
    TENNECO OIL COMPANY et al., Petitioners, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent.
    Nos. 76-2960 et al.
    
    United States Court of Appeals, Fifth Circuit.
    April 18, 1978.
    
      Allan Abbot Tuttle and Howard E. Shapiro, Solicitors, Drexel D. Journey, Gen. Counsel, J. Paul Douglas, Atty., F.P.C., Washington, D. C., for Federal Energy Regulatory Com’n.
    Gordon Gooch, Bruce Kiely, Washington, D. C., Vernon M. Turner, Michael Silva, Phyllis Rainey, Houston, Tex., for Tenneco Oil Co.
    Shelia S. Hollis, Washington, D. C., for Public Service N. Y.
    Thomas G. Johnson, Houston, Tex., for Shell Oil Co.
    David M. Whitney, Houston, Tex., for Aminoil USA, Inc., Aminoil Development, Inc. and Signal Petroleum.
    Justin R. Wolf, Washington, D. C., for California Co., a Div. of Chevron Oil Co.
    William A. Sackmann, Findlay, Ohio, for Marathon Oil Co.
    Pat F. Timmons, Houston, Tex., for Superior Oil Co.
    Robert W. Henderson, Dallas, Tex., for Hunt Oil Co., et al.
    Paul W. Hicks, Dallas, Tex., for Placid Oil Co.
    Richard F. Generelly, Washington, D. C., for General American Oil Co. of Texas.
    James D. Olsen, Dallas, Tex., for Sun Oil Co. (Delaware).
    George B. Mickum, III, Washington, D. C., for Atlantic Richfield Co.
    Thomas H. Burton, Houston, Tex., for Continental Oil Co.
    Richard A. Solomon, Washington, D. C., for Public Service Comm, of State of N. Y.
    Patricia D. Robinson, Oklahoma City, Okl., for Kerr-McGee Corp.
    Bruce F. Kiely, Washington, D. C., for Pennzoil Co., et al.
    Edmunds Travis, Jr. and Paul W. Wright, Houston, Tex., for Exxon Corp.
    Judy M. Johnson, Houston, Tex., for Belco Petroleum Corp.
    Charles F. Wheatley, Jr., Washington, D. C., for American Public Gas Ass’n.
    John L. Williford, Bartlesville, Okl., for Phillips Petroleum Co.
    Robert D. Haworth, Houston, Tex., for Mobil Oil Corp.
    B. James McGraw, Houston, Tex., for Gulf Oil Corp.
    Kenneth L. Riedman, Jr., Los Angeles, Cal., for Union Oil Co. of Cal.
    Richard F. Remmers, Oklahoma City, Okl., for Sohio Petroleum Co.
    William H. Emerson, Chicago, III, for Amoco Production Co.
    C. Roger Hoffman, Houston, Tex., for Texaco, Inc.
    Randolph C. Bruton, Tulsa, Okl, for Amerada Hess Corp.
    Alan H. Maclin, Sp. Asst. Atty. Gen., St. Paul, Minn., for State of Minn.
    Sam Riggs, Jr., Tulsa, Okl., for Cities Service Oil Co.
    Tilford A. Jones, Bethesda, Md., for United Distribution Companies.
    Malcolm H. Furbush, San Francisco, Cal, for Pacific Gas & Elec. Co.
    Jack L. Brandon, Houston, Tex., for Getty Oil Co.
    Ronald E. Jarrett, Tulsa, Okl., for Skelly Oil Co.
    William W. Hensley, Pampa, Tex., for Cabot Corp.
    David H. Thornberry, Houston, Tex., for United Gas Pipe Line Co.
    
      Before CLARK, RONEY and TJOFLAT, Circuit Judges.
    
      
       Consolidated with cases Nos. 76-2962/3099/3100/3111/3132/3133/3142/3144/-3167/3232/3243/3378/3397/3453/3515/3565/-3579/3581/3582/3584/3700/3771/3863/4264/-4266.
    
   RONEY, Circuit Judge:

In 1976, the Commission established, for the first time, a national rate which would govern future prices for “flowing gas,” i. e., natural gas from wells commenced prior to January 1, 1973. In this decision we affirm the Commission’s rate, find its procedure proper, and hold the petitioners have failed to show the rate is unjust and unreasonable under the limited review permitted this Court. We reverse only that portion of the Commission’s order which denies refund credit under the new rate to producers who have already dedicated gas to the interstate market on the representation that they would receive the credit in addition to the established just and reasonable rate for such gas.

We follow a familiar path. The methodology on which the Commission relied tracks the design of the area rate order affirmed by the Supreme Court in Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968), and closely parallels that established in Area Rate Proceeding (Southern Louisiana Area), 46 F.P.C. 86 (1971), aff’d sub nom. Placid Oil Co. v. FPC, 483 F.2d 880 (5th Cir. 1973), aff’d sub nom. Mobil Oil Corp. v. FPC, 417 U.S. 283, 94 S.Ct. 2328, 41 L.Ed.2d 72 (1974). This Court in Shell Oil Co. v. FPC, 520 F.2d 1061 (5th Cir. 1975), cert. denied, 426 U.S. 941, 96 S.Ct. 2661, 49 L.Ed.2d 394 (1976), upheld the Commission’s Opinion No. 699, which announced its decision to switch from area to national ratemaking. Shell Oil Co. affirmed the Commission’s first national rate for “new” gas, i. e., natural gas from wells commenced on or after January 1, 1973. In Opinion No. 770, the Commission revised that rate, and established a second national rate for gas from wells commenced after January 1, 1975. The D.C. Circuit affirmed that order, American Public Gas Ass'n v. FPC, 186 U.S.App.D.C. 23, 567 F.2d 1016 (1977), cert. denied, 46 U.S.L.W. 3541 (Feb. 28, 1978).

The rate presently under review, established in Opinion No. 749 (Dec. 21, 1975), Opinion No. 749-A (Feb. 20, 1976), Opinion No. 749-B (March 31, 1976), and Opinion No. 749-C (July 19, 1976), is a national rate for gas from wells commenced before those controlled by the other national rates, that is before January 1, 1973. The producers state the wells covered by this rate produce about 90 percent of the natural gas sold interstate in the United States today.

The Rate

The Commission established a price of 29.5 cents/mcf, rejecting both the minimum 24.5 cents/mcf figure suggested by its staff and the maximum 43.3 cents/mcf requested by the producers. It limits the price that can be charged for gas produced under contracts providing for a price, higher than this rate, and establishes a new price level for gas sold under those contracts that fix price at the highest price allowed by the Commission. It makes an exception to the ceiling, however, for area rates previously established at a higher price. All contracts not come to the ceiling. See Gillring Oil Co. v. FERC, 566 F.2d 1323 (5th Cir. 1978). If fixed at a lower price, they remain unaffected, unless they are below the floor, or “minimum” rate the Commission also established. That minimum is 18 cents/mcf. The resulting net impact of this rate is expected to be an increase in the average price of flowing gas from 22.90 cents/mcf to 27.68 cents/mcf, and an increase of $503,-000,000 a year in producers’ income.

The starting point for setting price is cost. The Commission attempted to establish an aggregate cost for the nation’s flowing gas. It issued a notice of proposed rulemaking and collected industry data. The staff proposed a rate, the parties commented on it, and the Commission formulated its opinion, which was modified on rehearing. In calculating costs, the Commission made a number of judgments challenged here. It chose to measure exploration and development costs by using a 1972 test year, even though many of the wells from which the gas comes were developed at a lower cost years earlier. The Commission included a component to cover the cost of income taxes producers might have to pay on their income, despite a lack of evidence that taxes would actually be paid. It allowed producers a 15 percent rate of return. In allocating the costs of wells which produce both oil and gas, the Commission selected a division based on the relationship of oil price to gas price in the unregulated intrastate market.

In the overall rate design, the Commission adhered to the methodology first established in Permian. In particular, it decided to “vintage” the rate, by basing it on historical cost, and making it lower than rates for subsequent years when costs have risen dramatically. The price for flowing gas of 29.5 cents/mcf stands in marked contrast to the 50 cents/mcf rate the Shell decision approved for post-January 1, 1973 gas. The later price, subsequently raised to 93 cents/mcf, is still far less than the $1.42/mcf rate for post-January 1, 1975 gas approved in American Public Gas Ass’n, supra.

The petitioners, both consumers and producers, stand in opposite camps. The only point on which all would agree is that producers should at least recover their historical, or actual, costs.

The Consumers’ Objections

The consumers argue the Commission has, without adequate justification, exceeded actual cost. In particular, the American Public Gas Association, an organization of public utilities whose brief is joined by the State of Minnesota, challenges the use of the 1972 test year, the inclusion of an income tax component, the choice of a rate of return, the design of the cost allocation method, and the adoption of the minimum rate. The Public Service Commission of the State of New York, a regulatory body representing consumer interests, joins in the objection to the income tax component and the cost allocation method. Both seek to have the rate set aside, and as an additional ground the Association argues the Commission erred in using rulemaking rather than adjudication.

The Producers’ Objections

On the other hand, the producers, led by Tenneco Oil Company, contend the Commission failed to award even actual cost at a time when replacing dwindling gas supplies requires far more than that barebones standard will allow. The producers:

—object to the Commission’s use of the Permian methodology, and allege the rate will produce a return so far below the amount they currently need to do business as to violate the Natural Gas Act;

—raise the Commission’s failure to take into account regulatory lag, the time value of money, and inflation;

—fault the Commission’s failure to provide in the rate for individual adjustment when royalty costs go up;

—and argue the Commission erred in requiring them, in order to collect the new national rate, to waive credits against refunds due for gas previously sold in excess of ceiling rates.

Atlantic Richfield Company (ARCO) separately attacks the whole vintaging concept as contrary to the basic purpose of the Natural Gas Act and a violation of the due process clause of the Constitution.

The producers do not want the rate set aside, because it is higher than the old area rates which it replaces, but seek affirmance, with instructions to the Commission to commence a proceeding to revise it upwards.

Standard of Review

Review of a Commission rate order examines (1) whether the Commission abused or exceeded its authority, (2) whether the essential elements chosen by the Commission for the rate are supported by substantial evidence, and (3) whether the “end result” is unjust and unreasonable. Permian, 390 U.S. at 791-792, 88 S.Ct. 1344, 20 L.Ed.2d 312; Shell Oil Co., 520 F.2d at 1071.

The first inquiry springs from the familiar words of the Administrative Procedure Act that instruct a reviewing court to set aside agency action which is “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” 5 U.S. C.A. § 706(2)(A). The other requirements, while not inconsistent with general principles of administrative law, have taken on a special gloss in Natural Gas Act review.

Issuing rate orders is simply not like the garden variety of administrative action. The Commission faces, on the one hand, a need to protect consumers from monopolistic price exploitation in a time of soaring energy costs, and, on the other, the sure knowledge that unless producers are guaranteed an adequate return consumers will find themselves without gas at any price. Complicating the Commission’s attempt to resolve this difficult balance is the gargantuan inequity that results when some consumers, merely because they contracted first, get natural gas at a price which is less than one-fifth of the price that other consumers pay for natural gas or any other comparable energy source. As this Court said in Shell Oil Co.:

Finding and maintaining this point of delicate balance is a difficult task. Congress has chosen the [Commission] to be its surrogate for this responsibility, and our view of the agency’s work must take into account the attendant difficulties to assure that the legislative scheme will be effectuated.

520 F.2d at 1072. Among these difficulties is the suddenness with which the energy shortage has developed, the need for speed to reduce the “regulatory lag” between the time data is collected and the date rate orders based on that data go into effect, the immense number of parties and interests affected, the technical nature of the problems, and the need for continuing adjustment and experiment as past rate designs succeed or fail their intended purpose.

As a result, the Supreme Court has mandated a special approach to the “substantial evidence” standard which the statute specifies the Commission’s factual findings must meet. See 15 U.S.C.A. § 717r(b). Judge Leventhal has recently articulated a cogent description. In Public Service Commission v. FPC, 159 U.S.App.D.C. 172, 487 F.2d 1043 (1973), he wrote an opinion for the D.C. Circuit reversing the Commission’s rate order for the Texas Gulf Coast Area. The Supreme Court vacated that judgment for consideration in light of its intervening decision, Mobil Oil Corp. v. FPC, 417 U.S. 283, 94 S.Ct. 2382, 41 L.Ed.2d 72 (1974). On remand, the D.C. Circuit affirmed the Commission. Public Service Commission v. FPC, 170 U.S.App.D.C. 153, 516 F.2d 746 (1975). Judge Leventhal has offered this view of Mobil:

Throughout Mobil reflects an approach to the “substantial evidence” standard as requiring the reviewing court to respect the agency’s wide latitude for difficult policy choices, and in adjusting that standard “in this time of acute energy shortage” to provide greater freedom for new proposals and techniques, [citing 417 U.S. at 331, 94 S.Ct. 282] . . . The parties raised a not insubstantial issue. The Court’s response identified the context that the Commission had taken “massive evidence” with voluminous exhibits and various cost estimates in the record, and that the rates fixed, even with incentive increments, were within the range of cost estimates. “Its difficulties, while not minor, did not stem from any failure to seek answers.” 417 U.S. at 318, 94 S.Ct. at 2350-51, referring to n.48 at p. 313, 94 S.Ct. 2328. That single sentence is a capsule of the requirement of reasoned decisionmaking in the context of the novel and exigent problem of seeking to enhance the natural gas supply in time of dire shortage while maintaining fairness to consumers.

American Public Gas Ass’n, 186 U.S.App.D.C. at 37, 567 F.2d at 1030. In short, in examining the record support for the elements of the rate order, the Court is to look first and foremost at the effort the Commission has made and whether the Commission has “given reasoned consideration to each of the pertinent factors,” Permian, 390 U.S. at 792, 88 S.Ct. at 1373, rather than just to weigh the evidence the Commission’s search has produced. An integral part of this review is respect for the statutory requirement that, absent special circumstances, only objections urged before the Commission are to be considered by the Court. 15 U.S.C.A. § 717r(b).

The final, and most important, aspect of court review is the “end result” doctrine. In FPC v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 288, 88 L.Ed. 333 (1944), the Supreme Court stressed:

It is not theory but the impact of the rate order which counts. If the total effect of the rate order cannot be said to be unjust and unreasonable, judicial inquiry under the Act is at an end. The fact that the method employed to reach that result may contain infirmities is not then important. . . . [H]e who would upset the rate order under the Act carries the heavy burden of making a convincing showing that it is invalid because it is unjust and unreasonable in its consequences.

The “zone of reasonableness” is wide. The producers, under the Constitution as well as the Act, are, at bottom, only entitled to a fair return on their actual costs, i. e., a rate which, if anticipated at the time their wells were dug would be sufficient to “maintain financial integrity, attract necessary capital, and fairly compensate investors for the risks they have assumed.” Permian, 390 U.S. at 792, 88 S.Ct. at 1373. Subsequent increases in operating costs would be taken into consideration, but replacement value would not. See Hope Natural Gas Co., 320 U.S. at 605, 64 S.Ct. 281, 88 L.Ed. 333. Because the flowing gas rate of 29.5 cents/mcf is higher than the older area rates which it supersedes, the producers face a burden at the outset of justifying an increase over the return previously thought sufficient.

At the same time, however, the statute does not forbid the Commission from taking replacement cost into consideration when formulating a rate. While the Commission may not abandon regulation altogether, FPC v. Texaco, 417 U.S. 380, 94 S.Ct. 2315, 41 L.Ed.2d 141 (1974), it does have the power to put some of the burden of replacing scarce gas supplies on the consumer of flowing gas. Mobil Oil Corp., 417 U.S. at 320, 94 S.Ct. 2315; American Public Gas Ass’n, 186 U.S.App.D.C. at 65, 567 F.2d at 1058. The consumers are getting a product the replacement price of which has been determined to be $1.42/mcf. In a free market, competitive bidding would tend to equalize the prices of flowing and new gas. The Commission’s vintaging policy insulates consumers from market forces and provides them with gas at one-fifth the price of replacement gas. In the light of that benefit, consumers face a difficult task if they are to show the adopted rate has an end result which is unjust and unreasonable for them.

This standard of review largely dictates the outcome of this case. Insofar as theories of regulation are concerned, the choice between actual cost and replacement cost is for the Commission to make, subject to the sole requirement that the end result be within the “zone of reasonableness.” While the Commission cannot adopt unauthorized procedures and it must work within the confines of the substantial evidence test, that test means here only that its difficulties in applying its chosen methodology must not stem from a “failure to seek answers.” Mobil Oil Corp., 417 U.S. at 318, 94 S.Ct. 2382. This “kid glove” approach, see Shell Oil Co., 520 F.2d at 1072, is warranted by the nature of the delegation Congress has made to the Commission in this instance. Without it, these national rates, fraught as they are with judgment calls, experiment, and occasional rank speculation, could not be affirmed.

Use of Rulemaking

The Association, as consumers, attack the Commission’s decision to develop the rate through rulemaking rather than adjudication. The Association claims the Commission violated due process, the statutory hearing requirement, 15 U.S.C.A. § 717c(e), r(b), and the Commission’s regulations, 18 C.F.R. § 1.20(g)(1) (1977).

The steps the Commission took in promulgating Opinion No. 749 followed those it has taken in other similar orders. The Commission first issued data collection forms and a notice of proposed rulemaking. After parties commented on the forms, the Commission served modified forms and the producers submitted the required data. The Commission’s staff issued a rate recommendation. After an extension of time, the parties filed initial comments, and later had an opportunity for reply comments. The Commission then issued Opinion No. 749, and entertained petitions for rehearing. Opinions No. 749-A, 749-B, and 749-C followed.

The Association alleges no specific prejudice from the procedure the Commission followed. The only asserted omission is that the Commission did not grant an oral hearing. The statute does not require oral hearings, however, even if it is construed to mean the Commission must follow the formal hearing requirements of the Administrative Procedure Act. Shell Oil Co., 520 F.2d at 1075. See 5 U.S.C.A. § 556(d). The parties were not only allowed to comment on the proposed order, they also were given a chance to comment on each others’ comments. The Association has not distinguished the procedures followed here from those approved by this and other courts. See American Public Gas Ass’n, 186 U.S.App.D.C. 71-74, 567 F.2d at 1064-1067; Shell Oil Co., 520 F.2d at 1074-1076; American Public Gas Ass’n v. FPC, 162 U.S.App. D.C. 176, 498 F.2d 718 (1974); Phillips Petroleum Co. v. FPC, 475 F.2d 842 (10th Cir. 1973), cert. denied, 414 U.S. 1146, 94 S.Ct. 901, 39 L.Ed.2d 102 (1946). Furthermore, the asserted right to an oral hearing under regulation § 1.20(g)(1) does not come into play unless the Commission initiates a hearing under § 1.20(a), which it did not do in this case. The procedure here is consistent with § 1.20(m), which governs rulemaking. The procedure by which the Commission adopted the flowing gas rate violated neither statute, Constitution, nor regulation.

1972 Test Year

The Association next challenges the use of 1972 as a test year for estimating the exploration and development costs of gas from wells ' drilled as much as 40 years before. As consumers, they object that the 1972 test year permits too high a figure for such costs. The data for even the most recent years dramatically illustrates the basis for its complaint. The rate contains a 6.26 cents/mcf component for exploration and development costs. The Commission arrived at this figure by dividing 1972 exploration and development costs by total gas production for that year. Similar figures for 1969 and 1960 were only 5.45 cents/mcf and 3.55 cents/mcf respectively. The Association argues that the cost of finding gas in 1972 has no relationship to the flowing gas involved in this proceeding, because gas found in 1972 would ordinarily not have been produced until after the January 1, 1973 cut-off date. The effect of inflation on exploration and development costs is argued to be irrelevant to this rate because those costs are literally “sunk costs” fixed on the day the flowing gas was discovered.

The Commission rested its choice of the 1972 test year largely on administrative expedience. By using 1972, it could avoid the large number of claims for special relief that would result if it had chosen an earlier test year and fixed a cost figure below that incurred by those who found gas in later years. The Commission noted that its customary practice has been to adopt a test year just prior to the cut-off year for a particular “vintage.” Orders using that technique have been affirmed, but because no challenge to the test year was made in those cases, no guiding precedent exists. See Permian, supra; Mobil Oil Corp., supra; Austral Oil Co. v. FPC, 428 F.2d 407 (5th Cir.), cert. denied, 400 U.S. 950, 91 S.Ct. 241, 27 L.Ed.2d 257 (1970).

Administrative expedience, the pursuit of the achievable rather than the perfect, provides a reasoned basis for the Commission’s judgment. Even if it did not, the Commission could legitimately choose to adopt the 1972 test year, knowing it provided a return that was to a degree excessive, insofar as return of actual cost is concerned, in order to insert an allowance for replacement cost into the rate. The Association argues that the Commission had no such intent. In another context, the Commission rejected the inclusion in the rate of a 3.5 cents/mcf exploration and development incentive proposed by its staff, saying that such incentives were not the function of this rate. The Commission stoutly denied the choice of the 1972 test year involved a “windfall” for producers. Undoubtedly, however, the Commission was of more than one mind on the subject. The denial of a “windfall” cannot change the fact that using the 1972 test year does, absent other error, provide an allowance for costs at a level the producers of this gas did not incur. The Commission explicitly recognized this in a passage in its final word on the subject, Opinion No. 749-C, which says the 1972 test year would “aid in part current exploration and development activities.” The Association would dismiss this as a “post-hoc rationalization,” but that is one function of opinions on rehearing. Ease of administration, twinned with a permitted purpose to make some allowance for replacement cost, fully supports the Commission’s choice of the 1972 test year, and the similar inclusion of high cost areas in the rate base even though they are excluded from the price ceilings.

Tax Component

The Commission reversed part of its Permian methodology by adding to the rate base a component representing the income tax that would theoretically be due on producers’ income from jurisdictional sales of natural gas. The Association and the Public Service Commission forcefully argue that all past precedent demonstrates that, because of tax deductions and credits earned in other activities, the gas companies will never actually pay income taxes at the rate estimated by the Commission. Because the Commission did not bother to examine company tax returns to see whether taxes would be paid, they conclude the tax component is based on caprice rather than on substantial evidence.

In calculating the tax component, the Commission treated the industry as a single enterprise. The Commission first calculated production net income. Then it made a series of adjustments to arrive at taxable income, which was only 73 percent of production net income. The adjustments included an addition for amortization of capitalized intangible drilling costs, and deductions for estimated tangible drilling costs in test year 1972 and for interest expense. From that point on the Commission’s methodology is not clear from the record, but it appears that the Commission multiplied taxable income by 48/52 to arrive at the appropriate tax allowance. Presumably 48/100 was not used because the allowance itself increases income and is subject to tax. Employing 48/52 takes this into account. The resulting tax allowance, when divided by the relevant volume of flowing gas, yielded the 6.08 cents/mcf tax component included in the rate by the Commission. Because of the adjustments of production net income to yield taxable income, the “effective” tax rate which this rate included was only 35 percent.

The consumers first observe that Commission rate opinions for the Permian Basin and South Louisiana found that producers paid no income tax at all on their jurisdictional income. Indeed, for that reason, the Commission has in the past steadfastly refused to include an income tax component on producer rates. The consumers then cite case authority which lends some support to the proposition that the Commission does not have the discretion to include an allowance for taxes other than those actually paid. FPC v. United Gas Pipeline Co., 386 U.S. 237, 87 S.Ct. 1003, 18 L.Ed.2d 18 (1967); El Paso Natural Gas Co. v. FPC, 281 F.2d 567 (5th Cir. 1960), cert. denied, 366 U.S. 912, 81 S.Ct. 1083, 6 L.Ed.2d 955 (1961). In El Paso, this Court reversed a Commission order allowing a pipeline producer to retain income sheltered by nonjurisdictional tax losses. The Court said regulated companies must save on all costs, including taxes, and pass those savings on to consumers. See also City of Chicago v. FPC, 147 U.S.App.D.C. 312, 458 F.2d 731, 757 (1971), cert. denied, 405 U.S. 1074, 92 S.Ct. 1495, 31 L.Ed.2d 808 (1972). The consumers conclude that because the Commission produced no tangible evidence that the amount allowed for income taxes will ever wind up in the tax coffers of the federal treasury, the allowance must be set aside.

The Commission says the repeal of the depletion allowance explains its policy reversal. The repeal contained an express exemption for natural gas sold before July 1, 1976, and the language seems to indicate that Congress wanted to give the Commission time to change its rates to compensate. See I.R.C. § 613A(b)(2). Numerically, depletion repeal cannot by itself justify the size of the tax allowance granted here. As a practical matter, depletion deductions could never have amounted to more than 24 percent of taxable income. Depletion allowance repeal could, however, have provided the impetus for a total rethinking of Commission policy toward producer taxes. Shell Oil Co., 525 F.2d at 1263 (5th Cir. 1976) (on rehearing).

The cited cases do not obstruct the Commission’s path. United Gas contained a phrase referring to “the power and the duty of the Commission to limit cost of service to real expenses,” 386 U.S. at 245, 87 S.Ct. at 1008, but the use of the word “duty” was dictum. The holding went no further than saying the Commission could, if it so chose, take nonjurisdictional tax savings into account when calculating jurisdictional income. American Public Gas Ass’n, 186 U.S.App.D.C. at 46, 567 F.2d at 1039. On its precise facts, El Paso, which dealt with the consequences of nonjurisdictional depletion deductions, is called into question by the passage of I.R.C. § 613A(b)(2). El Paso dealt with the known facts of an individual pipeline, and has less force when assessing a rulemaking proceeding for an industry of producers, whose collective non-jurisdictional net tax losses could only be the subject of speculation.

Having begun a reevaluation, the Commission embraced the theoretical tax compensation scheme found in this ratemaking Opinion No. 749. Such action was a reasoned exercise of regulatory discretion. Several considerations stand out.

The nature of the problem justifies reliance on an economic model rather than a survey of test year tax returns. The choice was not between the unknown and the known, but rather between the satisfaction of theory and the frustration of data not compiled for the use to which it would be put. When material, company tax returns would have been consolidated. While it might be possible to separate the tax burden on gas and non-gas income, it would have been far more difficult to make the necessary breakdown between the burden on new gas and the burden on flowing gas, a distinction unfamiliar in the world outside the regulations of the Commission. Speculation would have been necessary. Even the final tax burden figure at which the Commission arrived would have been an average, and perforce would have been somewhat hypothetical. The data, based on the past, would not have reflected the effect of depletion repeal, nor would it have shown the impact of the additional income produced by the higher prices allowed by this rate.

The Commission’s model avoided such difficulties, but at the same time preserved important elements of the “actual taxes paid” principle by taking into account the tax impact that flowing gas intangible drilling costs would have on production net income. American Public Gas Ass’n, 186 U.S.App.D.C. at 45, 567 F.2d at 1038. The Public Service Commission of the State of New York challenges the Commission’s calculation of those intangible drilling costs, but the objections were not made to the Commission and cannot be considered here.

The model is consistent with Opinion No. 699, which sets the first new gas rate. In that rate, the discounted cash flow credited producers with income tax deferrals which they would receive if the activities outside the scope of Opinion No. 699 produced income which was subject to tax. Because the production of flowing gas is such an activity, the assumptions leading to the income tax allowance in Opinion No. 749 agree with those underlying the Commission’s earlier decision.

The Commission has not shown that its income tax component is strictly cost-justified. It has, however, made a reasonable effort to construct a rate element that would confront the reality of the tax laws rather than pretend they do not apply. We affirm the Commission’s use of an income tax component not because of what we find in the record, but because of the reasoned consideration the Commission has given the problem. That is all the Natural Gas Act requires.

Rate of Return

The Commission allowed a 15 percent rate of return on capital, which amounts to a 17.73 percent return on common equity. Our review of that rate of return hinges on the nature of the choice with which the Commission was faced.

The Association has advanced a number of arguments why the Commission’s choice was too high, and so was against consumers’ interests. The Commission principally relied on the 15 percent return allowed in Opinion No. 699, setting the first new gas rate, and affirmed in Shell Oil Co., 520 F.2d at 1081-1082. The express purpose of allowing a 15 percent rate for new gas, however, was to attract venture capital into a high risk industry. That justification does not apply to flowing gas, production of which now involves little risk. Nothing guarantees that a rate increment tacked onto a flowing gas price will actually be spent in expanding interstate gas supplies. The Commission’s approach ignores the cushion provided by the exploration and development allowance, and overestimates the importance of risk in an industry-wide proceeding, where the law of average applies. See Kitch, The Permian Basin Area Rate Cases and the Regulatory Determination of Price, 116 U.Pa.L.Rev. 191, 201 (1967).

Despite these possible errors, the Commission’s choice of a rate of return seems reasonable on the basis of the record before it. In Opinion No. 699, the Commission established not only a single rate of return, but also a “zone of reasonableness” which ranged from 12 to 15 percent. Here the Commission heard additional testimony. Statistics showed industry groups generally earned 13.3 and 14.1 percent on equity in 1972 and 1973. The staff recommended a 15 percent return on capital. Producer witnesses urged that a rate of 17 to 18 percent be allowed. The Commission rejected their proposals because they were based on petroleum company earnings inflated by the quadrupling of crude oil prices by the Organization of Petroleum Exporting Countries in late 1973. The Association did not suggest a rate of return it thought would be appropriate. While it more closely resembles a show of hands judgment than it does fine-tuned logic, the Commission’s choice of rate appears reasonable.

Cost Allocation

Some wells produce both condensate liquids and gas. The condensate is generally considered the equivalent of light crude oil. Mobil Oil Corp. v. FEA, 566 F.2d 87 (Temp.Emer.Ct.App.1977). The Commission has adopted various formulas to determine what percentage of cost for such a well should be borne by the sale of gas. The Commission here chose one of three methods for allocating production costs. Both the consumer petitioners challenge the formula adopted by the Commission.

In the past, for production expenses the Commission has used the “relative cost” method. It takes the ratio of costs on an oil-only lease to those on a gas-only lease as a model, and allocates costs for a combined production facility in the same proportion. All prior flowing gas rates have employed this method, and the ratio they relied on was 3.5 to 1, oil to gas.

In this opinion, the Commission adopted a “modified BTU” method. It allocates costs according to the ratio which the price per BTU of oil bears to the price per BTU of natural gas. BTU is the heat producing quality of the product expressed in British thermal units. The Commission has used this method in the past to allocate exploration and development expenses. The natural gas price component used in the ratio, however, was the regulated price. In this opinion the Commission decided to use the price for unregulated gas sold in the intrastate market. Historically, the ratio has ranged from 3.0 to 4.0 to 1, oil to gas, but the Commission found recent rises in the intrastate gas market indicated a relative value of 1.7 to 1 for 1975. Based on that trend, it chose a ratio of 1.5 to 1. The effect was to increase dramatically the proportion of costs borne by natural gas. The PSCNY claims that this change was the primary factor which caused the Commission to set a pretax cost figure of 23.3 cents/mcf, rather than the 21.0 cents/mcf proposed by the staff.

A third method, the “net liquid credit” method, assigns all costs to gas and then deducts a credit for the total revenue of liquid sales. In the past, net liquid credit has been used to allocate production expenses for new gas. The PSCNY advocates its use for flowing gas as well.

The consumers’ objection to the Commission’s choice is three-fold. Because the modified BTU method adopted by the Commission places reliance on unregulated market prices, they contend it is an abuse of discretion. They argue the 1975 price ratios have nothing to do with the cost of gas which predates 1973. They observe that the Commission appears to have simply split the difference between the producers’ suggested 1 to 1 ratio, and the consumers’ proposed 3.5 to 1. Commission Chairman Dunham, dissenting on this issue, suggested the modifying factor was manipulated to reach a “predetermined result.”

This Court’s duty, however, is to examine the reasoning expressed and the end result reached, not to oversee the internal machinations of the board. The Commission did not abuse its discretion by taking unregulated market prices into account. The Commission has the power to rely on those prices when it does so in conjunction with other factors. FPC v. Texaco, 417 U.S. 380, 399, 94 S.Ct. 2315, 41 L.Ed.2d 141 (1974). Here market prices are only being used to allocate a share of costs incurred, and that is a far cry from the total deregulation the Supreme Court perceived and condemned in Texaco. See also Atlantic Refining Co. v. Public Service Commission, 360 U.S. 378, 79 S.Ct. 1246, 3 L.Ed.2d 1312 (1959). While exploration and development costs are “sunk,” a substantial portion of production costs are prospective. The Commission could rationally choose to allocate production costs by using price ratios from 1975 rather than from an earlier date.

The end result test permits a wide latitude for the Commission when it is choosing among rival cost formulas. These choices have vexed producer rate regulation from its inception. Breyer & McAvoy, The Natural Gas Shortage and the Regulation of Natural Gas Producers, 86 Harv.L.Rev. 941, 954-957 (1973). Here, while the adopted allocation method has its faults, the ones proposed by the consumers are also far from perfect. The relative cost method allocates too much cost to condensate liquids, and therefore too little to gas. It does so because oil-only leases use expensive secondary and tertiary recovery techniques that are not used with condensate. The net liquid credit allocates cost in proportion to value earned. It thus assumes the relationship between cost and price, and therefore the rate of return is the same for both gas and condensate liquids. In fact, the rate of return is greater for liquids. Because the formula does not take that difference into account, it too allocates excessive cost to liquids. These considerations, noted by the Commission, provide a reasoned basis for its choice.

Minimum Rate

This Opinion No. 749 imposes a national minimum price of 18 cents/mcf for natural gas. That rate abrogates all contracts for a lesser price, some of which were set as low as 4 cents/mcf. The proposal falls between the 15 cents/mcf staff suggestion and the 20 cents/mcf advocated by Mobil Oil.

The consumers argue the Commission failed to make the necessary finding that contract prices below 18 cents/mcf were 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.” FPC v. Sierra Pacific Power Co., 350 U.S. 348, 355, 76 S.Ct. 368, 372, 100 L.Ed. 388 (1956), decided with United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332, 76 S.Ct. 373, 100 L.Ed. 373 (1956). A mere desire to relieve a producer of an improvident bargain is not enough. Id. The consumer Association contends the rate is greatly in excess of contract prices under which many producers currently find it profitable to extract gas, and so harms consumers.

The Mobile/Sierra doctrine is good law, but those cases must be read in light of Permian. In Permian, the Supreme Court approved a 9 cents/mcf minimum price as part of an area rate structure. The Court did not require a finding that service would be impaired unless the rate was allowed. Instead, it sustained an order which merely found “the establishment of minimum rates in this case is in the public interest and . the price impact on the consumer will be de minimis.” 390 U.S. at 821 n. 113, 88 S.Ct. at 1388 quoting 34 F.P.C. at 231. Noting that the order left the calculation of the 9 cents/mcf minimum “largely unexplained,” the Court gave weight to the Commission’s reliance on evidence before the hearing examiner. The Court said: “the Commission reasonably concluded that a minimum rate was imperative, and there is no evidence before us that permits the conclusion that its selection was unjust or unreasonable.” 390 U.S. at 821 n. 113, 88 S.Ct. at 1388.

Although the price impact here is not de minimis, the Commission has made the required finding that a minimum rate is in the public interest, and the Association has not shown the choice of a minimum rate to be unreasonable. The Commission’s cost studies indicated that the average cost of producing gas was 14.18 cents/mcf, allowing no return on capital or regulatory expense. The Commission fully articulated reasons to support its conclusion that a minimum rate was required. First, increasing prices would provide an incentive for maximizing production from existing wells. While the Commission could, as the Association suggests, achieve the same purpose through individualized special relief hearings, it could also reject that procedure as an administrative burden. Second, the minimum rate would help compensate producers with fixed-rate contracts for the increased tax burden caused by repeal of the depletion allowance. Third, eighty percent of the volumes affected by the minimum rate come from contracts dated 1964 or earlier. Implementing a minimum now will help redress the bargaining advantages that purchasers of natural gas then had in many markets. The Association argues that the Commission failed in some prior area rate orders to see any need to make up for producers’ lack of bargaining power, but the Commission was entitled to reevaluate its position from a national point of view.

Return of Historical Cost

The producers allege that errors in Commission methodology result in depriving them of even a bare-bones recovery of the actual costs already incurred, called “historical” cost. The Commission, however, provided a reasoned basis for shaping the rate design as it did, immune from rejection or review.

Ceiling-Fioor. The producers object to the use of an average cost of 29.5 cents/mcf as a price ceiling. The minimum price is only 18 cents/mcf. As a result, the average price will be only 27.68 cents/mcf, which is below average cost. These contentions are, however, essentially the same as those considered and rejected by the Supreme Court in Permian. 390 U.S. at 818-822, 88 S.Ct. 1344.

Inflation. The Commission did not expressly account for inflation between the 1972 test year and the 1976 effective date of the rate. The producers say such treatment deprived them of 12.3 cents/mcf of their true cost, and that the rate contains no provision for either escalation or biennial review, so its return will be further eroded by future inflation. The rate did, however, take inflation into account in other respects. The joint cost formula uses 1975 data. The Commission provided that producers suffering a significant revenue deficiency because of inflation would be entitled to special relief.

Time Value of Money. The producers say Permian methodology should be adjusted with a discounted cash flow analysis which would take into account the time value of money. Ideally, they are correct. The Permian method allows recovery of the entire cost of service as measured by a test year. That cost compensates for expenditures incurred many years previous. The Commission, however, could reject the producers’ suggested changes. The time value is not as crucial for flowing gas as it is for new gas, because the wells are already partially depleted and the cost of service was based on the 1972 test year, not the lower cost of earlier years.

Other Objections include: Regulatory Lag. The Commission did not compensate for the time period between 1972 and 1976 when Opinion No. 749 was not in effect, even though the producers were then bearing the burden of the 1972 test year costs. Capitalization. The Commission refused to capitalize exploration and development expenditures. Net Book Value. Using net book value as a base for rate calculation resulted in a “true” return here of only nine percent. Exploration and Development. The Commission calculated the exploration and development component by measuring 1972 exploration and development expenditures against 1972 production. (See 1972 Test Year, supra.) The two are not related. The Commission should have measured exploration and development expenditures against reserve additions for that year. If it had, the exploration and development cost component would have been 14.23 cents/mcf, not 6.26 cents/mcf.

These other objections are met by the Commission’s two general justifications for its rejection of the producers’ position. First, the Commission noted that the burden of providing a record to support a particular costing methodology was on the producers. It found the producers had not demonstrated a system which “better advances the interests of the producers and equally protects the consumer public.” On review, the producers have not shown that assessment by the Commission to be in error.

Second, the Commission noted that several elements of its overall national rate design provide a return over and beyond historical cost, and so counterbalance any error that may have been made. For example, the choice of the 1972 test year and the provision in the rate for new gas, Opinion No. 770, affirmed American Public Gas Ass’n, supra, which allows flowing gas to “rollover” to the rates for new gas as old contracts expire. These considerations warrant the Commission’s renewed use of the Permian methodology. National ratemaking is often an imprecise business. The Commission is entitled to structure the national rates so they fit together, and to honor the burden of proof that protects consumer interests.

The producers complain that the rate is an unconstitutional taking of their property, but the plain fact is that this Opinion No. 749 increases their income by $503,000,-000 a year. That is income over and above the contracts they negotiated and the area rates previously found just and reasonable. The Commission has adopted a reasoned approach, and has arrived at an end result which increases producer income and cannot be said to be beyond the zone of reasonableness allowed by the statute.

Vintaging

The combined effect of Opinion No. 770, which established the present price of new gas, and the Opinion No. 749 here, for pre-1973 gas wells, is to price gas from pre-1973 wells at 29.5 cents/mcf, while gas from post-1974 wells earns $1.42/mcf. The gap due to vintaging is thus $1.12/mcf. Atlantic Richfield, with support from the other producers, argues that this disparity, by itself, violates the “end result” test.

The argument is straightforward. While Permian approved vintaging, the Supreme Court allowed it only “if [the Commission] has permissibly found that such differences will effectively serve the regulatory purposes contemplated by Congress.” 390 U.S. at 798. In that case, the vintage disparity was 2 cents/mcf. Here, the gap is almost four times larger than the flowing gas rate. Atlantic Richfield says this difference cannot possibly serve the Commission’s regulatory purpose. It creates multiple, widely varied prices where a competitive market would tend to have the product closely priced. It encourages excessive demand for pre-1973 gas, known as flowing gas, and does not provide funds to develop new gas supplies. It discriminates unjustly between consumers of flowing gas and those who must pay for new gas. It condemns producers to a liquidating position because the money they earn on old gas will not finance the discovery of an equivalent volume of new gas.

The problem with Atlantic Richfield’s position is that policy considerations support the Commission’s decision, and the task of balancing rests with the Commission, not the courts. The statute allows the Commission to ignore the cost of replacing flowing gas. In Hope Natural Gas Co., supra, the case from which the “end result” test comes, the Supreme Court decided that question. While the case law may sometimes speak in terms of approximating market conditions, the market price may be defined as “a selling price which covers costs plus a reasonable rate of return on capital, thereby avoiding monopoly profits.” Northern Natural Gas Co. v. FPC, 130 U.S.App.D.C. 220, 226, 399 F.2d 953, 959 (1968). The producers get that from this rate. While the dollar consequences of the Commission’s adherence to vintaging are extreme, the law supports the decision, and the “end result” has not been shown to be so injurious to the producers as to justify judicial intervention.

Royalty Costs

Royalty owners have sued producers to collect contract payments measured according to intrastate market value instead of the regulated price at which the gas is sold. If the royalty owners are successful, increased royalty costs over those considered in fixing this rate will be incurred by the producers. The producers asked the Commission to include in this national rate a provision for individual rate adjustment to compensate them for such increased royalty costs. The Commission denied that request.

The Commission in part based its denial on its prior decision determining that it did not have jurisdiction to grant compensation based on market value. This Court has subsequently set aside that decision and remanded the case for further consideration of the special relief request for such royalty costs. Pennzoil Producing Co. v. FPC, 553 F.2d 485, 488 (5th Cir. 1977), petition for cert. filed 46 U.S.L.W. 3380 (Dec. 6, 1977).

In their brief to this Court, Commission counsel state: “In the event it is ultimately determined that the Commission has [the authority to grant the special relief requested in Pennzoil], the Commission will provide procedures for the recovery of such costs.” The Commission has wide discretion in selecting a forum for the resolution of issues. Fort Pierce Utility Authority v. FPC, 526 F.2d 993, 999 (5th Cir. 1976). Under these circumstances, we will not fault the Commission for failure to include a provision for individual rate adjustment that might be appropriate because of increased royalty costs.

Waiver of Refund Credit

In the past, because of the time lag in developing a rate for natural gas, producers have sold gas at filed rates later found to be unjust and unreasonable. The Commission would then order a refund of all money collected over the established rate. In several area rate proceedings, the Commission allowed a “refund credit” which reduced the amount of refund owed by 1 cent for each mcf of new gas dedicated and sold in the interstate market. The purpose of the credit was to provide an incentive for new dedications. The Supreme Court approved the refund credit technique in Mobil Oil Corp., 417 U.S. at 316-319, 94 S.Ct. 2382. See generally Note, Refund Beneficiaries and Refund Credits Under the Natural Gas Act, 41 U.Chi.L.Rev. 792 (1974). Once new reserves were dedicated to the interstate market to take advantage of this incentive program, it would take several years to work off the refund requirement because the 1 cent per mcf was credited only as the gas was sold.

In this proceeding, the Commission determined that producers who had responded to this incentive program and had dedicated gas reserves to the interstate market that would be eligible for refund credit when sold, would get the credits only for that gas actually sold at the area rates. If a producer wanted to sell the gas from those reserves at the new higher national rate, it would have to waive any refund credit claimed for the volumes of gas so sold.

The producers claim the required waiver exceeds the Commission’s authority under the Natural Gas Act, because it lacks a reasoned foundation and leaves them with a choice the Commission could not permissibly impose. Either they must waive the credit, to which they are entitled under Mobil, or they must charge an area rate which is below the national ceiling rate that the Commission has now found just and reasonable, and that the statute permits them to receive. 15 U.S.C.A. § 717c, d.

On this part of its order, the Commission has fallen short of its duty to exercise “reasoned consideration” of the issue before it. The Commission rested its approval of the waiver on a misreading of case authority and on an unsupportable view that the producers would otherwise get a “double recovery.”

The Commission misapplied this Court’s opinion in Shell Oil Co., 520 F.2d at 1082-1083, which approved a waiver of the refund credit requirement for new dedications entitled to earn the higher rate Opinion No. 699 established for new gas. In its 50 cents/mcf rate for “new” gas the Commission had included a different incentive element, to obtain new dedications, which superseded the 1 cent/mcf incentive bonus added to the area rate. This Court concluded the Commission could reasonably substitute one method of encouraging new dedications (a higher price) for another method (allowing refund credits). The Court said:

Replacing one incentive structure with another or, viewed in another light, providing a new alternative rate system, is an exercise of Commission discretion which does not amount to retroactive rate regulation. See Moss v. FPC, 164 U.S.App.D.C. 1, 502 F.2d 461 (1974) [affirming similar waiver for new dedications].

Shell Oil Co., 520 F.2d at 1083.

The Commission cited this language and noted, without elaboration, “[w]e find that the same reasoning is applicable to this proceeding.” That reasoning, however, has nothing to do with what the Commission has done in this rate. There can be no direct incentive for new dedications to which this rate would apply, because all gas covered by this rate has already been dedicated. So there is no replacement of one incentive with another. The credits were promised for dedications which have now already been made. Once the reserves were dedicated in order to take advantage of that promise, the gas flowing from those reserves must be sold in interstate commerce. See Mobil Oil Co., 417 U.S. at 299 and n. 18, 94 S.Ct. 2382; Placid Oil Co. v. FPC, 483 F.2d 880, 906 (5th Cir. 1973); Summers, Oil & Gas § 924 (Flittie ed. 1966). The producers have no choice. There was nothing left to do but determine the amount of the credit at the rate of 1 cent/mcf for the amount of gas sold from year to year until the refund owed had been worked off. This credit was in addition to a price that had been determined to be just and reasonable, without an alternative incentive component, the area rate. By requiring waiver, the Commission is taking away from them the benefit upon which they relied in making their dedications.

The Commission somehow thought this new rate for flowing gas provided some non-cost benefit to those producers equivalent to the 1 cent/mcf credit they were required to waive. It said:

Permitting a producer to receive the rate established in Opinion No. 749 and to retain the right to utilize gas volumes to discharge its prior refund obligations, in our opinion, allows such producer to receive a “double benefit.” We cannot rationalize any justification for granting such a bonus.

R. 1701 (footnote omitted). The “double benefit” language is curious. This rate gives no “benefit” to any producers for having dedicated the pre-1973 gas to the interstate market. The rate gives them a just and reasonable rate for that gas. This does not accrue from the largess of the Commission but from the Commission’s fulfilling its statutory obligation. The producers by law are entitled to a just and reasonable rate. The 1 cent/mcf refund credit in addition to the just and reasonable area rate was bargained for in order to get new gas for the interstate market, presumably gas that the interstate market would otherwise have missed. When the bargain was accepted by the producers by making an irrevocable dedication, they were then entitled to the bargained-for credit refund as the gas was sold at a just and reasonable rate. The Commission, by this action in setting a “new” rate for “old” gas, has determined that the area rates are no longer just and reasonable. The rate set here is just and reasonable. To require the producers to give up the refund credit to get a just and reasonable rate for their gas reneges on a government commitment. The requirement constitutes arbitrary action which exceeds the power of the Commission under the Natural Gas Act.

The part of the Commission order requiring waiver of refund credits for sales made at the new rate must be set aside.

AFFIRMED IN PART.

SET ASIDE IN PART.  