Shell Oil Co. v. Federal Power Commission (520 F.2d 1061, 1975)

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 (