
    SHELL OIL COMPANY et al., Petitioners, v. FEDERAL POWER COMMISSION, Respondent, and consolidated cases. In re NATIONAL RATE CASES FOR NEW GAS.
    Nos. 74-3330, 74-4036, 74-4040, 74-4044, 74- 4038, 74-4042, 74-4147, 75-1396, 74-4233, 75-1123, 75-1164, 75-1246, 75-1266, 75- 1268, 75-1270, 75-1614, 75-1620, 75-1615, 75-1617, 75-1616, 75-1618, 75-1619, 75-1621 to 75-1623, 75-1499, 75-1500, 75-1590, 75-1756.
    United States Court of Appeals, Fifth Circuit.
    October 14, 1975.
    Rehearing Denied Nov. 3, 1975.
    Rehearing Denied in No. 74-3330 Jan. 14, 1975.
    See 525 F.2d 1261.
    
      David G. Stevenson, Tulsa, Okl., for Amerada Hess Corp.
    Frederick Moring, Washington, D. C., for Associated Gas Distributors.
    Edward J. Kremer, Jr., Dallas, Tex., for Atlantic Richfield Co.
    David M. Whitney, Houston, Tex., for Burmah Oil & Gas Co.
    William C. Charlton, Pampa, Tex., for Cabot Corp.
    Justin R. Wolf, Washington, D. C., for The California Co.
    Samuel H. Riggs, Jr., Tulsa, Okl., for Cities Service Oil Co.
    Giles D. H. Snyder, Charleston, W. Va., for Columbia Gas Transmission Corp.
    Tom Burton, Houston, Tex., for Continental Oil Co.
    
      Paul W. Wright, Houston, Tex., for Exxon Co.
    Richard F. Generelly, Washington, D. C., for General American Oil Co. of Texas.
    Edward J. Grenier, Jr., Washington, D. C., for General Motors Corp.
    B. James McGraw, Tulsa, Okl., for Gulf Oil Corp.
    L. Dan Jones, Washington, D. C., for Independent Petroleum Association of America.
    Jerome J. McGrath, Washington, D. C., for The Interstate Natural Gas Association of America.
    William A. Sackmann, Findlay, Ohio, for Marathon Oil Co.
    Philip R. Ehrenkranz, Washington, D. C., for Mobil Oil Corp.
    Paul W. Mallory, Chicago, 111., for Natural Gas Pipeline Co. of America.
    Patrick J. McCarthy, Omaha, Neb., for Northern Natural Gas Co.
    Malcolm H. Furbush, San Francisco, Cal., for Pacific Gas & Electric Co.
    Gordon Gooch, Washington, D. C., for Pennzoil Co., Tenneco Oil Co., Texasgulf, Inc., and Rodman Corp.
    John L. Williford, Bartlesville, Okl., for Phillips Petroleum Co.
    Richard A. Solomon, Washington, D. C., for The Public Service Commission of the State of New York.
    Donald J. Richardson, Jr., San Francisco, Cal., for San Diego Gas & Electric Co.
    Morton L. Simons, Washington, D. C., for Sen. James Abourezk.
    David C. Henri, Tulsa, Okl., for Skelly Oil Co.
    Thomas D. Clarke, Los Angeles, Cal., for Southern California Gas Co.
    Lilyan G. Sibert, Houston, Tex., for Tennessee Gas Pipeline Co.
    Roger L. Brandt, Houston, Tex., for Texaco, Inc.
    Kenneth L. Riedman, Jr., Los Angeles, Cal., for Union Oil Co. of California.
    Tilford A. Jones, Bethesda, Md., for United Distribution Companies.
    W. DeVier Pierson, Washington, D. C., for United Gas Pipe Line Co.
    Thomas G. Johnson, Houston, Tex., for Shell Oil Co.
    Pat F. Timmons, Houston, Tex., for Superior Oil Co.
    Thomas W. Derryberry, Sp. Asst. Atty. Gen., Santa Fe, N. M., for State of New Mexico.
    Richard F. Remmers, Oklahoma City, Okl., for Sohio Petroleum Co.
    William H. Emerson, Chicago, 111., for Amoco Production Co.
    Robert F. Starzel, Denver, Colo., for Kerr-McGee Corp.
    Arthur S. Berner, Houston, Tex., for Inexco Oil Co.
    Neal Powers, Jr., Houston, Tex., for Texas Production Co. and Freeport Minerals Co.
    Charles F. Wheatley, Jr., Washington, D. C., for American Public Gas Assn.
    James W. McCartney, Houston, Tex., for Texas Eastern Transmission Corp. and Transwestern Pipeline Co.
    Paul W. Hicks, Dallas, Tex., for Placid Oil Co. and Hunt Oil Co.
    George W. McHenry, Sol., Robert Per-due, Deputy General Counsel, Washington, D. C., for respondent Federal Power Commission.
    Before BELL, CLARK and RONEY, Circuit Judges.
    
      
       In which the Federal Power Commission is Respondent and the following are Petitioners:
      Rodman Corp., 74-4036, 4040, 4044, 4038, 4042; Texas Eastern Transmission Corp. and Transwestern Pipeline Co., 74-4147, 75-1396; General American Oil Co. of Texas, 74-4233; Continental Oil Co., 75-1123; Superior Oil Co., 75-1164; Placid Oil Co. and Hunt Oil Co., 75-1246; Inexco Oil Co., 75-1266; Texas Production Co., 75-1268; Freeport Minerals Co., 75-1270; Associated Gas Distributors, 75-1614, 1620; James Abourezk, 75-1615, 1617; American Public Gas Association, 75-1616; Public Service Commission of New York, 75-1618; Gulf Oil Corp., 75-1619; Sohio Petroleum Co., 75-1621; Amoco Production Co., 75-1622; United Distribution Companies, 75-1623; Kerr-McGee Corp., 75-1499; Phillips Petroleum Co., 75-1500; Exxon Corp., 75-1590; and Texaco, Inc., 75-1756.
    
   RONEY, Circuit Judge:

On this review of consolidated cases entitled National Rate Cases For New Gas, we sustain the Federal Power Commission’s establishment of a national rate for jurisdictional wellhead sales of natural gas. In so doing, for the first time in this Circuit, we give judicial imprimatur to the promulgation of a rate order through rulemaking procedures in contrast to formal adjudicatory procedures; we sustain a national rate for wellhead sales of natural gas in contrast to the individual producer rates and the area rates that have heretofore been approved; and we hold that the rate structure prescribed withstands various attacks of the producer, purchaser and consumer petitioners against diverse findings and conclusions of the Commission. In sum, we hold the petitioners have failed to show either that the rate structure is unjust and unreasonable, under the limited judicial review permitted this Court, or that the Commission proceeded in disharmony with statutory and judicial requirements.

FACTUAL BACKGROUND

The history of producer regulation under the Natural Gas Act has often been recounted in judicial opinions, necessitating here only a brief statement of the historical background of this national rate proceeding. From 1938 when Congress passed the Natural Gas Act, 15 U.S.C.A. § 717 et seq., until 1954, the Federal Power Commission eschewed regulation of the price paid to the producer at the wellhead for natural gas. The Commission viewed its jurisdiction as limited to regulation of the pipelines which transported and sold natural gas in interstate commerce. The number of companies which the Commission regulated was fairly small. The regulation of the pipelines lent itself to the traditional cost-of-service mode of utility regulation on an individual producer basis.

In 1954 the Supreme Court ruled that the FPC was required to regulate wellhead sales of natural gas by independent producers, defining such producers as “natural gas companpes]” within the meaning of § 2(6) of the Act, 15 U.S.C.A. § 717a(6). Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1954). Independent producers are those producers which do “not engage in the interstate transmission of gas from the producing fields to consumer markets and [are] not affiliated with any interstate natural-gas pipeline company.” Phillips at 675, 74 S.Ct. at 795. The jurisdiction recognized by Phillips increased the number of Commission-regulated entities by over thirty-three hundred. This increase in regulatees made the burden of individual regulation unfeasible and forced the Commission to seek an alternative method. Area rate regulation resulted.

The Commission instituted proceedings to regulate the wellhead prices charged by independent producers for certain geographical areas throughout the United States. The Supreme Court held this to be permissible under the Natural Gas Act in its landmark area rate regulation decision, Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968). The guidelines set forth in that case have since been used by all Courts of Appeals called upon to review Commission area rate orders. See, e. g., Southern Louisiana Area Rate Cases, 428 F.2d 407 (5th Cir.), on reh., 444 F.2d 125 (5th Cir.), cert. denied, 400 U.S. 950, 91 S.Ct. 243, 27 L.Ed.2d 257 (1970) [So.La. I].

The Commission eventually delineated seven geographical areas and established ceiling prices for natural gas sold from those areas by independent producers. Pipeline producers and pipeline affiliated producers were subject to different rate regulation. The Commission has now decided that what it once hoped would be the mainstay of producer rate regulation, the area rate structure, is not the panacea it had sought. Consequently, in this case we are asked to review the next experimental phase in producer regulation, a national rate for new natural gas.

STRUCTURE OF THE NATIONAL RATE FOR NEW GAS

Despite protestations from many producers and pipelines, the Commission adhered to cost as the basis for the new national rate. The FPC utilized the methodology developed by it in Area Rate Proceeding (Permian Basin), 34 FPC 159 (1965), aff’d, Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968), as modified in the second Southern Louisiana proceeding, Area Rate Proceeding (Southern Louisiana), 46 FPC 86 (1971), aff’d, 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) [So.La. II]. Basically the rate was determined by projecting the average cost of finding and producing “new gas,” i. e., gas discovered after January 1, 1973, over the estimated life of the producing wells and adding a 15 percent annual rate of return. Historical items of cost were predicted for the future to attempt to insure that the producer would recover its actual expenses at the time work is done. Relating these estimated costs to the commonly accepted unit of gas sold to the consumer results in a maximum allowable rate for natural gas in cents per Mcf, i. e., thousand cubic feet.

Although the rate determined in this proceeding was based on the cost of finding nonassociated natural gas, i. e., gas occurring independently from other extractable forms of petroleum, casing-head gas is also eligible for the new rate, even though it might cost less to produce. The Commission has long refused to compute separately the cost of casing-head gas because of the difficulty in allocating the production costs between such gas and the oil produced from the same well. See, e. g., Permian, 390 U.S. at 761, 88 S.Ct. 1344. Likewise, this national rate will, under certain conditions, apply to substantially increase the price of “old” gas as well, even though the cost of such pre-January 1973 gas did not figure in the computation of the national rate.

While sales of pipeline producers previously had been vintaged by the date when the natural gas lease was acquired by the pipeline, the Commission decided in Opinion No. 699 — H to allow pipeline producers to be eligible for the new rate on the same basis as independent producers. The Commission saw no reason to treat wells commenced by a pipeline any differently than those commenced by independent producers for costing purposes.

In arriving at an ultimate rate figure under this method, the Commission was required to resolve many disputed issues of “pure” fact, assign values to rate components based on a combination of fact and policy considerations, and make policy decisions regarding which components to include, where to include them, and how they should be included. Thus, while the final result is a figure which must have some mathematical relationship to these various considerations, the premises from which the figure is derived are far from mathematically exact. Because of this elasticity in the rate equation, courts traditionally • refuse to be drawn into choosing “numbers” which actually represent policy choices properly available to the Commission, the governmental unit to which Congress has primarily committed the regulation of the natural gas industry.

The Commission developed both a “high” and a “low” cost figure by making various choices among the alternatives available to it. The overall cost determination was based on an evaluation of the following components: (1) Successful Well Cost, (2) Dry Hole Cost, (3) Lease Acquisition Cost, (4) Cost of Other Production Facilities, (5) Other Exploration Cost, (6) Exploration Overhead, (7) Production Operating Expense, (8) Net Liquid Credit (subtracted from costs), (9) Royalty Expense, (10) Recompletion and Deeper Drilling Cost (stipulated), (11) Regulatory Expense (stipulated), (12) Return on Production Investment, and (13) Return on Working Capital. The Commission did not include an element of cost for federal income tax but established a procedure whereby a producer can gain an increase for taxes paid upon jurisdictional activities by making an individual showing that such expense was actually incurred.

Various of these cost components have been attacked on appeal and will be discussed more fully hereinafter, but first a brief description of the FPC methodology may be helpful.

Like every cost factor, Successful Well Cost must be converted to cents per thousand cubic feet, the base unit. Ideally, to do this the Commission would divide the number of feet drilled in a given year which resulted in finding nonassociated natural gas into the nonassoeiated natural gas reserves discovered as a result of such drilling. The quotient is called the “productivity” of the drilling and is expressed in Mcf of newly-discovered gas per foot of drilling (Mcf/ft). The cost of drilling a foot of a successful well (<t/ft) would then be divided by the productivity (Mcf/ft) with the quotient being expressed in the desired unit, cents per thousand cubic feet (tf/Mcf). This computation is not feasible as described, however, because of the manner in which data. concerning the natural gas industry is collected. Drilling footage is recorded in the year it occurs, but no one compiles reserve additions by wells drilled. Instead, “reserves added” are computed on a net annual basis, taking into account reductions in reserves which have been previously overestimated. Thus, there are variables other than successful well drilling which affect the net nonassociated reserve additions for a given year. Nonetheless, the FPC must compute productivity, so it used the only information available to it for reserve additions, the American Gas Association reserve studies and the various footage compilations.

Dry Hole Cost (cost of drilling unsuccessful wells) was separately computed by dividing the cost per foot drilled (<t/ft) by the productivity of successful wells (expressed in Mcf/ft), computed as previously discussed, with the quotient again being in cents per thousand cubic feet (<f/Mcf). The figure so obtained was then adjusted upward to reflect the greater depth and thus higher costs and the offset of higher success ratio at those depths for gas well drilling as compared to oil well drilling.

Lease Acquisition Cost, expressed in dollars, was reduced to the base unit, 0/Mcf, by determining the relationship between total Successful Well Cost and total Lease Acquisition Cost in a given year. The ratio of the former cost to the latter cost was then multiplied by the previously determined Successful Well Cost per unit, the result being Lease Acquisition Cost per Mcf.

Cost of Other Production Facilities is the cost of those production facilities not included in Successful Well Cost. To convert this cost to the base unit, the Commission divided total Other Production Facilities Cost by total Successful Well Cost and multiplied the unit Successful Well Cost by the resultant ratio.

Several elements were used in computing Other Exploration Cost: the unit Lease Acquisition Cost component (expressed in (p/Mcf) was multiplied by the ratio of total national Other Exploration Cost to total Lease Acquisition Cost. Other Exploration Costs are the direct costs, other than the cost of drilling a dry hole, which are experienced in the search for natural gas. These should be distinguished from the Exploration Overhead, which was separately computed as a component of the rate structure.

Exploration Overhead was derived by multiplying the sum of unit Dry Hole Cost and Other Exploration Cost by the ratio of National Exploration Overhead Cost divided by National Other Exploration Cost, using a multi-year average.

Production Operating Expense, the daily costs of labor, energy, and other expenses for operating a successful well, was calculated by dividing operating expenses for gas leases by the production from gas leases (expressed in Mcf) to obtain a unit value quotient.

Net Liquid Credit, unlike the other components of the cost based rate, represents receipt of revenue incident to the production of natural gas, and, therefore, is a credit against expenses. In processing natural gas, certain liquifiable hydrocarbons, such as propane, butane and ethane are extracted and liquified. These liquids are then sold and the experienced revenue from these per Mcf of natural gas was subtracted as the Net Liquid Credit.

Royalty Expense represents the percentage of the gross receipts which a producer must pay to the landowner for the privilege of extracting from the reserves underlying his land. It was computed by applying a percentage to the gross receipts.

Two cost components were stipulated by the parties, which stipulations were accepted by the Commission as representative costs: Recompletion and Deeper Drilling Cost and Regulatory Expense. Recompletion and Deeper Drilling Costs are incurred in rejuvenating old wells to extend their productive life. Regulatory Expense is the cost per Mcf which is directly attributable to the cost of filing required reports, of participating in proceedings such as the instant one, and of other necessary activities related to both state and federal regulation.

Return on Production Investment and Return on Working Capital were computed by applying the annual rate of return decided upon to certain predicted costs.

Certain of the cost items are included in the “rate base” upon which the Commission allows the producers to receive a percentage return on expenses, some are not. The decision as to which items are properly part of the rate base for return purposes is one which involves policy as well as economic considerations. The items which are not included in the rate base are still recoverable as expenses. The cost components comprising the rate base, and, therefore, on which a rate of return is allowed are Successful Wells, Dry Holes, Lease Acquisition, Other Production Facilities, Other Exploration, Exploration Overhead, and Recompletion and Deeper Drilling. The remaining items, Production Operating Expense, Net Liquid Credit, Royalty Expense, and Regulatory Expense, are treated as annual credits or expenses. Having decided on which items a return would be allowed, the Commission computed the unit cost of that return at a 15 percent annual rate using a discounted cash flow economic model.

In computing all costs to be used in the above-described model, the FPC recognized that it could not be exact and, therefore, made a number of different assumptions regarding each component. In this manner the Commission arrived at the range of what it considered reasonable costs, with a “low” total cost based primarily on the low assumptions and a “high” total cost based primarily on the higher assumptions. For example, in computing drilling costs for the 1973-74 time period for which the rate was designed, the “low” cost was actual experienced cost in 1972, whereas, the “high” cost was the 1972 cost projected by the least squares regression method in order to account for a rising trend in drilling costs. Similarly, the important element, productivity, was computed to produce a high and a low estimate: as productivity has been declining recently, a longer period (10 years) was averaged to produce the “low” cost than was averaged to produce the “high” cost (7 years). The Commission asserts that it set the 15 percent annual rate of return high enough above a traditionally non-confiscatory rate of return to put some noncost factors into the rate to make the interstate market more competitive with other markets.

Ultimately, the FPC determined that a reasonable rate could fall between 48 cents and 52 cents, based on all factors. From this range the Commission chose 50 cents per Mcf as the rate it would allow on jurisdictional natural gas subject to the . No. 699 series of opinions.

A. Ancillary Provisions in the Rate Structure

Besides a determination of the rate and the natural gas to which it would apply, the Commission’s order contains a number of ancillary provisions, some of which are important to an understanding of the rate structure.

First, the order made provision for special relief in unusual circumstances where the rate is not sufficient to recover the cost of producing natural gas already dedicated to the interstate market. The burden is on the producer with the above average costs to justify an additional price for its gas. This is not the only avenue of extraordinary relief for producers who may be adversely affected by the national rate structure, however. The FPC has standing regulations which afford relief to producers who face an increase in costs. 18 C.F.R. § 2.76 (1974). A producer who is seeking special relief because of federal income taxes actually paid may use procedures established in this proceeding for such relief. Thus, although federal income taxes are not allowed as a cost in the basic “cost-based” rate, they are recoverable, if actually paid, by use of a special relief proceeding.

Second, the rate structure provides for a biennial review of the rate and the rate’s efficacy in accomplishing the goals which the FPC is seeking to attain. It is the Commission’s stated policy that any increased rate found just and reasonable in each biennial review will be allowed for all natural gas which is subject to the present proceeding.

Third, the rate structure provides for a fixed annual rate escalation, irrespective of any additional proof of increased costs. Under this provision gas subject to this proceeding is allowed a one-cent per Mcf escalation in price as of January 1 of each year.

B. Scope of the Order

Besides the requirement that the natural gas be produced within the continental United States, or offshore thereof, exclusive of Alaska, the current scope of the order is primarily defined by the interaction of three possible occurrences relating to natural gas distribution and production. If any one of them occurred on or after January 1, 1973, the sales of natural gas from the affected well are eligible for the new national rate under the Commission’s regulations. The three sale situations which justify the new rate were described by the Commission in Opinion No. 699 — H:

(i) The sale is made from a well or wells commenced on or after January 1, 1973;
(ii) Sales made pursuant to contracts for the sale of natural gas in interstate commerce for gas not previously sold in interstate commerce prior to January 1, 1973, except pursuant to the provisions of 18 C.F.R. §§ 2.68, 2.70, 157.22, or 157.29 (including sales made pursuant to those sections as modified by Federal Power Commission Order No. 491, et al.) [temporary emergency sales of various sorts], or 18 C.F.R. § 2.75(n), where such sales are initiated on or after January 1, 1973, provided that no certificate for the subject sale has been issued under the optional procedure (18 C.F.R. § 2.75);
(iii) Sales made pursuant to contracts executed prior to or subsequent to the expiration of the term of the prior contract where the sales were formerly made pursuant to permanent certificates of unlimited duration under such prior contracts which expired of their own terms on or after January 1, 1973, or pursuant to contracts executed on or after January 1, 1973, where the prior contract expired by its own terms prior to January 1, 1973.

The propriety of applying the new rate to sales made under (i), the “wells commenced” standard, and (ii), new long-term commitments of natural gas to interstate commerce is not questioned in this proceeding.

The application of the new rate to category (iii), sales made pursuant to renewal contracts of natural gas previously committed to interstate commerce, is challenged on this review as unjustifiable.

STANDARD OF REVIEW

It is always necessary to keep in mind the limits of judicial inquiry when we are called upon to review an order issued by the Federal Power Commission. Although these limits have been variously explicated over the years, they have never been diverted from the “end result” test which finds its genesis in the earliest Supreme Court cases reviewing orders under the Natural Gas Act. FPC v. Hope Natural Gas Co., 320 U.S. 591, 64 S.Ct. 281, 88 L.Ed. 333 (1944); FPC v. Natural Gas Pipeline Co. of America, 315 U.S. 575, 62 S.Ct. 736, 86 L.Ed. 1037 (1942). The end result test was tailored to area rate orders by the Supreme Court in Permian Basin Area Rate Cases, 390 U.S. 747, 766-767, 791-792, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968). This Court has, on various occasions, discussed our understanding of the Permian prescription. See Shell Oil Co. v. FPC, 491 F.2d 82, 85 (5th Cir. 1974); Placid Oil Co. v. FPC, 483 F.2d 880, 888-890 (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); Southern Louisiana Area Rate Cases, 428 F.2d 407, 417-418 (5th Cir.), on reh. 444 F.2d 125 (5th Cir.), cert. denied, 400 U.S. 950, 91 S.Ct. 243, 27 L.Ed.2d 257 (1970).

The issue which we must ultimately resolve is whether the end result of the order is “unjust and unreasonable.” In assessing the facts from which this ultimate conclusion is derived, we are guided by four elements which delimit the scope of our authority:

(i) the well-known statutory “substantial evidence” standard, (ii) a judicially recognized “presumption of validity” implied from the congressional limitation, (iii) the long-standing “total effect” test of FPC v. Hope Natural Gas Co., 1944, 320 U.S. 591, 64 S.Ct. 281, 88 L.Ed. 333, and (iv) a “zone of reasonableness” to compensate for the necessarily imprecise nature of cost determinations and the inherent difficulty of the regulatory undertaking.

Placid Oil Co. v. FPC, supra at 889 n. 6.

The fact that our vision is tunneled does not relieve us, however, from our duty to look at the Commission order from all angles. The Supreme Court has made clear

. that the responsibilities of a reviewing court are essentially three. First, it must determine whether the Commission’s order, viewed in light of the relevant facts and of the Commission’s broad regulatory duties, abused or exceeded its authority. Second, the court must examine the manner in which the Commission has employed the methods of regulation which it has itself selected, and must decide whether each of the order’s essential elements is supported by substantial evidence. Third, the court must determine whether the order may reasonably be expected to maintain financial integrity, attract necessary capital, and fairly compensate investors for the risks they have assumed, and yet provide appropriate protection to the relevant public interests, both existing and foreseeable. The court’s responsibility is not to supplant the Commission’s balance of these interests with one more nearly to its liking, but instead to assure itself that the Commission has given reasoned consideration to each of the pertinent factors.

Permian Basin Area Rate Cases, supra at 791-792, 88 S.Ct. at 1373 (emphasis supplied).

In the review of area rate cases, however, our already narrow scope of review has been tempered even further by recognition of the experimental nature of area regulation. E. g., Placid Oil Co. v. FPC, supra at 889-890; Southern Louisiana Area Rate Cases, supra at 418; see Permian Basin Area Rate Cases, supra passim. The “kid glove” review resulting from the “experiment rationale” has led this Court and the Supreme Court to accept findings and reasoning by the Commission as adequate, even though both courts have expressed serious misgivings about the ultimate accuracy of the FPC’s conclusions. Accordingly, on at least two occasions we have “affirmed” or “enforced” FPC orders while expressing our concern about the marginal adequacy of the FPC orders. We have specifically reserved to the Commission the authority to make retroactive changes to the very orders we “affirmed” as being supported by substantial evidence. Southern Louisiana Area Rate Cases, supra at 421, 426 n. 46, 427, 431, 434-444; 444 F.2d at 126-127. See Shell Oil Co. v. FPC, supra at 87-88. The FPC responded to our admonition with a more extensive study of the problem in the Southern Louisiana Area, and the resultant area rate order was affirmed by both this Court and the Supreme Court. 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).

To affirm the action of the Commission on review here requires continuation of the heightened deference to the Commission’s expertise inherent in the “experiment doctrine.” Opinions 699 and 699 — H assert many factual conclusions and regulatory justifications without explicating for this Court the factual predicates or assumptions upon which such decisions are based. We have concluded, however, that national rate regulation is still experimental and we must apply a standard of review requiring heightened deference to the Commission’s expertise in such experimental regulations.

The first area rate regulation proceedings related to the Permian Basin Area and began in 1960. Prior to the establishment of the national rate in this proceeding, the FPC had considered area rate structures in ten proceedings involving seven distinct geographical areas. Seven of these proceedings were the subject of judicial review and comment, with two of those receiving review by both a court of appeals and the Supreme Court. An examination of the area rate structures and the cases in which they were reviewed reveals that the FPC has continued to experiment with various combinations of contingent escalations, automatic escalation, vintaging, refund workoffs and the like in an attempt to alleviate the national natural gas shortage by stimulating exploration and development. At the same time the Commission has persisted, in spite of the protestations of the producers, in relying upon a cost-based rate as the starting point in an effort to protect the consumer from exploitation in this time of shortage.

The national rate structure under review is a unique combination of provisions which, along with the shift to a national rate itself, demonstrates that the Commission does not believe that any of the total rate structures which it developed in the area proceedings had the desired effect of providing developmental incentive while preventing exploitation. The Commission has been unsuccessful in generating ■ additional natural gas reserves for the interstate market within the framework of its congressional mandate. In the face of growing demand for natural gas by the intrastate market, the effort to protect consumer interest as to price is at odds with the long range consumer interest in maintaining an adequate supply of natural gas for the interstate market. Finding and maintaining this point of delicate balance is a difficult task. Congress has chosen the FPC 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.

We must express our regret, however, that the FPC continues to issue orders which would be inadequate but for our “kid glove” treatment. Perhaps one reason the Commission has continued to flounder in the sea of area regulation is its failure to assess the consequences of its various policies. For example, if it does not have reasonable knowledge of the effect a contingent escalation in price will have, it can hardly evaluate the efficacy of having such a provision in the rate structure. Just as we must consider individual elements in our review of an FPC order to insure that it is supported by substantial evidence, so should the Commission examine the effect of each when it is deciding how to compose the rate structure initially. For over fourteen years the Commission has been experimenting in area rate regulation and yet it still “supports” many of the essential elements of its new national rate order with little more than ipse dixit.

We recognize, of course, that the issues in a review such as this are not always separate and distinct, but involve overlapping considerations and resolutions. But a cautionary note should indicate that as experiment lapses into experience, the courts may well expect the Commission to justify its policies with reasoned projections of that once-prototypic policy’s probable net effect. The principle of stare decisis may only lightly touch the standard of subsequent review.

Therefore, with these principles of review in mind, we give a limited review to the Commission’s actions.

IS A NATIONAL RATE PERMISSIBLE UNDER THE NATURAL GAS ACT?

The initial inquiry is whether the Commission has the authority to establish a national rate under the Natural Gas Act. It would seem clear that under existing Supreme Court cases there is no legal impediment to the Commission’s choosing a national rate as its method of regulation of wellhead sales of natural gas. In the approval of area rates, the extent of the area does not appear to have been a controlling consideration. To a large extent, the nation is merely a geographically expanded area. The rate set in at least some of the area rate proceedings was based on national data only. The most noteworthy of the Supreme Court cases in this regard is, of course, Permian itself. See 390 U.S. at 761, 88 S.Ct. 1344. We think that the Supreme Court’s approval of an area rate for new gas based partially on national data requires us to uphold the legality of a national rate in this case.

This decision that such rate regulation is permissible comes with some misgivings. A national rate exacerbates the problems noted in Justice Douglas’ dissent from Permian as to the rates set for the relatively small geographical area involved in that case.

The area rate orders challenged here are based on averages. No single producer’s actual costs, actual risks, actual returns, are known.
The “result reached” as to any producer is not known.
The “impact of the rate order” on any producer is not known.
The “total effect” of the rate order on a single producer is not known.

Permian Basin Area Rate Cases, 390 U.S. at 829-830, 88 S.Ct. 1344 (Douglas, J., dissenting) (footnote omitted).

The problem with the legality of any area rate, and most particularly a national rate, stems from the fact that the legal role of a reviewing court under the Act involves a bifurcated examination of the “end result” or consequence of any FPC rate order: (1) does the order protect the consumer against excessive rates and charges; and (2) is it consistent with the maintenance of adequate service in the public interest. See generally Atlantic Refining Co. v. Public Service Commission, 360 U.S. 378, 388, 79 S.Ct. 1246, 3 L.Ed.2d 1312 (1959). If this is our Court’s role, as opposed to merely preventing confiscation, then it is arguable that any rate methodology which inherently prevents this Court from performing its role contravenes the Act. Put another way, if there can simply never be “substantial evidence” to support the discretionary exercise of judgment by the Commission, then it could be argued that the method of regulation should be outside the scope of the Act.

The national rate presents such a circumstance. First, since it is largely “prospective” the rate can hardly be confiscatory because the producers may adjust their programs within the structure of the national rate in such a manner to produce the profit which they need, virtually disregarding the Commission’s “reasonable rate of return.” In an industry with high risks of exploration and development, prospective rates arguably could never really work “confiscation” in the constitutional sense. If the producers’ geological surveys remain reasonably accurate, they will usually be able to produce some quantity of gas at a profit within practically any rate structure. They will simply stay out of high cost production that would earn less profit than necessary to attract venture capital. The larger the rate the greater would be the exploration for new reserves. The producers here do not assert the invalidity of the rate on the ground that it is confiscatory.

Assuming then, that the rate is not confiscatory, the use of a national rate with biennial review precludes any court from effective review based on the “end result” of the rate order. First, because there is never one definitive, lasting rate determination, the “end result” of Commission action is in a continuous state of flux. Second, the Commission itself makes no evaluation of the “end result” of its rate order. The Commission concludes that supply and price are directly proportional, i. e., that an increase in the price allowed will result in an increase in supply. From this the Commission reasons that an increase in the price allowed will of necessity do something to alleviate the natural gas shortage which everyone recognizes has developed. But the FPC “found” that there was no way to quantify this relationship and that there is accordingly no way to determine just how much any given price increase will affect the supply of natural gas. There is no reliable estimate as to what new gas will be brought to the interstate market because the Commission reports that such a factually reliable estimate is impossible. Without any such quantification, it is simply impossible for this Court to determine if the “end result” will maintain an “adequate supply in the public interest” or not. Going on past experience for area rates the answer appears to be in the negative, and it is in part for this reason that the FPC has abandoned area rates.

What basically appears to exist, then, is a method of regulation by area, approved by the Supreme Court, at least as an experiment, and a standard of review, similarly prescribed by that Court, which are somewhat incompatible. The method of regulation prevents quantification of the effects of FPC decisions, with only the most general conclusions readily deducible, whereas, this Court is supposed to examine this unquantifiable “end result” to determine whether the FPC order is acceptable.

Having decided, however, that we are bound to approve a national rate method of regulation control of natural gas, our review of the Commission’s actions must be tailored to the practical requirements of the circumstances. Little would be accomplished by on the one hand deciding that a national rate could be established, while on the other hand burdening the Commission with procedural and evidentiary requirements which, though necessary to the legality of individual or smaller area ratemaking, would either prolong or complicate the task of the Commission to the point of impossibility.

DOES RATEMAKING BY THE RULE-MAKING PROCEDURE COMPORT WITH STATUTORY REQUIREMENTS AND CONSTITUTIONAL DUE PROCESS?

The American Public Gas Association (APGA) challenges the Commission’s use of a rulemaking process to set a national rate for natural gas, arguing that by excluding adversarial trial procedures such as formal evidentiary hearings, oral testimony and oral cross-examination, the Commission violated both the requirements of the Natural Gas Act and those of constitutional due process.

In setting a national rate for new gas the Commission went beyond the rudiments of informal rulemaking. On April 11, 1973, the Commission issued a notice of proposed rulemaking, which clearly indicated that the Commission intended to establish by rule nationwide rates for natural gas. 38 Fed.Reg. 10014 (1973). The notice made all large producers respondents to the ratemaking proceeding, and provided for the submission of sworn written comments from all interested parties. Shortly thereafter the FPC gave notice that it intended to establish a single national rate for new gas. 38 Fed.Reg. 14295. These Notices of Rulemaking incorporated Commission cost studies. Pursuant to these Notices over eighty parties representing a broad range of consumer and gas industry interests responded, submitting such sworn testimony and evidentiary data as they desired. Parties thereafter submitted reply comments, this second round of submittals giving them an opportunity to rebut both Commission and privately-generated evidence. In addition to accepting copious written responses to its proposed rulemaking, the Commission held a public conference on the issues of reserve additions and drilling footages, and held two days of oral argument on proposed Opinions Nos. 699 and 699 — H.

In upholding the rulemaking procedures used by the Commission in this proceeding we do not find it necessary to decide what minimum procedures are necessary under the Natural Gas Act and the Administrative Procedure Act. It is unnecessary to enter the colloquy between the Tenth and the District of Columbia Circuits as to whether informal rulemaking (5 U.S.C.A. § 553) or formal evidentiary hearings (5 U.S.C.A. §§ 556, 557) are mandated by the Natural Gas Act. Compare Phillips Petroleum Co. v. FPC, 475 F.2d 842 (10th Cir. 1973) (holding that the informal rule-making provision of the Administrative Procedure Act, 5 U.S.C.A. § 553, applies to FPC rulemaking) with Mobil Oil Corp. v. FPC, 157 U.S.App.D.C. 235, 483 F.2d 1238 (1973) (holding that § 553 rulemaking is insufficient, but §§ 556, 557 hearings are not necessarily required by the Natural Gas Act). But see American Public Gas Association v. FPC, 498 F.2d 718 (D.C.1974) (rulemaking to set area rates did not abuse the Natural Gas Act).

The above-described procedural process which is on review before this Court satisfies even the more stringent requirements of the formal hearing process. The APGA is incorrect in arguing that it has a statutory right to present oral testimony or conduct oral cross-examination. The Administrative Procedure Act provides in pertinent part that

A party is entitled to present his case or defense by oral or documentary evidence, to submit rebuttal evidence, and to conduct such cross-examination as may be required for a full and true disclosure of the facts. In rule making ... an agency may, when a party will not be prejudiced thereby, adopt procedures for the submission of all or part of the evidence in written form.

5 U.S.C.A. § 556(d). The procedures used in setting the national rate neither prejudiced the APGA, nor prevented a full and true disclosure of the facts. On this appeal petitioner APGA has failed to demonstrate that oral, adjudicatory procedures were necessary for a full and fair disclosure of the facts. All private submissions and Commission cost studies were on record either at the time of the Notices in the case of Commission data or after the first round of submissions, and petitioners had ample opportunity for refutation. Evidence of a technical nature is well suited for written dissection. Without concrete demonstration of how the Commission’s reliance on written submittals prejudiced the rights of the petitioners, we cannot say that as a matter of law the FPC was prohibited from adopting the procedures it did, or was required to conduct a full, oral hearing.

As a second line of argument, the APGA contends that even if the rule-making procedure is statutorily correct, it violates the due process rights of affected parties. Constitutional due process “is flexible and calls for such procedural protections as the particular situation demands.” Morrissey v. Brewer, 408 U.S. 471, 481, 92 S.Ct. 2593, 33 L.Ed.2d 484 (1972). In FPC ratemaking we agree with the D.C. Circuit that:

Whatever procedure is utilized, a primary objective is the acquisition of information which will enable the Commission to carry out effectively the provisions of the Natural Gas Act. The ability to, choose with relative freedom the procedure it will use to acquire relevant information gives the Commission power to realistically tailor the proceedings to fit the issues before it, the information it needs to illuminate those issues and the manner of presentation which, in its judgment, will bring before it the relevant information in the most efficient manner.

City of Chicago v. FPC, 458 F.2d 731, 743-44 (D.C.Cir. 1971), cert. denied, 405 U.S. 1074, 92 S.Ct. 1495, 31 L.Ed.2d 808 (1972). The procedures before us serve the purpose of providing the Commission with essential information, while protecting the procedural rights of concerned parties under the circumstances. Private parties were afforded ample opportunity to make their case and to challenge both internally and externally generated evidence of costs and conditions which affected the calculus of a national rate for new gas. Were the Commission to have allowed all interested parties to submit oral testimony and conduct oral cross-examination on an undertaking so massive and novel as setting a national rate for new gas, the proceeding would have taken years, and the Commission’s power to effectively regulate the industry would have been destroyed.

The Public Service Commission for the State of New York brings a more limited due process challenge, arguing that insufficient notice was given that the Commission’s order would extend to renewal contracts which concern flowing (“old”) gas. Under the circumstances, and in light of the necessity to maintain flexible agency procedures, we hold that New York received adequate notice of the enlargement of scope. The Commission’s initial Notice of Proposed Rule-making issued on April 11, 1973, did not indicate that old gas would be affected by the new national rate. Prior to issuance of an FPC order, however, producer groups raised the possibility of extending the order. New York responded to the producer proposals, and, 42 days after the issuance of Opinion No. 699, the FPC granted rehearing of that order, scheduling two days for oral argument, available to any party who wished to participate. Following consideration of both written and oral argument against Opinion No. 699, the FPC issued its final order on rehearing, Opinion No. 699 — H. Under these circumstances the Public Service Commission’s right to make its case against extending the higher new rate to flowing gas was not prejudiced. It had the opportunity to state its position and refute positions to the contrary prior to the issuance of Opinion No. 699, and thereafter New York had a fair opportunity to argufe against the FPC action before the new rate system became final.

REVIEW OF SPECIFIC OBJECTIONS TO NATIONAL RATE

Having concluded that the Commission was within its authority in choosing a national rate structure to regulate independent producers of natural gas, we now examine the manner in which the FPC has applied its chosen methodology to see that the essential elements of the various orders are supported by substantial evidence or that they otherwise withstand review. While the parties have attacked many different components of the Commission’s rate structure, we think only the following merit separate treatment and extended comment. The other issues will be discussed briefly in a miscellaneous portion of this section of the opinion.

A. Application of New Rate to Renewal Contracts

The Commission’s decision to allow the new national rate to be charged for natural gas sold pursuant to renewal contracts replacing old contracts which had expired by their own terms prior to January 1, 1973, where the sales under the prior contracts were made pursuant to permanent certificates of public convenience and necessity of unlimited duration, has been challenged as unjustified by some producers and consumers. The producers, particularly Superior Oil Company, assert that the requirement that there be a newly executed contract is arbitrary. They reason that since under the Commission’s order the delivery of natural gas must continue at the old rate under the certificate, even though there is no private contract, there is no incentive for a pipeline to negotiate and the requirement for a contract is, therefore, anticompetitive. Although the producers can be relieved of this duty to continue deliveries by successful prosecution of an abandonment proceeding, such proceeding is costly both in terms of time, while the lower rate is being received, and in terms of money to prosecute the abandonment.

The consumer interests are represented on this issue by Associated Gas Distributors, New York, and the American Public Gas Association. These parties basically attack the asserted rationale for the Commission decision as being unsupportable in the record.

The Commission reasoned that application of the new, higher rate to “old” gas as primary contracts expire will generate added funds for greater exploration. The FPC thus applied the rate functionally to “old” gas rather than on a cost-related basis, hoping that a higher uniform rate will help alleviate the current severe shortage. The FPC believed that by requiring an old contract to be renegotiated before the new rate is recoverable, the pipeline might be able to negotiate for additional acreage dedication to interstate commerce, or exploration and development activity on previously dedicated acreage or other concessions for the price increase. The consumers argue that in this time of an ever-increasing shortfall of supply the pipelines will simply not be in the position to bargain for or gain any quid pro quo, and, therefore, the Commission should have required some such concession from those producers who are allowed the “windfall” rate increase on “old” gas.

The arguments on each side of this issue have some validity, creating in their juxtaposition a contradiction which buttresses this Court’s deferral to the reasoned expertise of the Commission. Our responsibility is not to supplant the Commission’s choice with one we might find preferable, but simply to make sure that the Commission has exercised its discretion after considering all pertinent options. The FPC has reached a well-considered, expert decision on this issue. The Commission found from evidence in the record that a massive commitment of new funds is necessary to alleviate the natural gas shortage and that internally generated sums are a necessary source of such funds. Additionally, it noted that by phasing out the vintaging practice and attending price variations, all consumers would more equitably bear the burden of financing added exploration. From these facts it reasoned that the national rate structure should be functionally applied to provide some of these funds, placing the burden not just on “new” gas but also on flowing gas for which the primary contract had expired. In so doing the Commission recognized that natural gas is an exhaustible commodity and expressed its belief that today’s consumers should share the burden of finding replacement supplies for the supplies which are being exhausted by the consumers.

Furthermore, the Commission does not consider the matter finally determined. It has expressly reserved for consideration in the biennial review the question of whether the pipelines are negotiating in good faith or trying to take advantage of the producer’s locked-in position, and whether or not the additional funds generated by the application of the new rate increase “the level of monies committed to exploration and development programs and the volumes of new gas supplies dedicated to interstate pipelines under long-term contracts.” Opinion 699 — H, Appendix pp. 564-65 and footnote 121. The Commission has thus remained flexible and is prepared to adjust the national rate structure as necessary. The Commission has struck a tentative balance between the consumer and the investor interests and stated that it is prepared to reevaluate the equilibrium it sought to achieve in the biennial review. Under such a circumstance, no party has carried the heavy burden of showing that the Commission’s balance is tilted so far in either direction as to be unjust and unreasonable in its consequence. We also consider the decision, although not compelled by the evidence, to be supported by the substantial evidence of a shortage and the need for a massive infusion of funds.

B. Trend Toward Elimination of Vintaging

The practical result of allowing flowing or “old” gas to be sold at the new national rate upon expiration or renegotiation of preexisting contracts is that the former “vintaging” of gas according to its period of discovery will gradually disappear. The Commission is not bound by its previous policies. As this Court and the Supreme Court have noted on various occasions, the rate structures which introduced or adjusted vintaging were experimental. It is necessary without a doubt that agencies be permitted latitude to evaluate old experiments and modify or abandon them when their best judgment requires such a course of action. The Commission’s reasons for permitting old gas to be repriced at the new rate apply equally to the related decision to abandon vintaging.

C. Commission’s Productivity Projections

One of the most important and hard to predict variables in the cost-based formula is productivity, the amount of natural gas that will be added to nonassociated gas reserves for every foot drilled resulting in some addition to those reserves.

The Commission’s decision as to predicted productivity is attacked from both sides. Shell, Amoco and the United Distribution Companies assert that the productivity estimates ignored the only substantial evidence in the record which showed a decreasing trend. American Public Gas Association, on the other hand, contends that the productivity is overstated because the Commission did not use the longest term data available, as had been its practice in previous area rate cases. The parties do not really argue that the ultimate productivity projections are not based on substantial evidence, but rather assert that the Commission’s analysis of that evidence, and the inferences drawn therefrom were incorrect. We find, however, that the Commission’s resolution of this admittedly difficult and uncertain factual issue is supported by the record.

The record in this case presented two special problems for the Commission in using historical figures to predict future productivity in addition to those previously discussed: first, how to treat the historical rates in light of a recent trend of decreasing productivity, and second, what adjustment to make because of a Staff study which suggested that some reported reserve additions were understated in the only available information source, American Gas Association, American Petroleum Institute, and Canadian Petroleum Institute, Reserves of Crude Oil, Natural Gas Liquids, and Natural Gas in the United States and Canada and United States Productive Capacity as of December 31, 1972, Vol. 27 (1973).

Because lower productivity means that the cost of drilling must be spread over less natural gas, resulting in a higher price per Mcf, the producers urged the Commission to accept the trend as valid and to predict an even lower productivity for the future. In addition the producers pointed out that in this time of shortage more marginal reserves, i. e., those with lower productivity, need to be developed, and this will only occur if the productivity allowance in the national rate justifies such a development. On the other hand, the Associated Gas Distributors urged the Commission to use only the data for 1952 — 1967, and to ignore the decreasing productivity trend from 1968 as being based on unreliable reserve data.

Faced with these conflicting positions, the Commission made a choice of what evidence to use in predicting productivity over the effective period of its rate order. The FPC adopted a middle ground computing the productivity for the “high” end of its range of reasonable rates from the most recent seven years (1966-1972) and computing the “low” end from the most recent ten years (1963 — 1972), making adjustment to the final rate range for the Staff-found understatement of nonassociated reserves. This choice of evidence is itself subject to review by this Court for evidentiary support. Southern Louisiana Area Rate Cases, supra at 425 n. 42.

The Commission recognized that the trend of decreasing productivity resulted from the interaction of two factors: drilling footages had dramatically increased in recent years as producers redoubled the search for nonassociated natural gas in the face of the national shortage, but reserve additions had steadily declined. There is no dispute over the existence of substantial evidence of the facts which demonstrate these two factors. The Commission analyzed these trends to project the likelihood of their continuance.

The FPC reasoned that the steady decline in reserve additions data was adjusted downward for significant net negative revisions to existing nonassociated gas reserves, as estimates for older reservoirs were updated to reflect continuing production experience. There is no way that the reservoir which is negatively adjusted can be isolated by year of discovery so that productivity for that year could be properly adjusted. Instead the productivity for the year in which the discrepancy is discovered is affected. The second factor which the Commission considered important in correctly understanding the reserve addition data was the low level of new field and new reservoir discoveries. The FPC believed this to be abnormally low and a result of decreased leasing in the offshore federal domain in the late 1960’s. It anticipated an increase in such discoveries would result from an increase in such leasing.

The Commission acknowledged that it was impossible to isolate the age of the reservoirs which accounted for the negative revisions, but expressed its belief, based on the fact that the revisions were obtained from “continuing production experience,” that at least a substantial portion of the large negative revisions related to older reservoirs. The FPC considered such revisions nonrecurring. Considering all of these facts ■ and the inferences it drew from them, the Commission concluded that nonassociated gas reserve additions had been abnormally low in the recent past and anticipated an increase in the near future.

The Commission recognized that drilling footages had increased and could be anticipated to continue increasing as the search for natural gas broadened. In fact, one of the primary goals of the FPC in formulating the national rate in this case was to stimulate exploration and development of new reserves. The Commission concluded, however, that the negative effect on productivity of this increased drilling was likely to be offset by the increased reserve additions it anticipated as developing. Because of this interaction, the Commission considered the productivity trend as unrepresentative of projected productivity and chose instead to rely on averages of past data to compensate for the inaccuracy of the reserve reporting system and for the instability of short range trends as demonstrated by various historical abrupt changes. Using 1966 — 1972 data, the Commission made a “high” estimate of 485 Mcf per foot, and using the 1963— 1972 data, the Commission made a “low” estimate of 559 Mcf per foot. Productivity for 1972 had been 286 Mcf per foot. The Commission apparently gave consideration to all factors involved in the productivity determination and arrived at an accommodation of the competing theories. That accommodation, although not the only one which could be made, is sufficiently supported by the record to withstand judicial review.

D. Move to Discounted Cash Flow Model in 699-H

The FPC’s choice of the Discounted Cash Flow (DCF) methodology in Opinion 699 — H is the subject of attack from all quarters. This accounting process focuses on cash flow over a set period of time rather than on net income in any one year. The underlying principle is that money has a time value. An amount received a year from now, for example, is worth less than an equal amount currently in hand. This is the principle upon which bonds bearing below-market rates of interest are discounted. Similarly, an expenditure made in year 1 is more costly than an equal expenditure made in year 2.

Discounted Cash Flow accounting focuses on two factors: net cash outflow and net cash inflow. In the FPC model all calculations are made by reference to the first year of production. Net investments (cash outflow) made during the four years prior to production of natural gas are increased at a 15 percent compounded annual rate to give a value as of the first year of production. This 15 percent annual rate reflects the permissible rate of return allowed by the FPC.

In the second stage of the model, the FPC projects future net cash inflows (future gross revenues less annual expenses) for each year of gas production. The model apparently assumes that operations will terminate after 17 years of gas production. These yearly amounts are discounted by a 15 percent annual rate, again a reflection of allowable return on investment. (Future net cash inflows are the equivalent of installment payments on indebtedness. If such payments are discounted by a specific percentage, that discount represents the interest which the lender receives as a return on his investment).

The final calculation of the FPC model is to simply say that future cash inflows, discounted at a 15 percent rate to allow a 15 percent return, must equal previous cash outflow in the form of start-up costs.

The producers attack the injustice of this model in the context of its inclusion of federal income tax credits and exclusion of tax liabilities in excess of those credits. In addition these petitioners variously challenge the time lag and future cash flow assumptions and the failure to provide for cost increases. One consumer group, the American Public Gas Association, questions assumptions about the rate of production and depletion, and use of trended drilling costs. The most serious challenge which the consumer groups bring is their assertion that this new methodology was adopted in midstream, without a sufficient evidentiary foundation, and that the adoption of DCF resulted in an unreasonable increase in the rate for natural gas from 42$ per Mcf to 50$. Without delving into the complexities of an esoteric costing methodology which counsel could scarcely describe in their briefs or at oral argument, we need only note that a reviewing court would go far afield in striking down an analytical model adopted by the Commission. As the Supreme Court long ago observed,

Under the statutory standard of “just and reasonable” it is the result reached not the method employed which is controlling [citations omitted]. 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.

FPC v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 287, 88 L.Ed. 333 (1944). To attack the Discounted Cash Flow methodology, petitioners must therefore demonstrate that it results in an unjust and unreasonable end result. Petitioners failed to sustain this weighty burden of proof, either specifically with respect to the DCF methodology, or with respect to the FPC’s rate structure in general.

E. Federal Income Tax Issue

The producers strongly urge that the Commission committed reversible error when it excluded a federal income tax component from the national rate for natural gas. Rather than calculate an average rate of tax which would be uniformly factored into the cost for natural gas, the FPC instead set a rate exclusive of federal income tax and announced that when producers can demonstrate during an extraordinary relief proceeding that their natural gas operations resulted in actual income tax liability, higher rates will be permitted to reflect that tax.

One argument made against the Commission’s refusal to augment the national rate by an average tax figure is that the Commission thereby acted inconsistently because it paradoxically reduced the rate by an average tax credit figure. There is no support in the statute or in precedent for the assertion that the Commission’s treatment of federal taxes as a whole renders the area ratemaking concept deficient, illogical, or unfair.

A second argument is made against the Discounted Cash Flow model’s treatment of income tax. The model reduces recoverable start-up costs by the amount of tax credits generated by such costs and factors in automatic recovery of income taxes during the period of production only to the extent that tax liability offsets previous tax credits. Thus the model assumes that income tax liability will not exceed income tax credits. It does not allow a return on initial investment which is sheltered by tax credits. Where tax liability exceeds credits,. producers must petition for special relief. The producers’ assertion that the FPC is taking a “double dip” against producer costs is not well taken. While average federal tax deductions are included to reduce start-up costs, an equal amount of tax liability is added to increase the cash flow which is later generated by gas rates during production, and individual tax liability in excess of this amount is recoverable at the time when such liability accrues through the special relief process. There is nothing so unjust or unreasonable about this treatment of tax costs as to require judicial intervention.

The Commission’s policy choice of excluding an average tax liability figure in excess of tax credits was based on findings of fact, lending weight to our conclusion that the net effect of the DCF treatment of federal income tax is not unjust or unfair. Evidence demonstrated that the tax liability of producers varied widely, thus making an average extremely imprecise. The Commission also took note of the complexity of federal income tax provisions for gas producers, the ability of producers in some circumstances to indefinitely postpone tax liability, and the impending reduction of depletion allowances, all good reasons for eschewing a simple tax component which would be cemented into ratemaking for a long time to come. There appears to be no danger that a producer who actually pays taxes will not be able to recover that cost.

Producers also contend that the treatment of tax credits in the DCF model cheats them of a return on investment which is offset by tax deductions. By this argument producers ask us to substitute an alternative investment base for the one which the Commission selected. That would amount to the imposition of our discretionary choice upon an expert agency, which is not permitted.

F. Rate of Return

The selection of a rate of return is overtly a factual determination and has been treated as such during the course of this litigation, but the Commission made an implicit policy choice which controls the nature of the relevant factual issues at hand. The Commission could probably have sought a rate of return which merely avoided charges of confiscation. But the FPC did more, seeking as it did a rate of return which at a minimum is competitive with other industries, and moreover encourages exploration. One petitioner, United Distribution Companies, challenged the 15 percent rate of return as being inadequate for these purposes, and asserts that the factual data supporting the decision to fix a 15 percent rate of return was not considered during the agency proceeding.

The Commission is to be upheld regardless of whether one views the rate of return as a factual determination which is subject to the substantial evidence standard of review, or as a parameter of the DCF model which is entitled to the less severe standard for reviewing a discretionary selection of policy and methodology. The record reveals that the Commission carefully evaluated average rates of return on capital invested in other industries and concluded that a zone of reasonableness spanned from 12 percent to 15 percent. The selection of the highest rate of return within the zone was based on the desire to provide the extra incentive which the Commission felt is needed to encourage increased exploration and development. We find no ground for either reversing the policy of setting a rate which attracts capital into natural gas production, or setting aside the factual base 'that supports the choice of a 15 percent rate of return.

G. Lease Acquisition Costs

Shell Oil and allied producers allege that the new national rate for natural gas understates Lease Acquisition Costs by approximately 25$ per Mcf. They recite factual data which indicates a dramatic increase in bonuses paid by producers to the federal government in recent years for Outer Continental Shelf gas leases. Their evidence includes scattered federal lease information pertaining to acquisition costs from 1972 through 1974, and actual successful well cost data for 1973. The 1973 total, $2 billion dollars, was not available until February of 1975, three months after the issuance of Opinion 699 — H. By contrast, the Commission based its lease acquisition cost estimates on six-year (1967-1972) cost averages and five-year (1968— 1972) “Trended Data.”

The Commission’s projections are based on substantial evidence and cannot be reversed at this stage. Their evaluation is necessarily constrained by the time lag in compiling data of this kind. The recent developments to which Shell and others point is not so compelling as to require that 18 year projections be based on extraordinary recent developments: While the Commission is surely obligated to monitor these developments so that future adjustments provide for just and reasonable recoupment of lease acquisition costs, the Commission exercised proper discretion in basing its determination on long range rather than extraordinary and incomplete recent data.

H. Net Liquid Credit

Net Liquid Credit is a cost equation component of relatively little import. Gas producers are able to capture a small amount of liquifiable petrocarbons as by-products of natural gas production. These petrocarbons are sold at a profit and are factored in as a credit which helps offset costs that are allocated through the rate charged to consumers of natural gas (the present credit amounts to 3.89$ per Mcf). In setting the amount of the credit the Commission took notice of the fact that prices paid for this petroleum condensate are increasing, causing the credit to be understated. There is also evidence, however, that the amount of condensate produced is declining. The Commission in its opinion indicates that it is continuing the evaluation of these trends. While there is some merit in the charge that the evidence supporting the level set by the Commission is thin, it is not so insubstantial to warrant reversal of the Commission’s evaluation of and response to these trends, especially in light of the implied promise to adjust the credit as further facts unfold. Certainly the magnitude of the issue is not sufficient to render the FPC order unjust and unreasonable.

I. Refund, Work-off and Contingent Escalation Provisions

Under previous area rate agreements the FPC determined that certain producers were obligated to refund overcharges to pipelines. The producers were allowed, however, to “work-off” the obligation by receiving a 1$ credit for each Mcf of new gas dedicated to interstate commerce in the affected area, as long as half of such gas is sold to the pipeline which was previously overcharged. See, e. g., Permian Basin Area Rate Proceedings, 50 F.P.C. 390 (1973); Texas Gulf Coast Area Rate Proceeding, 45 F.P.C. 674 (1971). In addition, the Commission provided for rate escalations contingent on the dedication of additional flowing gas to the interstate market by a given date. In Opinion Nos. 699 and 699 — H the FPC provided that natural gas sold at the new national rate could not be used to discharge refund obligations or to trigger contingent escalations. Producers argue before this Court that this constitutes an improper retroactive modification of prior rate opinions. We disagree. By its orders which are here at issue, the FPC has established a new rate system for gas dedicated to interstate commerce after January 1, 1973, in addition to gas from certain other sources. The new national rate is the product of an independent determination of incentives, and, as it is in so many-other regards, the new rate structure is not tied to previous determinations. 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).

J. Limited Term and Emergency Sales Procedures

In Opinion No. 699 the Commission modified its previous limited term and emergency sales procedures. Cf. 18 C.F.R. §§ 2.70, 157.29 (1974). The Commission provided that sales from the offshore federal domain made under both the limited term and the emergency sales procedures should not exceed the new national rate, and it limited the term of such sales to a single 60-day sale from a particular well or group of wells. The FPC reasoned that “the present gas shortage requires long-term solutions, not stop gap measu-res.” It based its decision to limit these short-term procedures on substantial evidence showing that an inordinate amount of new deliveries to the interstate market for 1971 to 1973 are traceable to emergency and limited-term sales.

The FPC action is attacked on a number of fronts. The producers group contends that limited term and emergency sales should be allowed to exceed the national rate. A number of pipeline companies argued that the Commission erred in restricting sales from a well or a group of wells to a single 60-day period, and they assert that the Commission failed to establish sufficiently clear guidelines for the pipelines’ recovery of their costs for emergency purchases.

As to the latter issue, the Commission has in fact stated the standard for acceptable cost recovery:

If a pipeline seeks to purchase gas in interstate commerce for only a short period of time at a price in excess of the national rate, there must be credible evidence demonstrating that the gas is to be purchased at the lowest price for which the pipeline could have obtained the gas, and that such gas supply is not available for a long-term dedication at the present national rate.

Opinion No. 699 — F. This standard is expanded by the statement in Opinion No. 699 — B that pipelines should “be entitled to pay a rate for emergency purchases which a reasonably prudent pipeline purchaser would pay for gas under the same or similar circumstances.”

We have approved the Commission’s objective of achieving a monolithic national rate for natural gas. Its limitation of short-term emergency sales to 60 days, and its restriction of the price at which jurisdictional sales may be transacted are acceptable means to that end. By its action the FPC has protected the integrity of the new national rate and has promoted long-term relationships between producers and pipelines. Its decision to restrain allowable short-term transactions was based on substantial evidence that an abundance of these transactions adversely affects long-term national ratemaking, and is therefore not reversible.

K. Other Noncost Considerations

Various petitioners argue that the Commission erred in failing to consider noncost factors which are created by market forces. Specifically, the producers base their argument for higher rates on a comparison between the FPC’s new rate for natural gas and higher price of both oil and natural gas in the unregulated intrastate market. They argue that the national rate for regulated gas should equal the “commodity value” of gas determined by comparison with substitutable fuels such as oil. In essence, these petitioners would have us set the price of natural gas at the rate that the market would bear. The commodity price of gas would most likely be set by the prevailing price of oil and the cross-elasticity of demand between gas and oil. To accept this free market “commodity value” would be to eschew the congressionally mandated responsibility of rate regulation which is devised to reach a “just and reasonable” rate. Fixing a “just and reasonable” rate for a product sold in an inherently uncompetitive market requires more than mere subservience to national and international market forces. Just as the Natural Gas Act does not limit the Commission’s determination to cost-related ratemaking, neither is the Commission obliged to incorporate specific noncost factors into its calculus.

As another way of phrasing their argument that the “commodity value” of natural gas should determine the national rate, a number of producers argue that the FPC was erroneous in its use of cost-based ratemaking. But the Supreme Court has recently concluded upon a search for congressional intent that “the Commission lacks the authority to place exclusive reliance on market prices,” FPC v. Texaco, Inc., 417 U.S. 380, 400, 94 S.Ct. 2315, 2327, 41 L.Ed.2d 141 (1973). The Commission’s long and often judicially approved practice of basing rates on cost carries a substantial presumption of validity which places a heavy burden on those who would refute it. As noted above, the overall rate structure must be challenged on the basis of improper net effect. FPC v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 88 L.Ed. 333 (1944). The cost-based national rate on review before us is experimental. It represents a dramatic increase in the allowable price for interstate gas. It is premature to decide, as the producers would have us decide, that this experimental price increase— the effect of which cannot yet be measured — is not enough.

The statutory standard for review of FPC policy requires an examination of the end result of a rate structure. Petitioners have not met their burden of demonstrating that the natural gas rate must reflect noncost, market conditions in order to be just and reasonable, i. e., they have not shown that the FPC policy of basing the natural gas rate on cost rather than on market forces produces an end result which is harmful to the public interest.

CONCLUSION

Having carefully reviewed all of the various arguments against the validity of the Commission orders under review, we are constrained to uphold the Commission’s action. 
      
      . Under review here are a series of orders of the Federal Power Commission issued in The National Rate Proceeding, Docket No. R-389B; Opinion No. 699 issued on June 21, 1974; Opinion No. 699-A, issued on August 2, 1974; Opinion No. 699-B, issued on September 9, 1974; Opinion No. 699-F, issued on November 7, 1974; Opinion No. 699-H, issued on December 4, 1974; and, Opinion No. 699-1, issued January 7, 1975.
      The substantive issues in this proceeding have not previously been before this Court. However, on February 20, 1975, the Court issued an opinion and order determining that it had jurisdiction to review these orders and consolidating the various review petitions under the title National Rate Cases For New Gas under Docket No. 74-3330, Shell Oil Co. v. FPC, 509 F.2d 176 (5th Cir. 1975).
     
      
      . See, e. g., Mobil Oil Corp. v. FPC, 417 U.S. 283, 300-310, 94 S.Ct. 2328, 41 L.Ed.2d 72 (1974); Permian Basin Area Rate Cases, 390 U.S. 747, 755-766, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968) [Permian]; Southern Louisiana Area Rate Cases, 428 F.2d 407, 415-421 (5th Cir.), on reh., 444 F.2d 125 (5th Cir.), cert. denied, 400 U.S. 950, 91 S.Ct. 243, 27 L.Ed.2d 257 (1970).
     
      
      . See Permian, 390 U.S. at 757 n. 12, 88 S.Ct. 1344.
     
      
      . The existence of these geographical areas ' was noted by the Supreme Court, in a footnote in its most recent area rate review, Mobil Oil Corp. v. FPC, 417 U.S. 283, 289-290 n. 3, 94 S.Ct. 2328, 41 L.Ed.2d 72 (1974), which footnote when updated shows the status of the rate proceedings for the various areas as follows:
      1. Permian Basin Area
      
      Opinion Nos. 468 and 468-A, 34 FPC 159 and 1068, respectively (1965), aff’d, Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968).
      New rates for this area were established in: Opinion Nos. 662 and 662-A, 50 FPC 390 (1973) (petition for review withdrawn).
      2. Southern Louisiana Area
      
      Opinion Nos. 546 and 546-A, 40 FPC 530 and 41 FPC 301, respectively (1968), aff’d, Southern Louisiana Area Rate Cases, 428 F.2d 407 (5th Cir.), on reh., 444 F.2d 125 (5th Cir.), cert. denied, 400 U.S. 950, 91 S.Ct. 243, 27 L.Ed.2d 257 (1970).
      New rates for this area were established in:
      Opinion Nos. 598 and 598—A, 46 FPC 86 and 633, respectively (1971), aff'd, 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).
      3. Texas Gulf Coast Area
      
      Opinion Nos. 595 and 595-A, 45 FPC 674 and 46 FPC 827, respectively (1971), rev’d and remanded, Public Service Commission v. FPC, 159 U.S.App.D.C. 172, 487 F.2d 1043 (1973), vacated and remanded sub nom., Shell Oil Co. v. Public Service Commission, 417 U.S. 964, 94 S.Ct. 3166, 41 L.Ed.2d 1136 (1974).
      4. Hugoton-Anadarko Area
      
      Opinion No. 586, 44 FPC 761 (1970), aff’d, Hugoton-Anadarko Area Rate Case, 466 F.2d 974 (9th Cir. 1972).
      5. Other Southwest Area
      
      Opinion Nos. 607 and 607-A, 46 FPC 900 and 47 FPC 99, respectively (1971), aff’d, Other Southwest Area Rate Case (OSWAI), 484 F.2d 469 (5th Cir. 1973), cert. denied, 417 U.S. 973, 94 S.Ct. 3180, 41 L.Ed.2d 1144 (1974).
      6. Appalachian and Illinois Basin
      
      Order Nos. 411, 411-A and 411-B, 44 FPC 1112, 1334 and 1487, respectively (1970) (no appeal).
      The Commission declined to establish new area rates for this area in Opinion No. 639, 48 FPC 1299 (1972), aff’d, Shell Oil Co. v. FPC, 491 F.2d 82 (5th Cir. 1974).
      7. Rocky Mountain Area
      
      Opinion Nos. 658 and 658-A, 49 FPC 924 and-FPC-, respectively (1973) (petition for review withdrawn).
     
      
      . See footnote 4 supra.
      
     