. Their results are measured by the amount of gas produced — not by the amount of money invested. Exploration and development costs are financed out of current income and are charged to expense rather than capital. The uncertainty of the business causes substantial cost and revenue fluctuations not only from producer to producer but also from year to year for the same producer. A regulated commodity, gas, is produced in substantial quantities along with an unregulated commodity, oil. The allocation of costs between them baffles the experts and presents the temptation to use mathematical means of arriving at a predetermined result. The same rate may bring a financial windfall to one producer and a financial disaster to another. The price of gas must be competitive with that of other sources of energy and must be sufficiently attractive to encourage a continued search for new supplies.

In Federal Power Commission v. Natural Gas Pipeline Co., 315 U.S. 575, 582, 62 S.Ct. 736, 86 L.Ed. 1037, a case relating to pipeline rates, the Court held that the provisions of the Act were consistent with the due process clause of the Fifth Amendment and within the commerce power. Another pipeline case, Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 287, 88 L.Ed. 333, says that in fixing rates the Commission is “not bound to the use of any single formula or combination of formulae”; that “[u]nder the statutory standard of ‘just and reasonable’ it is the result reached not the method employed which is controlling”; and that the impact of the rate order rather than the theory behind it is the governing criterion. The “end result” test of Hope was followed in Colorado Interstate Gas Co. v. Federal Power Commission, 324 U.S. 581, 605-606, 65 S.Ct. 829, 89 L.Ed. 1206.

Second Phillips, 373 U.S. 294, 83 S.Ct. 1266, 10 L.Ed.2d 357, holds that the Commission did not abuse its discretion in terminating the § 5 investigation of Phillips’ rates and substituting an area basis for an individual company basis. The Court reaffirmed the principles announced in Natural, Hope, and Colorado Interstate, recognized the difficulties in herent in the regulation of the price of natural gas, shared the Commission’s hope for the success of the area approach, and observed that the “case might be different if the area approach had little or no chance of being sustained”.¹⁷ At the same time, the Court pointed out that “the lawfulness of the area pricing method” was not before it for review.¹⁸ Four justices dissented in an opinion which characterized the area rate policy of the Commission as “a new, untried, untested, inchoate program which, in addition, is of doubtful legality.” ¹⁹

In Callery ²⁰ the Court mentioned that the § 7 proceedings before It had at one time been consolidated with the South Louisiana area rate proceedings. Contrary to the argument of the California Distributors the Court did not, tacitly or otherwise, approve area rate regulation. The most pertinent comment is that of Justice Harlan in his concurring and dissenting opinion who said that area pricing “ultimately aims to simplify proceedings under the statute”.

Footnotes

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20a.

We cannot accept the arguments of the Commission and the California groups that the Supreme Court has determined the validity of area pricing under the Act. We read the decisions to mean that the Court has permitted the Commission to go forward with the area rate experiment and wishes it good luck in the development of a workable procedure which will be free from constitutional and statutory pitfalls.

Governmental price regulation of services and commodities on a group or geographical basis has been upheld in a number of decisions²¹ under the federal commerce and war powers and under state police powers. Those supporting the Commission place great reliance on these decisions. The producers painstakingly distinguish each from the case at bar. We decline to be drawn into these tortuous sidepaths because we are convinced that the “[translation of an implication drawn from the special aspects of one statute to a totally different statute is treacherous business.” ²² Specific reference need be made to only one decision. Several producers emphasize the statement in Bowles v. Willingham, 321 U.S. 503, 517, 64 S.Ct. 641, 648, that in the Natural Gas Act “Congress has provided for the fixing of rates which are just and reasonable in their application to particular persons or companies.” The argument is that by this language the Supreme Court has recognized that regulation under the Act is on an individual company rather than group basis. We do not agree. The statement is dicta and whatever value it might have had as dicta was, in our opinion, destroyed by the blessing which the Court gave area rate making in Second Phillips.

Producers urge that the language of the Act is contrary to regulation on a group basis because all pertinent references to natural-gas companies are in the singular. First Phillips holds that an independent producer is a “natural-gas company” within the purview of the Act. Section 2, the definitions section, provides that “person” means an individual or corporation, and defines “natural-gas company” to mean a person engaged in transportation or sale of natural gas in interstate commerce. Section 4, covering the filing and changing of rates, refers to “any natural-gas company,” “no natural-gas company,” “every natural-gas company,” and “the natural-gas company.” Section 5, authorizing investigation and determination of rates, refers to “any rate,” by “any natural-gas company” and to “such natural-gas company.” Section 7 provides for certificates of public convenience and necessity and uses the terms “a natural-gas company,” “no natural-gas company” and “such natural-gas company.” The repeated use of the singular rather than the plural is said to require that the just and reasonable rate of each particular seller be tested with reference to its peculiar circumstances and operations.

Opposing arguments point out that the Act does not prohibit group or area rate making and that § 16 empowers the Commission to perform any and all acts and to prescribe such orders, rules, and regulations “as it may find necessary or appropriate to carry out the provisions of this act.”

The basic query is whether the just and reasonable standard applies on an individual company basis or on a group basis. Section 4(a) says that “[a]ll rates * * * made * * * by any natural-gas company * * * shall be just and reasonable * * *.” If this means that each producer is entitled to a rate which will return its costs plus a reasonable profit, the inquiry is at an end because the Commission refused to receive individual cost figures.

The Natural, Hope, Colorado Interstate, and Second Phillips decisions all support the conclusion that in the regulation of natural-gas rates the Commission is not bound by any formula or method, and that the choice of the appropriate method for the determination of those rates lies in the sound discretion of the Commission. The appropriateness of the method depends on the peculiar characteristics of the natural-gas industry.

In its Opinion No. 338,²³ the Commission noted the reasons why the individual company cost-of-service method was inapplicable and unworkable. Among these were the lack of a fixed determinable relationship between investment and service to the public with the result that “a huge investment might yield only a trickle of gas, while a small investment might lead to a bonanza,” the staggering allocation problems which could result in such anomalies as widely varying prices for gas coming from a jointly owned lease or even from a jointly owned well, and the intolerable administrative burden of requiring a separate rate determination for each of the several thousand independent producers.

The powerful contrary argument is that no area rate, whether based on composite costs, average aggregate costs or any other industry wide criteria, will suffice to assure a high cost producer of its costs to say nothing of a profit. We accept this as true.²⁴ The impact of an area rate in the natural-gas industry may have effects which cover the entire range from bonanza to bankruptcy. It is sufficient for us that these results were lucidly demonstrated in the dissenting opinion of Justice Clark in Second Phillips and did not deter the majority from allowing the Commission to proceed with its area rate program.

Some of the producers argue that if the Act is construed to permit area rate making, the Act is invalid under Art. I, § 1, of the United States Constitution because no legislative standards have been set for establishing groups or making group determinations. Reliance is had on Panama Refining Co. v. Ryan, 293 U.S. 388, 55 S.Ct. 241, 79 L.Ed. 446, which held that a delegation of legislative power to the President was unconstitutional because Congress, among other things, “has declared no policy, has established no standard, has laid down no rule.” ²⁵

Congress cannot delegate its power to enact laws but it can confer on an administrative agency the power to carry into effect laws which it has enacted.²⁶ In the New England Divisions Case, supra, the Court referred to the power given by Congress to the Interstate Commerce Commission to determine just and reasonable rates and said that Congress “intended that a method should be pursued by which the task * * * could be performed.” ²⁷ In Lichter v. United States, 334 U.S. 742, 785-786, 68 S.Ct. 1294, 1316, 92 L.Ed. 1694, the Court in discussing legislative standards said that the “[standards prescribed by Congress are to be read in the light of the conditions to which they are to be applied” and for an example observed that “among those which have been held to state a sufficiently definite standard for administrative action: [are] ‘[j]ust and reasonable’ rates for sales of natural gas”.

In the regulation of the natural-gas industry “the actual necessities of procedure and administration” ²⁸ have led to the adoption of the area rate method. We believe that neither constitutional nor statutory provisions prevent the use of that method and that the Commission did not abuse its discretion in adopting it. The more important and difficult question is that of the validity of the area rates which have been established. The controlling standard is the end result test of Hope. In our opinion, this test is accepted by, and reaffirmed in, the Second Phillips decision.

Some of the producers urge that the area rate method is not consistent with the characteristics of the industry and that contract prices satisfy statutory requirements because they have been reached through effective competition. The Commission considered and rejected the argument. It pointed to the history of price negotiations in the Permian Basin, to the urgent requirements of the pipelines, to the heavy percentage of sales by a few producers, and to the control of undisclosed and uncommitted gas reserves by a few producers. It concluded that the record fails to establish that a just and reasonable rate can be established through competition and that “the primary competition revealed by the record was among the pipelines to secure new gas supplies at higher prices.” Commissioner O’Con-nor disagreed saying that “the contract price at which most producers are able and willing to operate is just and reasonable.” His conclusion was that “profit oriented costs and supply oriented contracts do not, in the aggregate, depart in any significant manner from each other.” We accept the conclusion of the Commission that competition has not been effective to fix a just and reasonable rate. It is supported by reasonable inferences from the record and they are binding on us.

Continental and Superior say that they were improperly denied an opportunity to be heard on the geographical propriety of the Permian Basin as a rate area. In its order instituting the proceedings the Commission eliminated the issue of the appropriateness of the area for rate making purposes.²⁹ The Commission may draw on its expertise to determine the ground rules for an investigation but in so doing may not deny a specific right.³⁰ The producers fail to convince us that any such denial has occurred here. The Permian Basin is a well known area. Unless prices are to be determined on a national basis, areas must be selected and defined. The Commission had two choices. It could first determine the national revenue requirement and divide that up among the areas or it could first determine the various rates so that in the aggregate they meet that requirement. We are unwilling to assume that when all the area proceedings are completed the total revenue will not equal the national requirement. If it does not, both the producers and the consumers will suffer. In our opinion the Commission acted reasonably in selecting the Permian Basin for an area rate proceeding.

6. The Two-Price System.

The Commission’s two-price system is vigorously attacked on many fronts. It will be remembered that one price is fixed for new gas-well gas and another for flowing gas. All agree that gas is a commodity which is valuable as a source of energy. The householder does not care whether the gas which burns at the tip of his appliance comes from a gas well, an oil well, or as a residue product. To him gas is gas.

The justification for the two-price system is that the higher price for new gas-well gas provides an incentive to explore for and develop new supplies. The producers do not question the finding that “the industry is increasingly becoming able to direct its exploration efforts toward finding new gas-well gas as distinguished from finding gas as a by-product in the search for oil.” This ability may be confined to the larger companies which maintain the technical staffs skilled in making the necessary predictions. The smaller producers are in a less advantageous position. They may be relegated to the farmouts which the majors pass down to them or to operations in accord with their less scientific but sometimes financially rewarding hunches.

New gas discoveries are well said to be the life blood of the industry. The consumers may reasonably be required to pay the price needed to bring forth such discoveries. If an incentive price based on current costs is used for all gas, windfalls will be assured to many producers of old gas developed under lower historical costs and often found in association with oil.

The producers say that a single-price system based on current costs is required because revenues for current exploration and development must be internally generated from sales of gas from whatever source. The Commission rejected the argument. The question is not so much the source of the funds as it is the inducement to use available funds in the search for gas. The higher price for new gas is intended to supply that inducement. Although the adequacy of the inducement can only be tested by future developments, we are not convinced that the refusal of the Commission to include the same inducement in the price of old gas, with the resulting likelihood of windfalls, was unreasonable.

Continental, Phillips, and others argue that the two-price system amounts to entrapment because of the possibility of reduction in price after financial commitments have been made. Although the Commission which announced the Permian Basin decision cannot bind a future Commission, we credit the Commission with good faith. The possibility of a change does not invalidate the rate method employed. When and if a reduction occurs, the argument of entrapment can be heard.

The division date of January 1, 1961, for the different prices of new gas-well gas and old gas-well gas is another subject of dispute. Here the Commission found as a fact that the appropriate date was the approximate time when directional drilling came to be used effectively. Under the evidence the selection of a division date was an administrative problem calling for the exercise of judgment. In making its choice the Commission acted within the evidence and within its powers. On rehearing, the Commission left open for future consideration the problem arising when new gas-well gas is developed from committed acreage. We assume that this problem will be met fairly when it comes to a head.

The two-price system is an outgrowth of directional drilling for gas. Its purpose is to assure a continued gas supply. The Commission frankly says that the adoption of the system for the Permian Basin “should serve to furnish a practical test of whether in fact it will result in bringing forth additional supplies.” We find no persuasive reason why the test should not be made.

7. The Cost Information.

In arriving at the Permian Basin rates the Commission used many sources of cost information. These included responses to questionnaires sent to producers, the Census of Mineral Industries for 1958, the Chase Manhattan Bank’s 1961 Annual Analysis of the Petroleum Industry, the World Oil Magazine, the Oil and Gas Journal, the Joint Association Survey,³¹ and others. The producers attack these sources on many and varied grounds. The range of objections runs from hearsay evidence through deprivation of right of cross-examination to denial of procedural due process. To take up each of these objections would increase the length of this opinion to encyclopedic dimensions.

From the information so obtained the parties, the staff, and the Commission make many computations and reach many results. The assumptions, allocations, formulae, equations, averages, means, and massive calculations may intrigue a mathematician or statistician but they have no attraction for us. We respectfully decline to be drawn into such a turmoil of numbers. We cannot in a few months unravel the snarl of statistics developed in the years of hearings. In our opinion the judicial process, in cases such as this, should be confined to consideration of errors of law. We leave to the experts the selection of source material and the calculations to be made therefrom. Our concern is with the result.

8. The Commission’s Price Determinations.

The Commission said that “costs must be a major factor in determining the area price.” On the basis of current national statistics plus questionnaire data it determined the 1960 Mcf cost of new gas-well gas thus:

Exploration and Development Costs

Dry Holes........................................ 1.42 cents

Other Exploratory Costs........................... 1.59

Adjustment for Exploration in

Excess of Production............................ 1.11

Production Operating Expense........................ 2.70

Net Liquid Credit.................................. (3.10)

Regulatory Expense...................................14

Depletion, Depreciation, and Amortization of Production Investment Costs

Successful Well Costs ............................. 2.88

Lease Acquisition Costs.............................76

Cost of Other Production Facilities...................31

Return of Production Investment (at 12%).............. 5.21³²

Return on Working Capital...........................35

Subtotal .............13.37

Royalty at 12%% ................................... 2.05

Production Taxes ................................... 1.01

Total ................16.43

The Commission rounded this figure ■off at 16.5 cents for the Texas production. Because the New Mexico figure is exclusive of taxes a reduction of one cent was made in the New Mexico price.

For the costing of flowing gas the Commission used historical data developed by the industry questionnaires. The results may be summarized thus:

Production operating expenses........................ 1.75 cents

Depreciation, depletion and amortization.............. 2.42

Return at 12%...................................... 4.99

Exploration and development......................... 4.08

Regulatory expense ..................................14

13.38

State production tax at 7% .......................... 1.01

14.39 ³³

This figure was rounded off at 14.5 cents for Texas and 13.5 cents for New Mexico. As a check on the method used the Commission back trended the new gas-well gas figures and arrived at a 14.64-cent price.

The rates so established are subject to downward adjustment because of quality deficiencies and to both downward and upward adjustments on the basis of Btu content. The Commission disclaims any intent that the rate figures show producer costs. It says that the price of new gas-well gas is “geared” to costs derived from national statistics and the questionnaire data and that for flowing gas the “touchstone” is the historical price of Permian gas.³⁴ Other undefined and unidentified “factors” were taken into consideration.

9. The Moratorium.

The Commission implemented the price provisions of the decision in various ways. It imposed a moratorium on rate increases until January 1, 1968, “except in compliance with a specific order of the Commission for a rate as determined pursuant to said proceeding [AR61-1] or pursuant to later order of the Commission.” The producers say this violates the Act because § 4 permits filings for rate increases. Section 4 must be read with other sections of the Act. Section 5 authorizes the Commission to determine the just and reasonable rate “to be thereafter observed and in force.” Section 16 gives the Commission power to make such orders “as it may find necessary or appropriate to carry out the provisions of this act.” In Callery the Court held that there was ample power under § 7(e) to impose a moratorium.³⁵ We believe that there is also ample power under §§ 5(a) and 16. The reasonableness of the exercise of the power is established by the need for price stability, the Commission’s expressed willingness to reopen the proceedings to consider the propriety of changes, and the expiration date which is only about a year off.

10. The Escalation Clauses.

The Commission’s order forbids the filing of rate changes in excess of applicable area rates when the contractual right thereto is based on indefinite escalation clauses not permitted by § 154.93 (a), (b), and (c) of the Regulations under the Natural Gas Act. The producers say that this provision destroys existing contract rights. The Commission replies that it has not proscribed the clauses but merely the right to file under them. This is a thin distinction. In Pan American Petroleum Corporation v. Federal Power Commission, 10 Cir., 352 F.2d 241, 245, we upheld § 154.93 and pointed out that if a producer felt aggrieved thereby it could apply for a rule waiver under § 1.7(b) of the Commission’s Rules of Practice and Procedure. We assume that a similar request could be made under the Permian order. When the request is made and rejected, the time will arrive for the consideration of the constitutional questions which the producers raise.

11. The Commission’s Fair Relationship Standard.

In fixing the amounts of the area rates the Commission rejected the end result test and adopted a fair relationship standard. This appears clearly from Opinion No. 468-A. After disclaiming that it had made any finding that “jurisdictional revenues will equate to jurisdictional costs,” the Commission said:

“ * * * we are convinced that the record fully justifies the Commission’s judgment that the ceiling prices we have fixed ‘provide a fair relationship between the aggregate price the consumer pays and the aggregate costs that the producers incur’ in the Permian Basin.”

Hope says that in the fixing of just and reasonable rates there must be a “balancing of the investor and the consumer interests.”³⁶ It goes on to say that from the company point of view the revenue must not only provide operation expense but also capital costs including “service on the debt and dividends on the stock”; and that the return to the equity owner must be commensurate “with returns on investments in other enterprises having corresponding risks” and “sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital.”³⁷ The Court concluded the discussion of this problem with the observation that in Hope the “end result” could not be condemned as unjust and unreasonable.

In Colorado Interstate Gas Co. v. Federal Power Commission, 324 U.S. 581, 605, 65 S.Ct. 829, 840, 89 L.Ed. 1206, the Court, after referring to the Natural and Hope decisions said:

“In those cases we held that the question for the courts when a rate order is challenged is whether the order viewed in its entirety and measured by its end results meets the requirements of the Act.”

Also pertinent is the statement of the Court in Second Phillips that:³⁸

“To whatever extent the matter of costs may be a requisite element in rate regulation, we have no indication that the area method will fall short of statutory or constitutional standards. The Commission has stated in its opinion in this proceeding that the goal is to have rates based on the ‘reasonable financial requirements of the industry’ in each production area, * * * and we were advised at oral argument that composite cost-of-service data will be considered in the area rate proceedings.”

Nothing in Second Phillips rejects the end result test of Hope. We believe that it applies here and that it is not satisfied by a finding of fair relationship. Something more than mere semantics is involved. The determination of a fair rate from the standpoint of the consumers must depend to large extent on the informed judgment of the regulatory agency. In these proceedings no distributor, consumer interest, or consumer representative objects to the rates. They are accepted as just and reasonable.

From the standpoint of the producer the situation is different. It is entitled to recover its prudent operating expenses and capital costs with a return commensurate to the risk and sufficient to attract capital. These requirements must be tested against the record. They may not be brushed aside with a general finding of fair relationship. The Commission concedes that it did not equate jurisdictional costs to jurisdictional revenues. This is obvious because no determination was made of the jurisdictional revenues which the rates will produce.

12. The High Cost Operator and the Small Producer.

The Commission broke down the rates into components which it justified on averages based on national statistics and questionnaire data. We recognize that weighted averages and sifted averages are suspect.³⁹ We accept the principle that both the basic figures and the averages obtained therefrom must be typical and representative but we are not convinced that the Commission has misused its expertise in this technical field. It is self-evident that when average costs are used to compute ceiling prices, the high cost operator will be hurt and some low cost operators may receive windfalls. Probably to a greater extent than in any other comparable segment of the national economy the element of chance can affect the success or failure of even the most prudent entrepreneur who engages in the natural-gas business.

The problem of the high cost operator is characteristic of group or area rate making. The Supreme Court upheld group rates in Acker v. United States, 298 U.S. 426, 431, 56 S.Ct. 824, 827, 80 L.Ed. 1257, and commented that “regulation cannot be frustrated by.a requirement that the rate be made to compensate extravagant or unnecessary costs”. In Tagg Brothers & Moorhead v. United States, D.C.Neb., 29 F.2d 750, 755, affirmed 280 U.S. 420, 50 S.Ct. 220, 74 L.Ed. 524, the court said that it was not necessary “to fix the rates so high that all agencies in the business would make money.” Covington & Lexington Turnpike Road Company v. Sandford, 164 U.S. 578, 596, 17 S.Ct. 198, 205, 41 L.Ed. 560, says that “[t]he public cannot properly be subjected to unreasonable rates in order simply that stockholders may earn dividends.”

The small producers, represented here by Big Chief Drilling Company, IPAA, Texas Independent Producers & Royalty Owners Association (TIPRO), J. C. Barnes, and others, join in the prediction that the Permian decision sounds the death knell of the small producers. Perhaps the flamboyant wildcatter must be replaced by the scientists of the industrial giants but the efforts of the boom- or-bust adventurers have contributed greatly to natural-gas discoveries. In its decision the Commission referred to the “smaller independent who traditionally drills much of the Permian exploratory acreage” and said that: “Consumers and the natural gas industry alike have a strong stake in the continuation of the exploration efforts of the thousands of small operators who contribute a large share of the discoveries of new sources of gas.” ⁴⁰

The Commission took note of the suggestions that small producers should be exempt from regulation.⁴¹ It found that outright exemption was neither necessary nor desirable but said that the small producers needed “special treatment.” To this end it defined a small producer as “a natural gas company selling jurisdictionally less than 10,000,-000 Mcf annually on a nationwide basis.” They were granted relief from various requirements of §§ 7 and 4 and were freed from rate adjustments because of quality differentials. In our opinion the classification is reasonable and within the Act.

The small producers do not seek complete exemption. Their attitude is that such relief would be illusory rather than real because the pipelines would not pay more for gas supplied by them than the price paid to the major companies. Their complaint is that the Commission did not give adequate consideration to small producers’ costs.

Data covering the costs of Permian producers came from questionnaires which are classified as Appendix B and Appendix C. The Appendix B group was mandatory for producers with company-wide jurisdictional sales of over 10 million Mcf and optional for others.⁴² The Appendix C questionnaires went to the small producers. Forty-two of the majors and 25 of the small producers answered Appendix B. The response to the Appendix C questionnaires was sporadic. The Commission used only the material supplied by the majors saying that the inclusion of the data supplied by the small producers “does not affect the results.”

TIPRO and Big Chief both emphasize the testimony of a staff witness that the small producer questionnaire showed average unit costs 2 cents per Mcf higher than those of the majors. They argue that the end result standards must be applied not only to the entire group but to them as a group. The weakness of the argument is that once the whole group is split the process can be carried on until the regulation is back on an individual company basis.

We do not know the answer to the small producer problem. Superficially it seems unfair to fix ceiling prices for all producers, both large and small, on the basis of the costs of large producers only. The Commission rejected the small producer data because in its opinion the impact on the rate structure was de minimis. On the record presented, we are unwilling to say that this conclusion was erroneous as a matter of law.

In any regulation of the natural-gas industry on an area basis the high cost producers, be they majors or little fellows, are certain to be placed in a position less advantageous than that occupied by those whose good fortune and able management have supplied a lower cost base. We agree with the Commission that the expense items included in an individual cost-of-service are not the measure of a confiscatory rate. A producer has no constitutional right to be reimbursed for dry-hole expenses.⁴³ Also it has no obligation to remain in business by replenishing the supplies of gas which form the basis of present obligations. Inability to continue exploration and development is not confiscation. We conclude that the impact of the Permian rates on the high cost producers does not destroy the area rate method.

13. Gathering and Processing Costs.

One subject of much discussion in the briefs is the allowance of the same rate for gas delivered at the tailgate of a processing plant and for gas delivered at the wellhead. Gathering lines cost money and have to be built and operated by someone. The Commission’s position is that the revenues received for oil and oil products derived from condensation and processing return a profit which induces the building of the needed gathering lines and plants. Here again we reach the troublesome field of cost allocations between a regulated commodity, gas, and unregulated commodities, oil and liquified petroleum products.

Bass places particular emphasis on this phase of the case. It points to its extensive investments in gathering lines and plants and to its permanently certificated rate of 18 cents which, it says, the Commission has never specifically found unreasonable or discriminatory. The answer as we see it is that if area rates are proper no greater need exists for the consideration of the individual cost and revenue requirements in the case of Bass than in the case of the other producers. Perhaps in the future courts will have to explore the mysteries of allocations but we are not so inclined in this case. If in fact Bass and others similarly situated are confronted with confiscation, a way must be open for them to be heard.

14. Special Exemptions.

The Commission recognized that some provision must be made for special exemption from area rates. It said that when a producer’s “out-of-pocket expenses in connection with the operation of a particular well are greater than the revenues under the applicable area price, he should be entitled to appropriate relief.” It declined to “specify all of the special circumstances which may serve as a basis for exceptions to the area rate” and observed that failure to earn exploration and development expenses plus the allowed return does not amount to confiscation. In regard to the form of relief it held that “it may be suffi cient to permit them to abandon their unprofitable sales.”

We agree with the Commission that an escape clause cannot be used to convert an area rate into an individual company cost-of-service rate but an escape clause which does no more than prevent an unconstitutional confiscation amounts to nothing. None is needed for that purpose. The producers are right in saying that the Commission’s exemption provisions are so vague and nebulous that neither they nor a court can determine what relief is being granted. Out-of-pocket expenses are not defined and we do not know what they include. If a producer’s accounting is on a lease rather than well basis, the facts relating to a particular well might not be determinable. It may be going too far to say categorically that individual producers should be permitted to show that the group costs are not typical or representative of their costs but in some instances that should be permitted. Conservation of gas is promoted if marginal wells are allowed to continue to produce but is discouraged if the same wells are shut down by a low price. Some producers furnish gathering facilities. Others sell at the wellhead and the pipelines pay for the gathering. Gathering costs are allowed pipelines. Perhaps in some instances they should be allowed to producers. An adequate savings clause should contain guidelines which if followed by an aggrieved producer will permit it to be heard promptly and to have a stay of the general rate order until its claim for exemption is decided. It is not enough to say in effect that confiscation will be prevented. Confiscation is an individual proposition and the individual is entitled to be heard. We are convinced that the Commission’s special exemption provisions are inadequate.

15. Quality Standards.

The Commission provided for adjustments in the area rates to reflect quality differentials. It said that “the price of gas cannot be related to volume alone but must be related to units of energy free of impurities and sufficiently compressed to enter the pipeline.” Standards were fixed for content of carbon dioxide, hydrogen sulphide, total sulphur, water, and other impurities; and the amount of delivery pressure was established. The applicable base area rate is adjusted downward by the net cost of processing the gas to bring it up to standard. Provision is made for both an upward and a downward adjustment of rate depending on the Btu content. Quality statements are required to be filed together with an agreement by the seller and- the buyer covering the cost of bringing the gas up to standard. If an agreement cannot be reached, each shall file a statement of its views on the processing costs.

About 90% of the flowing gas is substandard. We are cited to no figures on the similar percentage of new gas-well gas. The amount of the rate adjustments does not appear in the record because there was no evidence of the extent of quality differentials or of the processing costs of bringing the gas up to standard.⁴⁴ At oral argument various estimates were given as to the amount of rate reduction which would result from substandard quality. These were based on statements filed pursuant to the decision but after the record was closed. They ranged from .7 cents to 2.0 cents per Mcf. A spokesman for the Continental Group said that on 1960 volumes a revenue deficiency of some $12 million a year would result. The Commission response in this court to the Skelly motion for stay of the Commission’s orders herein said that the reductions in applicable rates because of adjustments for quality standards are expected to result in a revenue reduction of about $10 million annually.⁴⁵

The producers’ argument that the imposition of quality standards violates procedural due process because of lack of notice need not be resolved at this time. We are remanding the case and now everyone has notice. The matter of the Btu adjustments presents a particular problem which was emphasized by Commissioner O’Connor in his dissent. The price goes down if the Btu content is below 1,000 and goes up if it is above 1,-050. The producers say the adjustment upward should begin at 1,000. We do not understand the Commission’s reasons for the gap. On remand this can be clarified.

16. The Rate of Return.

The Commission says that the impact of the quality adjustments is taken care of in the rate of return which is made generous on this account. It fixed a rate of return of 12% on production activities and held that such rate “protects gas consumers against excessive prices but it is not so low that it fails to respond to the needs of the industry.” The principles applicable to the determination of an appropriate return are set forth in Bluefield Water Works & Improvement Co. v. Public Service Commission, 262 U.S. 679, 692-693, 43 S.Ct. 675, 679, 67 L.Ed. 1176. It “must be determined by the exercise of a fair and enlightened judgment, having regard to all relevant facts.” The rates of a public utility should “permit it to earn a return on the value of the property * * * equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties” but the utility has no constitutional right to profits realized by “highly profitable enterprises or speculative ventures.” The return should assure “confidence in the financial soundness of the utility” and be adequate under prudent management “to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties.” The Hope decision⁴⁶ states the same basic principles.

The Commission recognized these controlling principles. The objections of the producers are to the point that the allowed rate of return is inadequate to enable the industry to attain the goals which the principles contemplate. At this time there is no need for us to go into the comparisons of the returns appropriate for producers as opposed to pipelines of to the financing methods employed by either. The fact is that by treating quality deductions as a risk rather than a cost the Commission has made it impossible to determine the amount of return with any degree of certainty. The difficulty is that the record does not disclose the amount of deductions.

A fair rate of return cannot be ascertained with mathematical certainty.⁴⁷ Pragmatic adjustments may be made by an agency within the ambit of its statutory authority.⁴⁸ A court must put great reliance on agency expertise in evaluating a rate of return but this does not mean that a court must accept the agency determination in blind faith. A producer is entitled to a higher rate of return than a pipeline because of the greater risk of the business. The Commission has here compounded the risk of discovery with the risk of substandard quality.

We believe that the price reductions to reflect quality deviations are an item of cost rather than an item of risk and should be directly reflected in the applicable base rates instead of hidden in a rate of return allowance. The amount of cost is the expense of bringing the quality up to standard. In the Permian Basin sound reason exists for this conclusion because of the known and substantial quality deficiencies particularly in flowing gas production. We find it hard to understand why a revenue deficiency in the estimated amount of $10 million annually should be classified as a risk and not a cost. A risk occurs as the result of unknown or unconsidered contingencies. In the Permian Basin it is known and considered that flowing gas falls short of pipeline standards. In any event, the lack of evidence as to quality deductions makes it impossible to determine whether the rate of return satisfies the Bluefield and Hope principles and we have no basis on which to appraise the allowance made by the Commission. We respect the expertise of the Commission but the conclusions reached by the use of expertise must accord with legal standards.

17. Contract Limitations.

The producers say that recovery of industry costs under the area rates is impossible because many of the existing contracts do not permit a producer to file for the flowing gas ceiling price of 14.5 cents. The Commission recognized that “there undoubtedly will be some contract prices lower than the area rate ceiling, as adjusted for quality.” Some of the producers estimate the deficiency because of contract limitations to be $14.4 million in the test year of 1960. The Commission has estimated that a reduction of base rates alone will result in a revenue reduction of about $10 million annually.⁴⁹

It is elementary that gas prices are originally set by contract between the producer and the pipeline, that the producer may not raise the price unilaterally, and that any increase in price must be within contract terms unless the price is set so low as to affect the public interest. The Commission says that the producers are not entitled as a matter of right to collect contract rates that are higher than otherwise reasonable in order to offset other rates limited by contract to below maximum reasonable levels. Regulation does not guarantee an over-all profit;⁵⁰ relief from an unduly low rate may be given only if the rate is “so low as to adversely affect the public interest — as where it might impair the financial ability of the public utility to continue its service, cast upon other consumers an excessive burden, or be unduly discriminatory”; ⁵¹ and a company’s losses in one instance do not justify an illegal gain in another instance.⁵² At the same time in such group procedures as the division of railroad rates the Interstate Commerce Commission, with court approval, has recognized that revenue from one source may balance that from another.⁵³

Contract limitations are one of the facts of life for the natural-gas industry. They are the outgrowth of the days when gas, which had previously been vented, flared, or capped, became salable to the newly constructed interstate pipelines. The pipelines wanted long-term contracts and the producers wanted to sell their gas. Prices were low. With the phenomenal increase in the use of gas as an energy source the prices rose. The producers whose contracts either contained no escalation clauses or clauses of the type proscribed by the Commission were in a disadvantageous position. Even permissible escalations do not, in many instances, bring the 1960 price up to the area ceiling. In Second Phillips the Court upheld the termination of certain § 4(e) dockets on the Commission’s finding that “the annual increase in revenue produced by these increased rates was substantially less than the deficit for the test year 1954.” ⁵⁴ The same situation exists here for many companies. We do not know whether it exists for the area producers as a group because no finding was made of revenue and requirements. The Supreme Court has said that losses in one instance do not justify illegal gains in another. To us this means that the contract limitations do not preclude the establishment of a just and reasonable area rate. The answer is provision for a minimum rate.

The Commission held that “the establishment of minimum rates in this case is in the public interest and that the price impact on the consumer will be de minimis.” It established a minimum rate of 9 cents per Mcf for gas of standard pipeline quality. We believe that the controlling question is whether the proper revenue requirements of the area producers as a group can be satisfied with rates having the ceiling and the floor which the Commission has fixed. This cannot be answered because the financial impact of the quality deductions is not ascertainable from the record.

18. Refunds.

The revenue deficiency argument of the producers leads directly to the refund issue. The Commission required “appropriate refunds in the case of rates which are the subject of proceedings under Section 4(e) of the Act, and have thus been collected subject to an obligation to refund amounts collected in excess of the just and reasonable rates as here determined.” Procedures to accomplish this result were set up in detail.

The producers say that these individual company refunds are not proper because of the revenue deficiency of the industry. They say that in the test year of 1960 the producers in the area failed to meet their revenue requirements by $14.4 million and they estimate the refunds for that year under the Commission decision to approximate $6 million.

The Examiner held that refunds should be ordered only to the extent that over-all industry revenues exceed over-all industry expenditures in a given year. The Commission said that this theory was unworkable because it would result in inequities among both the buyers and the producers and because of “insurmountable” administrative difficulties. We are at a loss to understand how refund obligations, which might come into existence under the Examiner’s approach, would be divided among the producers.

We see no escape from the requirement that refunds be on an individual company basis and on a schedule by schedule basis. As we understand Federal Power Commission v. Tennessee Gas Transmission Co., 371 U.S. 145, 153, 83 S.Ct. 211, 9 L.Ed.2d 199, refunds are appropriate for each excessive rate regardless of over-all revenues. The Commission has required refunds only on § 4(e) rate increases above the applicable area ceiling. If a producer claims that the refunds required of it are confiscatory or harmful to the public interest, it must have an opportunity to petition for special relief. A similar opportunity must be afforded if a producer can show that a refund is required for collections at or below the “last clean rate.” ⁵⁵ An adequate special exemption clause can take care of such situations.

19. The End Result Test.

This brings us back to the end result test. The Continental Group, which includes many large producers and major integrated oil companies and which is supported by Phillips, presents alternative arguments. The first is economic. It is said that regulation under the Act must be consistent with the economic characteristics of the industry; that this requires the establishment of market prices based on contracts; that a cost-based system of regulatory rates does not recognize the responsiveness of the gas supply to gas prices; and that a producer does not explore on the expectation of a return of its cost plus a return on its investment but on the hope of getting back many times what it expends as a reward for its gambler’s risk. No doubt these are the economic facts of the industry.

The divorce of commodity value from costs was suggested by Justice Jackson in his dissent in Hope. He commented that a producer would have difficulty showing the invalidity of a fixed commodity value so long as it voluntarily continued to sell its product in interstate commerce.⁵⁶ One difficulty with this suggestion is that once the gas is committed no withdrawal from interstate movement is possible without Commission approval.⁵⁷ A producer can stop exploration and development if it is dissatisfied with price but the interstate sales go on with a continuing impact of cost on price and of price on exploration and development. In any event the majority rejected the proposal and held that under the just and reasonable standard of the Act a regulated company is entitled to revenue for operating expenses and capital costs and to a return “commensurate with returns on investments in other enterprises having corresponding risks.”⁵⁸ These standards cannot be met without consideration of costs and revenues. In our opinion the Hope construction of the statutory standard casts serious doubts on the validity of the adoption of a contract-based commodity value.

The alternate argument of the Continental Group is that if the rates are to be determined on a composite cost-of-service basis, the revenue requirements of the industry must be found and rates fixed to meet those requirements. In Second Phillips the Court particularly noted the assurance of the Commission that “composite cost-of-service data will be considered in the area rate proceedings.” ⁵⁹ Consideration of such data does not eliminate consideration of other factors. At the same time Second Phillips did not reject the end result test of Hope. Instead it quoted a portion of that opinion which said among other things that “it is the result reached not the method employed which is controlling.” ⁶⁰

The Commission rejected both alternatives of the Continental Group. It said that commodity value established by contracts may not be used because of the absence of effective competition; and it emphasized that it took into consideration factors other than costs. The record does not disclose what these other factors were but they must have had some economic basis. The Commission held that its ceiling prices provided a “fair relationship” between consumer prices and producer costs. Fair relationship is pertinent but it is only part of the end result test. We do not know the producers’ costs or revenue requirements. We do not know the economic factors which either require or permit departure from costs and revenues. The end result test is not satisfied by a reliance on unknowns.

We have accepted the Commission’s conclusion that contract rates should not be used. The trouble is that the Commission decision rides two horses and we have no way of knowing the outcome of the race. It uses composite cost-of-service evidence, engrafts economic factors on top, and comes out with a rate which it justifies on a fair relationship basis. We have the problem of how in such circumstances a court can determine whether the just and reasonable standard of §§ 4 and 5 has been met. The answer is not found in the record before us.

The facts sustaining the conclusion of fair relationship must be found. The Commission did not make those findings and indeed it could not have done so because of the failure of the record to disclose the revenue impact of the adjustments in area rates to reflect quality differentials. Whether rate reductions because of quality deficiencies are a risk or a cost, the answer comes out the same. If they are a risk, we do not know the rate of return. If they are a cost, we do not know whether the revenue received will equal the reasonable revenue requirements. We believe that under Hope, and under Second Phillips, the area producers, as a group, are entitled to recover their prudent operating expenses and capital costs with a return commensurate to the risk and sufficient to attract capital. Satisfaction of this requirement must appear through appropriate findings based on substantial evidence. These cannot be made on the record presented. The decision of the Commission is not saved by the special exemption provisions which we find to be insufficient and unsatisfactory.

Rate making under the Act has produced a superabundance of delay and litigation. Much gas has moved through the pipelines since the First Phillips decision. We wonder if the time has not come for the establishment of a better rapport among the Commission, the consumers, the distributors, the pipelines, and the producers. Some practical means of resolving the economic and legal issues is highly desirable. The Commission has approved many settlements. The use of this procedure may well be explored further in an effort to obtain a true “balancing of the investor and the consumer interests.” ⁶¹

One point remains to be mentioned. Eleven motions for leave to adduce additional evidence were filed with us by various producers. We deferred all to the hearing on the merits. In view of the disposition which we make of the cases we see no reasons to explore evi-dentiary problems which may arise on remand. The Commission will hold such additional hearings as are needed to determine the effect of the quality adjustments, and to determine the group revenues and the group revenue requirements. It will make appropriate findings on these matters. The order based thereon shall contain an adequate provi-vision for special exemptions. We decline to make advance rulings on the procedures to be followed or on the evidence to be received.

The motions to adduce additional evidence are severally denied. The petitions to review are severally granted and the cases are all remanded to the Commission for further proceedings consistent with this opinion.

ON REHEARING.

PER CURIAM.

Texaco Inc. asserts that the opinion is not clear as to the disposition of its Docket No. C161-879 in which, by an order separate and apart from Opinions Nos. 468 and 468-A and their accompanying orders, a § 7 certificate was issued at a rate of 14.5 cents less quality deductions. This separate order shows that the Commission treated the area rate as the in-line rate for § 7 certificates.

The order on this docket was lost in the mass of material presented to us. No party made a point of it. We have reconsidered the Texaco petition for review and have concluded that it is sufficiently broad to cover such order. It should receive the same treatment as the § 4 and § 5 proceedings. Accordingly, the remand includes the separate order entered in Docket No. C161-879.

We note that in its disposition of this particular docket the Commission took the position that an established area rate automatically becomes the in-line rate for a § 7 proceeding. The same position was taken by the Commission in its Opinion No. 484 which we are today reversing by our decision in Nos. 8723 etc.—Phillips Petroleum Company, et al., v. Federal Power Commission, 10 Cir., 377 F.2d 278. We there hold that in a § 7 application heard by the Commission after its Permian decision the adoption of the area rate as an in-line rate must fall because we have rejected the area rate. We do not there, and we do not here, express either approval or disapproval of the principle that an area rate established in a § 5 proceeding automatically becomes an in-line rate for a § 7 proceeding. The validity of such a principle may be affected by the final determination of the validity of the Permian Basin area rate.

Various producers insist that we erred in our treatment of refunds. We held that refunds must be on a company-by-company and schedule-by-schedule basis. We are now convinced that such holding was wrong and is inconsistent with our conclusion that satisfaction of the end result test requires rates which will equate group revenues with group revenue requirements.

The refunds in question relate to collections made during the so-called “locked-in” periods, i. e., the periods during which an increased rate, later superseded by a further increase, is effective. See Second Phillips, 373 U.S. 294, 298, fn. 5, 83 S.Ct. 1266, 10 L.Ed.2d 357. In that case the Court said that on the locked-in rate issue “the sole question was whether all or any part of the increases had to be refunded by Phillips.” The Court pointed out that the Commission decided that the increases did not bring revenues up to cost of service, and held that the Commission “properly concluded” that “no refund obligations could be imposed.” Id. at 306, 83 S.Ct. at 1273.

We are now convinced that this treatment of refund obligations for locked-in rates in the case of an individual company in Second Phillips must be applied on a group basis when an area rate is fixed and tested by the end result. We are also convinced that our reliance on Federal Power Commission v. Tennessee Gas Transmission Co., 371 U.S. 145, 83 S.Ct. 211, 9 L.Ed.2d 199, was misplaced. That case dealt with zone rates. The Second Phillips decision on locked-in rates came later.

This modification of the opinion means that no refund obligation may be imposed for a period in which there is a group revenue deficiency. When group revenues exceed group revenue requirements, refunds may be ordered on some equitable contract-by-contract basis. In fixing an area rate, the Commission must consider the effect which past and potential refunds have on the balancing of group revenues with group revenue requirements.

In all respects, except those specifically noted herein, the petitions for rehearing are severally denied.

1

. 15 U.S.C. §§ 717-717w.

2

. El Paso Natural Gas Company began buying Permian gas in 1945, Northern Natural Gas Company through a predecessor in 1954, and Transwestern Pipeline Company in 1958. In 1961, El Paso purchased 73% of the Permian gas moving in interstate commerce, Northern 18%, and Transwestern 9%.

3

. Tlie word “independent” is used to describe a producer which does not transmit gas interstate either by its own operations or those of an affiliate. Some of the interstate pipelines produce a share of their own gas and sell gas to other pipelines.

4

. See Pan American Petroleum Corporation v. Federal Power Commission, 10 Cir., 352 F.2d 241, 243.

5

. 24 FPC 537.

6

. 24 FPC 818.

7

. State of Wisconsin v. Federal Power Commission, 112 U.S.App.D.C., 369, 303 F.2d 380.

8

. Docket No. AR61-1, 24 FPC 1121.

9

. Docket No. AR61-2, 25 FPC 942.

10

. Docket No. AR64-1, 30 FPC 1354.

11

. Docket No. AR64r-2, 30 FPC 1354.

12

. A motion for the disqualification of Commissioner Black was made to and denied by the Commission. We find no similar motion in the record pertaining ■ to Commissioner Swidler.

13

. United States v. Morgan, 313 U.S. 409, 421, 61 S.Ct. 999, 1004, 85 L.Ed. 1429. See also Federal Trade Commission v. Cement Institute, 333 U.S. 683, 700-703, 68 S.Ct. 793, 92 L.Ed. 1010.

14

. In Texaco, Inc. v. Federal Trade Commission, 118 U.S.App.D.C. 366, 336 F.2d 754, vacated 381 U.S. 739, 85 S.Ct. 1798, 14 L.Ed.2d 714, the charge was precom-mitment of a commissioner on the guilt of an accused. In Gilligan, Will & Co. v. Securities and Exchange Commission, 2 Cir., 267 F.2d 461, certiorari denied 361 U.S. 896, 80 S.Ct. 200, 4 L.Ed.2d 152, a similar charge was made against a commission. Amos Treat & Co. v. Securities and Exchange Commission, 113 U.S.App. D.C. 100, 306 F.2d 260, related to a charge against a commissioner who had previously served as a staff member in the investigation which led to the complaint.

15

. In Texas 4.7 million acres of public lands are within the Permian Basin and in New Mexico over 3 million acres. Much of this land is leased for oil and gas and produces royalty income.

16

. See opinions of Justice Jackson dissenting in Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 628, 64 S.Ct. 281, 88 L.Ed. 333, and concurring in Colorado Interstate Gas Co. v. Federal Power Commission, 324 U.S. 581, 608, 65 S.Ct. 829, 89 L.Ed. 1206; dissenting opinion of Justice Douglas in First Phillips, 347 U.S. 672, 687, 74 S.Ct. 794, 98 L.Ed. 1035; dissenting opinions of justice Clark in First Phillips, 347 U.S. 672, 690, 74 S.Ct. 794, 98 L.Ed. 1035, and in Second Phillips, 373 U.S. 294, 315, 83 S.Ct. 1266, 10 L.Ed.2d 357; dissenting opinion of Justice Harlan in Sunray Mid-Continent Oil Co. v. Federal Power Commission, 364 U.S. 137, 159, 80 S.Ct. 1392, 4 L.Ed.2d 1623; and Opinion No. 338 of the Commission, 24 FPC 537, 542-548.

17

. 373 U.S. 294, 310, 314, 83 S.Ct. 1266, 1277, 10 L.Ed.2d 357.

18

. Id. at 308, 83 S.Ct. at 1274.

19

. Id. at 317, 83 S.Ct. at 1279.

20

. United Gas Improvement Co. v. Callery Properties, Inc., 382 U.S. 223, 225-226, 86 S.Ct. 360, 15 L.Ed.2d 284.

. Id. at 231, 86 S.Ct. at 365.

21

. See The New England Divisions Case, 261 U.S. 184, 43 S.Ct. 270, 67 L.Ed. 605 (ICC—divisions of joint rates); Aetna Insurance Co. v. Hyde, 275 U.S. 440, 48 S.Ct. 174, 72 L.Ed. 357 (Missouri regulation of fire insurance rates); Tagg Bros. & Moorhead v. United States, 280 U.S. 420, 50 S.Ct. 220, 74 L.Ed. 524 (Packers and Stockyards Act of 1921); Nebbia v. People of State of New York, 291 U.S. 502, 54 S.Ct. 505, 78 L.Ed. 940, 89 A.L.R. 1469 (New York Milk Control Act); United States v. Rock Royal Co-op., 307 U.S. 533, 59 S.Ct. 993, 83 L.Ed. 1446 (Agricultural Marketing Agreement Act of 1937); Sunshine Anthracite Coal Co. v. Adkins, 310 U.S. 381, 60 S.Ct. 907, 84 L.Ed. 1263 (Bituminus Coal Conservation Act); Bowles v. Willingham, 321 U.S. 503, 64 S.Ct. 641, 88 L.Ed. 892 (Emergency Price Control Act of 1942); State of New York v. United States, 331 U.S. 284, 67 S.Ct. 1207, 91 L.Ed. 1492 (ICC—railroad rates); and Ayrshire Collieries Corp. v. United States, 335 U.S. 573, 69 S.Ct. 278, 93 L.Ed. 243 (ICC—railroad rates).

22

. Federal Trade Commission v. Bunte Bros., 312 U.S. 349, 353, 61 S.Ct. 580, 582, 85 L.Ed. 881.

23

. 24 FPC 537.

24

. An appendix to the Hunt brief presents an array of natural-gas costs of 44 Permian producers whose volumes total over 208 million Mef. Of these, 16 producing over 170 million Mef are shown to have costs of less than 14.5 cents. The remainder have costs running from 14.77 cents to 216.05 cents. We have been unable to check the accuracy of these figures and mention them only to show the claimed disparity of costs. Continental says that “approximately 67 percent of the companies and approximately 30 percent of the volumes had costs above the industry average cost level.”

25

. 293 U.S. 388, 430, 55 S.Ct. 241, 253.

26

. Crain v. First National Bank of Oregon, Portland, 9 Cir., 324 F.2d 532; 537.

27

. 261 U.S. 184, 197, 43 S.Ct. 270, 275, 67 L.Ed. 605.

28

. Id. at 198, 43 S.Ct. at 276.

29

. 24 FPC 1121, 1122.

30

. Amax Petroleum Corporation v. Federal Power Commission, 10 Cir., 350 F.2d 92, 94.

31

. This is a survey of a few producers conducted by the American Petroleum Institute, the IPAA, and the Mid-Continent Oil and Gas Association.

32

. This is computed as follows: The production investment is the sum of successful well costs, lease acquisition costs, and cost of other production facilities or a total of 3.95 cents. It is to be recouped over an average period of 10 years beginning an average of one year after investment. Accordingly, the return is allowed on an investment base 11 times the production investment of 3.95 cents per Mcf or 43.45 cents. 12% of this figure is 5.21 cents per Mcf.

33

. No separate item was included for royalty payments because costs were computed on % of actual volumes.

34

. In Opinion No. 468 the Commission said: “Nevertheless, we make clear that we do not confine ourselves to a cost calculation in determining just and reasonable rates.”

35

. 382 U.S. 223, 228, 86 S.Ct. 360, 15 L. Ed.2d 284.

36

. 320 U.S. 591, 603, 64 S.Ct. 281, 288, 88 L.Ed. 333.

37

. Ibid.

38

. 373 U.S. 294, 309-310, 83 S.Ct. 1266, 1275, 10 L.Ed.2d 357.

39

. See United States v. Abilene & Southern Railway Company, 265 U.S. 274, 291, 44 S.Ct. 565, 68 L.Ed. 1016, and Interstate Commerce Commission v. Mechling, 330 U.S. 567, 583, 67 S.Ct. 894, 91 L.Ed. 1102.

40

. Big Chief asserts that the small producers, although credited with only 20% of current production volumes, actually drill almost 40% of all successful gas wells and 50% of all successful exploratory gas wells.

41

. See statements of Justice Clark dissenting in Second Phillips, 373 U.S. 294, 329-330, 83 S.Ct. 1266, 10 L.Ed.2d 357, and speaking for the Court in Federal Power Commission v. Hunt, 376 U.S. 515, 527, 84 S.Ct. 861, 11 L.Ed.2d 878.

42

. Appendix A pertained to well and drilling statistics. It is not pertinent here.

43

. Cf. Columbus Gas & Fuel Co. v. Public Utilities Commission of Ohio, 292 U.S. 398, 407, 54 S.Ct. 763, 78 L.Ed. 1327, 91 A.L.R. 1403.

44

. The Commission says in its brief that “appropriate price differentials or adjustments could not be made on the basis of the record.”

45

. The statement was this: “It has been estimated that the reductions to the base rates alone will reduce the revenues from jurisdictional Permian sales by about $10 million annually. The adjustments for quality standards, which were substantially altered by Opinion 468-A * * * are expected to result in a further reduction of the same magnitude.”

46

. 320 U.S. 591, 603, 64 S.Ct. 281, 88 L. Ed. 333.

47

. Colorado Interstate Gas Co. v. Federal Power Commission, 10 Cir., 142 F.2d 943, 961-962, affirmed 324 U.S. 581, 65 S.Ct. 829, 89 L.Ed. 1206.

48

. Federal Power Commission v. Natural Gas Pipeline Co., 315 U.S. 575, 586, 62 S.Ct. 736, 86 L.Ed. 1037.

49

. See supra, note 45.

50

. Federal Power Commission v. Natural Gas Pipeline Co., 315 U.S. 575, 590, 62 S.Ct. 736, 86 L.Ed. 1037.

51

. Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348, 355, 76 S.Ct. 368, 372, 100 L.Ed. 388.

52

. Federal Power Commission v. Tennessee Gas Transmission Co., 371 U.S. 145, 153, 83 S.Ct. 211, 9 L.Ed.2d 199.

53

. See New England Divisions Case, 261 U.S. 184, 43 S.Ct. 270, 67 L.Ed. 605.

54

. 373 U.S. 294, 305, 83 S.Ct. 1266, 1272, 10 L.Ed.2d 357.

55

. By “last clean rate” is meant the last rate in effect pursuant to a permanent certificate not subject to any refund obligation.

56

. 320 U.S. 591, 652, 64 S.Ct. 281, 88 L.Ed. 333.

57

. Section. 7(b) of the Act. See also Sunray Mid-Continent Oil Co. v. Federal Power Commission, 364 U.S. 137, 156, 80 S.Ct. 1392, 4 L.Ed.2d 1623.

58

. 320 U.S. 591, 603, 64 S.Ct. 281, 288, 88 L.Ed. 333.

59

. 373 U.S. 294, 310, 83 S.Ct. 1266, 1275, 10 L.Ed.2d 357.

60

. Id. at 309, 83 S.Ct. at 1275.

61

. 320 U.S. 591, 603, 64 S.Ct. 281, 288, 88 L.Ed. 333.