Southern Louisiana Area Rate Cases, Austral Oil Co. v. Fed. Power Comm'n, 428 F.2d 407 (5th Cir. 1970)

In discussing the issues in this case, we have usually simplified the positions of the parties by considering them as producers, consumers, and the Commission. Our review of the case, however, has taken into account subtler differences among the parties. Most of the producers, for example, have joined a single group, the Amerada group, in briefing their argument, but others have chosen to present their arguments separately. Particularly conspicuous among these separate petitioners are several small producers, and we have treated their special arguments herein. The method of presentation is a question for the parties themselves. We think, however, after considering this case, that it is to the great advantage of the parties in a complex, multi-party case to aggregate their arguments in so far as possible.

The pipelines purchase gas from the producers, and it seems anomalous at the outset that they are arguing that prices are too low. The Commission found that the inelasticity of market demand for gas at the consumer level “tends to make price a second level consideration” to pipelines. 4 Joint Appendix, pt. 1, at 533d (Commission’s opinion). Pipelines sometimes own production factors as well. A significant reason for the pipelines’ alignment here, however, may be simply that they are concerned that the price level will not elicit sufficient supply for their needs. At oral argument, they represented that informal rationing procedures among pipeline purchasers were now in effect and that formal agreements might be necessary in the future.

These parties include the New York Public Service Commission and the Municipal Distributors Group, a group of municipally owned gas distribution systems.

It is supported in this position by the Associated Distributors Group (ADG) of intervenors, a group of privately owned local utility companies.

15 U.S.C. § 717 et seq. (1963); 52 Stat. 821 (1938).

347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035.

See F.P.C.Ann.Rep. 176-77 (1955); 36 F.P.C.Ann.Rep. 10 (1956); 37 F.P.C. Ann.Rep. 17-18 (1957); 39 F.P.C.Ann.Rep. 12-13 (1959).

Johnson, Producer Rate Regulation in Natural Gas Certification Proceedings: CATCO in Context, 62 Colum.L.Rev. 773, 783 (1962); see also M. Merrill, The Public’s Concern with the Fuel Minerals 104 (1960).

See, e. g., M. Adelman, The Supply and Price of Natural Gas 39 (1962); P. McAvoy, Price Formation in Natural Gas Fields 265 (1962); E. Neuner, The Natural Gas Industry 280-90 (1960) (recommending that contracting behavior rather than price be regulated, in light of a conclusion that industry structure, at least, is competitive) ; Cram, Intro*416duction to the Problem of Developing Adequate Supplies of Natural Gas, in Economics of the Gas Industry 24 (Southwestern Legal Foundation ed. 1962) ; Kail, The Evolution of Area Gas Pricing and Its Effects on the Natural Gas Industry 18-22, January, 1968 (unpublished thesis in University of Texas Library); Kitch, Regulation of the Field Market for Natural Gas by the Federal Power Commission, 11 J.Law & Econ. 243 (1968) ; of. Kitch, The Permian Basin Area Rate Cases and the Regulatory Determination of Price, 116 U.Pa. L.Rev. 191, 194-99 (1967) (concluding that area rate regulation resembles wartime price control). These and other authorities, however, are relevant only to the quasi-legislative function of the Commission in deciding how producers are to be regulated. The decisions of the Supreme Court definitely indicate that the Commission has a responsibility to take the steps necessary to assure that wellhead prices are in the public interest. The Commission does not have to employ the area rate method, or for that matter regulate price directly at all, but it has chosen to fulfill its duty in that manner here.

The Commission concluded that there was an absence of effective competition in wellhead sales. This absence seems to be strongly evidenced by a rapid spiral of price increases over the years from 1950 to 1958, when the price went from less than 9 cents per Mcf to a peak of 24.05 cents. This spiral was apparently caused by three factors. First, the contracting practice in the industry resulted in oligopolistic behavior, because devices such as favored nation, periodic escalation, re-determination, and renegotiation clauses caused any price above in-line levels to trigger other price rises. (These contract terms are defined in the Supreme Court’s Permian opinion, 390 U.S. at 765, 88 S.Ct. at 1358, n. 46.) Second, the producers were able to assert market power even though the market for sales to large pipelines appears at first glance to be oligopolistic, because the pipelines typically needed large blocks of reserves at times not of their own choosing. Finally, the bargaining motivation of pipelines themselves was diluted because pipelines resold in a relatively inelastic market and hence could pass price increases on to consumers. The Commission chose to believe this evidence rather than to focus on concentration ratios, leadership turnovers, or conditions of entry, and it appears to have been justified in so doing. 4 Joint Appendix at 530d-34d (Commission’s Opinion). At the same time, there seems to be general agreement that the market is at least structurally competitive. The Supreme Court in Permian described producers as “intensively competitive.” 390 U.S. at 757, 88 S.Ct. at 1354. See also P. McAvoy, supra note 9, at 7; E. Neuner, supra note 9, at 178-204, 280-281; M. Adelman, The Supply and Price of Natural Gas 39 (1962).

See J. Landis, Report on Regulatory Agencies to the President-Elect 54 (printed for the use of the Senate Comm, on the Judiciary, 86th Cong., 2d Sess., 1960).

Atlantic Ref’g Co. v. Public Service Commission of State of New York, 1959, 360 U.S. 378, 79 S.Ct. 1246, 3 L.Ed.2d 1312 (known as the CATCO case). The Court urged the Commission to disallow or condition new certifications “where the proposed price is not in keeping with the public interest because it is out of line or might result in a triggering of general price rises or an increase in the applicant’s existing rates ."

These matters were set out in the FPC’s Statement of General Policy No. 61-1, 1960, 24 F.P.C. 818.

Permian Basin Area Rate Proceeding, 1965, 34 F.P.C. 159, affirmed in part and reversed in part sub nom. Skelly Oil Co. v. FPC, 10th Cir. 1967, 375 F.2d 6, affirmed in full, in re Permian Basin Area Rate Cases, 1968, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312.

This date was chosen for three reasons. First, it was the most convenient date following 1960, the year of most data for old gas. Secondly, the in-line and guideline policies had been established in 1960. Thirdly, this date reflected the Commission’s estimate of the time at which the industry acquired the capability to drill “directionally,” i. e., to explore specifically for gas rather than finding gas as a by-product of the search for oil. 34 F.P.C. at 189. This directionality hypothesis is a major basis of area rate regulation as the Commission has implemented it, because multi-price regulation depends upon the function of greater prices to elicit gas exploration. The hypothesis is not without its critics. See Foster Associates Report, December 18, 1969, at 9-10.

The new gas ceiling was 16.5 cents per thousand cubic feet (Mcf) in Texas or 15.5 cents per Mcf in New Mexico, and the old gas ceiling was 14.5 cents per Mcf in Texas or 13.5 cents per Mcf in New Mexico. The difference reflected the fact that the Texas price included state taxes while the New Mexico price did not. Casinghead gas was priced at old gas ceilings irrespective of its vintage. The Commission also set a minimum price of 9 cents per Mcf.

The Commission made no assessment of the effect of its prices on supply, demand, reserves, or industry structure. The Supreme Court advised that in future cases the Commission should state more “fully and carefully * its assessment of the consequences of its orders for the character and future development of the industry.” 390 U.S. at 792, 88 S.Ct. at 1373.

“Offshore” gas production, in this opinion, means production outside state boundanes and thus not subject to state severance taxes, i. e., that in the federal domain.

In 1965, the year the record in this case closed, Bureau of Mines figures attributed 35.7 percent of this nation’s total energy production to natural gas. The percentage has been steadily increasing over the years. For 1968, the producers quote a figure of 37.5 percent. Brief for Amerada Group at Appendix B-2.

The reasons for the establishment of the January 1, 1961 (late were similar to those for its establishment in Permian. See note 15 supra. The October 1, 1968, date marked the approximate end of these proceedings before the Commission.

The Commission ruled that, by further order, it would require refunds of the difference between the amounts collected and amounts that could have been received under the applicable area rate (or the amounts that would have been received under firm certificates or settlement rates if those rates were higher than the area rate).

The Commission relied upon published data, testimony, and questionnaires filled out by producers to collect its raw cost data.

[figure] All figures given are unit costs, in cents per Mcf. The grouping of flowing gas costs is different from that for new gas; the flowing gas E & D computation, for example, contains some allowance for rate of return.

Area rates “will be modified if a showing is made that unit costs — reflecting amounts spent and reserves found — have increased to such an extent that an increase in area rates is required.” As to individual producers, the Commission recognized that it was avoiding “precise specification of circumstances that would justify special relief,” but stated that: These and other statements of the Commission, taken together, probably constitute as specific an exposition of circumstances for relief as can be expected at this stage in area regulation.

The Commission established a system of quality discounts that were to be used in adjusting maximum rates, outlawed certain types of flexible pricing clauses resulting in increases over ceilings, created special exempt types of producer sales, exempted “small” producers from certain requirements, and determined that minimum rates need not be established.

Order Enlarging Investigation and Proposed Rulemaking, 1969, F.P.C. [No. AR69-1; slip opinion dated December 15, 1969, at 3], The Commission indicated that “we desire to have this proceeding expedited in every way possible.” Prehearing was set for January 27, 1970. The Commission had already set part of the offshore territory for reconsideration in its opinion on rehearing. The Order of December 15 enlarged that proceeding to include the entire area.

The maximum rates that the Commission has set, in addition to the moratoria, are to remain in effect throughout the new proceeding, which may last for years. Moreover, it was never contemplated that there should be a single area proceeding setting rates once and for all; rather the Commission has always made it clear that it intended to review the rates it had set whenever the circumstances made it advisable to do so. See note 24 supra.

See section III D infra.

About fourteen percent of gas produced in Southern Louisiana is casinghead, and the Commission states that “we are well aware that its indicated cost is substantially below that of gas-well gas.” The ADG has calculated the difference in cost at about 3 cents. Assuming this figure to be correct (which we cannot really assume because joint costing of oil and gas is judgmental), the inclusion of casinghead gas into the computation of costs for the first vintage would result in a total decrease in first-vintage price from 18.5 cents to approximately 18.3 cents by our calculation, or a difference of just over one percent. Especially in view of the cost-computation structure as a whole, which has frequently involved the Commission in the approximations of interpreting joint costs, we consider this amount de minimis, even conceding its accuracy. But our rejection of this argument is based upon more fundamental considerations. The assignment of costs to products jointly produced, as are oil and casinghead gas, is not an exact undertaking, and we think the Commission has acted on the basis of substantial evidence, particularly since it has set a rate structure under which casinghead gas of all vintages is assigned the lowest price, that of first vintage. The Supreme Court approved a similar calculation in Permian. Cf. ICC, Bureau of Accounts, Statement No. A-54, Explanation of Rail Cost Finding Procedures and Principles Relating to the Use of Costs, Ch. 1, pt. 4 (1954).

It seems clear that oil, which is more valuable than a volume of gas of the same heat content, should bear more of the exploration and development cost. The Commission, as its first step in assigning these costs, determined a unit by which gas and oil could be compared: the amount of each that is required to produce a Btu of heat. It then determined what it called the “economic factor,” which is the number of gas units that equaled in value a unit of oil. By strict computation, the Commission arrived at an economic factor of 4.0. This factor would have indicated the assignment of four times as much of the cost to oil as to gas. It then adjusted this factor to 3.5, however, to allow for the fact that revenues from flowing gas should be expensed against present drilling, which is undergoing a continuing shift away from searches directed solely at discovering oil toward searches directed at finding gas. We think it is reasonable for current revenues from flowing gas to be compared with current expenses in exploration for new gas. Thus the Commission adopted an allocation that assigned higher costs to exploration for gas than would its straight calculation, but it justified this modification by a qualitative finding that is based upon substantial evidence.

The consumer interests argue that these plant gathering costs should rather be assigned to those salable liquids, since they are incurred in producing them. On rehearing, the Commission indicated that the allowance might have been overstated slightly, but that “ * the entire allowance is only 0.33 cents. The amount of possible excesses does not seem worth the burden of further hearings on other allocation methods.” The Commission indicated that a significant portion of the 0.33 cents is chargeable against gas because part of the liquid revenues do not go to the producers at all but rather are *423paid to the leasehold, reducing its cost. Another significant part is also chargeable to gas, because transportation to a plant is usually done in furtherance not only of liquid extraction but also of moving the gas stream itself closer to the centralized point at which it must be delivered. Therefore, we agree with the Commission that possible excesses in the 0.33 cent figui-e, which is itself less than 2 percent of the total price, would be de minimis, and we hold that the plant gathering allowance is based upon substantial evidence.

They argue that the credit of 3.5 cents for lease-extracted liquids and that of 0.50 cents for plant-extracted liquids is too low. The Commission calculated the lease liquid credit at 4.18 cents, but it reduced this figure to allow for a trend of decreasing revenues from these liquids. It reduced the plant liquids credit from a calculated 0.75 cent to 0.50 cent to allow for a duplication of credits elsewhere. These actions are supported by substantial evidence.

A generous reduction for all four cost criticisms considered here, if all of them were accepted, would certainly not exceed 1.5 cents. Commissioner Carver, on the other hand, indicates reasonable changes that could result in an increase of 4.0 cents, if all were adopted, in his dissent to the opinion on rehearing. See note 85 infra. The inherent, unavoidably approximate nature of rate regulation under legislative standards has been noted by both economists and courts, including the Supreme Court in Permian, 390 U.S. at 790, 88 S.Ct. at 1372 n. 59; see also J. Bonbright, Principles of Public Utility Rates 27, 67 (1960). Of course, the inaccuracy of pricing techniques is one reason why the FPC is required separately to determine the consequences of its pricing actions. See section III(D) infra.

Provided it meets other requirements of law, the Commission may employ any “formula or combination of formulas” it finds appropriate. It may “make the pragmatic adjustments which may be called for by particular circumstances.” FPC v. Natural Gas Pipeline Co., 1942, 315 U.S. 575, 586, 62 S.Ct. 736, 743, 86 L.Ed. 1037; see also Permian, 390 U.S. at 800, 88 S.Ct. at 1377.

We recognize possible validity in the consumers’ argument that Commission reliance on such matters as hurricanes in fixing a 12 percent rate of return for Southern Louisiana is misplaced. It might have been more appropriate to treat these matters as above-the-line costs (reflected, for example, in insurance premiums) rather than as a risk upon which one obtains return. Permian, however, indicates that arguments of this type should be addressed to the discretion of the Commission. 390 U.S. at 811, 88 S. Ct. at 1383. Furthermore, we do not need to rely heavily upon these factors, because the Commission has advanced other justifications for the rate of return.

See 3 Joint Appendix, pt. 1, at 239d (Initial Decision). The Commission relied heavily upon the examiner’s findings in fixing the rate of return.

See G. Stigler, Capital and Rates of Return in Manufacturing Industries 90-91 (1963); of. J. Galbraith, The New Industrial State (1967).

We note at the outset that the Commission is not required to compute rate of return on the basis of the comparable earnings test. The Permian decision states that “other standards might properly have been employed.” (The Court cites with apparent approval the examiner’s discussion of rate of return in this very case, the Southern Louisiana proceeding). 390 U.S. at 805, 88 S.Ct. at 1380 & n. 1; see also J. Bonbright, supra, note 33, at 240-283. However, we review the Commission’s decision under the comparable earnings test because that is the standard it evidently followed. The test has been formulated as follows : Return should be “equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties.” Bluefield Water Works & Improvement Co. v. Public Service Commission, 1923, 262 U.S. 679, 692, 43 S.Ct. 675, 679, 67 L.Ed. 1176; FPC v. Hope Natural Gas Co., 320 U.S. at 603, 64 S.Ct. at 288.

The Amerada group of producers argued for a 16-18 percent rate of return. The FPC Staff recommended 9.5 percent and asserted that 12 percent “can well be considered as in excess of the upper limit of the range of reasonableness.” See 3 Joint Appendix, pt. 1, at 164d, 173d, 185d, n. 1, (Initial Decision).

See 4 Joint Appendix, pt. 1, at 567d-74d (Commission’s Opinion).

“[W]e recognize that the limited available data on non-intograted companies refers to a few unusually successful producers. Also, earnings-book ratios of integrated companies deserve to be given some weight.” Id. at 573d.

The comparable earnings standard is a general one, encompassing several indicia of earnings and requiring both ability to attract capital and a fair return on equity. Williams v. Washington Metropolitan Area Transit Comm., 1968, 134 U.S.App.D.C. 342, 415 F.2d 922, 933. Certain types of computation are unacceptable, see Id. at 970 & n. 294, but the Commission has broad power to select the evidence upon which it should rely. We find that the Commission was obviously attempting to apply the comparable earnings test. The sole questions it struggled with were what companies’ risks were comparable and what the earnings of those companies were. Its choice of evidence is reviewable under the substantial evidence standard.

We are singularly unimpressed with the characterization of this offshore factor as a “phantom tax” by both the MDG and the New York Commission. These parties begin by stating that the computed cost difference between offshore and onshore is 2.3 cents (the amount of the Louisiana severance tax), go on to show that the Commission’s ceiling for offshore is only 1.5 cents lower, and from this conclude that the Commission has allowed 0.8 cent for “phantom” taxes inapplicable to offshore, which is outside Louisiana’s taxing jurisdiction. The conclusion is the baldest of sophistry, for the 0.8 cent allowance has nothing to do with the Louisiana tax. It is a noncost element intentionally added by the Commission, and we consider it as such. It is only fair to add, however, that this sophistry was made possible, if not plausible, by the Commission’s failure to label noncost factors specifically and to justify them in a way clearly independent of costs. It is also a product of conflicting implications in the Commission’s findings. See sections IV A(l), (4) infra. The raising of phantom issues such as this one wastefully consumes the efforts of a reviewing court.

The main thrust of the MDG argument is that the Commission failed to include adequate justification for the noncost factors in its opinion, an argument with which we would be inclined to agree were it not for the newness of area regulation. See Colorado-Wyoming Gas Co. v. FPC, 1945, 324 U.S. 626, 65 S.Ct. 850, 89 L.Ed. 1235; United States v. Carolina Freight Carriers Corp., 1940, 315 U.S. 475, 62 S.Ct. 722, 86 L.Ed. 971. This is a procedural issue crucial to appellate review. See notes 110-11 infra and accompanying text.

All other issues remanded to the Transit Commission were so treated because of a lack of required findings, but the court disapproved completely the cushion in the rate of return. The Transit Commission had included the amount because of the possibility that its “conservative” cost and revenue findings might be inaccurate. *426It expressed a preference for adding a cushion above costs to cover this possibility rather than allowing for it in its cost findings because adjustment in cost findings would be compounded by the addition of return. The court did not dispute this proposition, which indeed is indisputable, but stated that “ [notwithstanding the uncertainty that attends all prophesy, a regulatory agency is duty bound to make its forecasts as accurate as it possibly can, and a reviewing court is entitled to assume that it has done so.”

The gas industry is different from metropolitan transit in that it requires a constant infusion of entrepreneurship of the highest order if even basic public needs are to be satisfied. The D.C. Transit System will continue to operate even if the return its investors expect in a given year is poor, because it is a true public utility subject to the orders of the Transit Commission. Its service may not be of the best quality if rates are too low, or, more importantly, its owners may have a Constitutional claim against the Government, but the public will not be irreparably injured. On the other hand, we count upon persons who carefully weigh investment risks for our supply of natural gas. We think the Commission here, having calculated the dangers involved in allowing the gas supply to lapse, and the probabilities that its estimates might be too low, is justified in having added the small noncost factors it thought were necessary. It found that it needed to do so to protect the public interest and not to assure any rights of gas producers. However, as the Williams case indicates, the use of noncost factors to allow for possible inaccuracies is not favored. Inaccuracy, if that is really the concern (and not higher costs), can result in a windfall to producers as easily as in a loss. See note 47 infra. We approve the use of noncost factors for this purpose under the facts of this case only.

Williams is distinguishable from our case in several respects; it is so clearly so, in fact, that we feel justified in concluding that it is based not on disapproval of noncost increments but upon disapproval of egregiously inattentive regulation. The cushion had been added ostensibly to allow for inaccuracies in cost computations, but the court found that as the computations had been made any inaccuracies would lie on the side of generosity to the Transit Company. Moreover, in earlier years regulation by the Transit Commission had allowed, in reality, a return of equity of 21 percent for the Company, as versus a “comparable earnings” return computed at 7.5-8.7 percent. The Transit Commission had made no findings as to comparable earnings. 415 F.2d at 936-937, 973-974.

390 U.S. at 815, 88 S.Ct. at 1385 & nn. 97-99.

This argument is widely accepted; indeed, it was cited with approval in Permian. See Id. at n. 99 and authorities therein cited.

These considerations are in apparent conflict with the Commission’s finding that “it has not been demonstrated that the unit cost of gas is greater offshore than onshore.” *4 Joint Appendix, pt. 1, at 622d. The Commission could have reconciled this conflict by indicating, for example, that it had some* reason for thinking costs might be higher, or that the newness of the undertaking and the consequent unavailability of cost data was itself a risk justifying a higher return.

This finding should have been discussed in light of the Commission’s finding that costs were unlikely to rise. Evidently the Commission recognized some probability that costs would rise slightly, and the amount of the cushion is tied to this probability — but the Commission has not exposed its reasoning.

Cf. 390 U.S. at 815, 88 S.Ct. 1385 n. 98.

The Supreme Court affirmed in Permian, however, while being forced to read the Commission’s mind even more than we are. The Commission there had said that “no [noncost] adjustments are required in the Permián Basin.” 34 F.P.C. at 207. But the Supreme Court found that the Commission had actually used four separate types of noncost factors and had justified each. 390 U.S. at 815, 88 S.Ct. at 1385 n. 98.

Noncost factors will often in the ultimate analysis relate to these market variables, although there are other possible justifications for them. Where noncost elements are used to relate supply and demand, the level of each and the relationship between them must be explored. Here, adequate supply, even though the Commission has not examined it, is obviously a major consideration lurking behind the noncost additions, expressed in the Commission’s frequent allusions to the “importance” of the Southern Louisiana area. A finding as to “importance,” without any identification of or discussion of the specific characteristic of the region that is important, is of little benefit to a reviewing court.

See note 46 supra; cf. note 47 supra.

390 U.S. at 782, 88 S.Ct. at 1367 (emphasis added).

No constitutional objection arises from the imposition of maximum prices merely because “high cost operators may be more seriously affected than others,” Bowles v. Willingham, supra, 321 U.S. 503, at 518, 64 S.Ct. 641 at 649, 88 L.Ed. 892, or because the value of regulated property is reduced as a consequence of regulation. FPC v. Hope Natural Gas Co., supra, 320 U.S. at 601, 64 S.Ct. at 281; Permian, 390 U.S. at 769, 88 S.Ct. at 1361. See also* West Coast Hotel Co. v. Parrish, 1937, 300 U.S. 379, 57 S.Ct. 578, 81 L.Ed. 703; Nebbia v. New York, 1934, 291 U.S. 502, 54 S.Ct. 505, 78 L.Ed. 940; Munn v. Illinois, 1877, 94 U.S. 113, 24 L.Ed. 77.

5 U.S.C. § 550 et seq. (1967).

The argument is based upon the following two contentions: first, that sections 7 and 8 of the APA, read in conjunction with section 4 of the Natural Gas Act, require rate orders to be made upon formal hearing and not upon the “informal” procedures established here, and second, that the issuance of the moratorium order was not preceded by the public notice required by section 4(b) and other sections of the APA. The answer to the first argument is that the instant proceeding is the rate order required to comply with sections 7 and 8; we do not think these sections apply to the decision whether to grant individual relief after the just and reasonable rates have been set. This is the clear import of the *429 Permian approval of group regulation. See 390 U.S. at 744, 88 S.Ct. at 1364, distinguishing Bowles v. Willingham, supra. The second argument likewise has no merit. The Commission published notice regarding the commencement of area proceedings, and the notice in our view was sufficient to inform all parties that ancillary regulations would be considered. 26 Fed.Reg. 4296 (1960).

15 U.S.C. § 717c (1963).

The Court in Permian also approved Commission orders of indefinite duration prohibiting increases above maximum rates brought about by flexible pricing clauses. 390 U.S. at 782-783, 88 S.Ct. at 1368-1369. See also Atlantic Ref’g Co. v. Public Service Commission, 1959, 360 U.S. 378, 79 S.Ct. 1246, 3 L.Ed.2d 1312 (approving prospective ceilings on price in section 7 proceedings); cf. United Gas Improvement Co. v. Callery Properties, Inc., 1965, 382 U.S. 223, 86 S.Ct. 360, 15 L.Ed.2d 284.

15 U.S.C. §717d (1963). Moreover, section 16 of the Act, 15 U.S.C. § 717o (1963), gives the Commission power “to perform any and all acts, and to prescribe, issue, make, amend, and rescind such orders, rules, and regulations as it may find necessary or appropriate to carry out the provisions of this chapter.”

United Gas Improvement Co. v. Callery Properties, Inc., 1965, 382 U.S. 223, 232, 86 S.Ct. 360, 365, 15 L.Ed.2d 284 (separate opinion of Mr. Justice Harlan).

United Gas Pipeline Co. v. Mobile Gas Service Corp., 1956, 350 U.S. 332, 339, 76 S.Ct. 373, 378, 100 L.Ed. 373.

See notes 5-13 supra and accompanying text.

Certain of the producers urge that §§ 4 and 5 must in combination be understood to preclude moratoria upon filings under § 4(d). They assert that the period of effectiveness of a rate determination under § 5(a) is limited by § 4(e) ; they reason that § 4(d) creates an unrestricted right to file rate changes, and that such changes may, under § 4(e), be suspended for a period no longer than five months. If this construction were accepted, it would follow that area proceedings would terminate in rate limitations that could be disregarded by producers five months after their promulgation. The result, as the Commission observed, would be that “the conclusion of one area proceeding would only signal the beginning of the next, and just and reasonable rates for consumers would always be one area proceeding away.” 34 F.P.C., at 228. 390 U.S. at 781, 88 S.Ct. at 1367. The same conditions, of course, are present here.

It is to be emphasized that the moratorium provisions do not prohibit increased rate filings. They prohibit rate filings in excess of the ceilings. These ceilings are the maximum prices that the Commission feels can be considered just and reasonable. The Commission has added noncost increments to the rates that present the greatest danger of inadequacy, and it has provided avenues of extraordinary relief, both industrywide and on an individual-producer basis, whereby the moratoriums may be lifted. We do not think that the moratorium provisions, which are necessary to the area regulation process, “write section 4 out of the Act,” as the producers have contended.

These two considerations can also be extracted from the following Permian language : “We cannot, given the apparent stability of production costs, the Commission’s relative inexperience with area regulation, and the administrative burden of concurrent area proceedings, hold that this [moratorium] arrangement was impermissible.” 390 U.S. at 781, 88 S.Ct. at 1367.

Moreover, the Tenth Circuit had stayed the moratorium order and it consequently had no effect at all throughout its duration, 390 U.S. at 777, 88 S.Ct. at 1365.

Specifically, considerations relating to the law of the case should be accorded only limited significance, since experience with area regulation may increase to such an extent as to constitute a change in circumstances.

Theoretically speaking, the indefinite nature of the moratorium will assert itself only in the future. Practically, it will have some effect on industry expectations and hence industry conduct. But since the new proceedings before the Commission create expectations that ceilings may be changed, we consider the present effect of the indefinite moratorium tó be minimal.

We reiterate, as the producers seem to lose sight of the fact, that the Commission is not required to compute return by the comparable earnings test. See note 38 supra.

The producers’ most easily comprehended presentation is a graph over the years 1947 to 1968 of rates of return they considered comparable. The 1958-1962 period chosen by the Commission is decidedly a dip in the curve, reflecting a recession during these years. Also, the producers attack the Commission’s choice of companies to compare and failure to consider evidence showing a rise in earnings since 1963. Persuasive evidence, however, supports the Commission’s action, and we are not engaged in finding these facts anew. Furthermore, the rate of return even as set may be higher than 12 percent. Non-cost factors, if they are viewed as additions to the return — and this is a logical way to view them, since they must go either to pay costs or to increase return —would increase return to 14-16 percent for new gas. Earnings on equity at a 12 percent rate on capital, of course, are higher than 12 percent because they are leveraged by debt; here they amount to about 13.3 percent. Finally, the producers’ argument for a 16-18 percent rate of return is defective because it includes early years in which very high returns— well over 20 percent — distort the figure so that it is unreliable for present use.

Imprecision is, however, one of the reasons for the requirement that a regulatory body reassess its rates in terms of purpose and consequences. See section IV A (3) infra.

390 U.S. at 818-820, 88 S.Ct. at 1386-1387. Cf. 390 U.S. at 829-838, 88 S.Ct. at 1392-1397 (dissenting opinion of Mr. Justice Douglas).

See 3 Joint Appendix, pt. 1, at 77d (examiner’s discussion of testimony and exhibits regarding rates of entry and exit).

A different question would be presented if the persons' regulated were prevented in some manner from going out of business even when revenues fell below costs.

The Court held that railroad rates for a route spanning two territories, served by two or more carriers in cooperation, cannot be divided among the carriers on the basis of costs for both territories taken *433together if the costs of lines in one territory distort the cost findings so derived for lines in the other. In the absence of a finding that there is no distortion, said the Court, the unadjusted costs for either territory or for the whole are not substantial evidence.

The examiner, after extensive consideration, concluded that Southern Louisiana costs were probably slightly lower than those for the nation. 3 Joint Appendix, pt. 1, at 221d-31d.

The producers contend, for example, that costs for the Hugoton-Anadarko area are significantly lower since reservoirs are shallower and should be excluded. The examiner’s overall comparison of Southern Louisiana with national costs, however, is more to the point.

There are limits to the movability of gas exploration, too, since a pipeline “cannot be moved around like a garden hose.” See E. Neuner, supra note 9, at 282; note 101, infra; Staff Report at 17.

Compare, e. g., 4 Joint Appendix, pt. 1, at 546d (Commission’s Opinion, calculating FP ratio at 1.37 for recent years in 1966) with Brief for Amerada Group at 17 (indicating FP ratio of approximately 0.62 for 1968, calculated from Bureau of Mines figures).

It is to be noted that the Permian case, too, was eight years old when the Supreme Court issued its opinion.

See, e. g., note 72 supra.

See 4 Joint Appendix, pt. 1, at 666d-76d (Commission’s Opinion).

The Commissioner’s computations produced the following: Item Impact in ft/Mcf 22-year depletion period .................................... 0.480 Time lag of 1.57 years...................................... 0.28 Drilling costs — successful well .............................. 0.29 Related Lease acquisition ....................................... 0.09 Return allowance ....................................... 0.43 Unit capitalized outlay .................................. 0.31 Exploration and development ................................ 1.90 Dry Hole ................................................. 0.19 Liquids credit.............................................. 0.25 He added that “I have no idea that all or any of these figures are precisely correct; I think the Commission and its staff has no better idea. ” Id. We find the arguments in this dissent to be strong ones, but it is not our task to choose which method we could use. The Commission has followed the cost method in this case, and we cannot reverse its decision here. We have inspected the Commission’s findings as to each of the cost items attacked by the producers with some care. Although we do not discuss each individually in order not to lengthen an already lengthy discussion (cf.* notes 29-32 supra), we find each to be supported by substantial evidence.

4 Joint Appendix, pt. 1, at lOOOd (dissenting opinion). The Commissioner stated that he could not decide this case on the basis of any cost record. In light of the imprecision of costs, broad support for the settlement, evidence that the market has at least a procompetitive structure, and cumbersome nature of price regulation, it may be that the settlement arguments advanced by Commissioner Carver are persuasive. In this case, the settlement is championed by the producers, and before the Commission it was supported by gas distributors (whom we classify as representing consumer interests) accounting for over 87 percent of delivery volume. Id. at 1001d. Widespread use of the settlement technique would result in negotiation pitting market forces against each other on an aggregate scale, overseen by the Commission.

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., supra, 320 U.S. at 602, 64 S.Ct. at 288. In keeping with this statement, we would not have such serious misgivings about affirming this order, with all the infirmities of the Commission’s pricing methods, if the Commission had adequately considered its result in a larger context. A reviewing court, which is not privy to the Commission’s special knowledge, is not likely to be able to make the assessment of results that the Commission could. We are troubled greatly by the fall in the FP ratio, for example, and cannot know whether it is so serious as to warrant some immediate, extraordinary action by this Court. The point is that without adequate consideration by the Commission of ultimate market impact, even slight troublesome facts assume fearful proportions. In this case, the producers, as well as the FPC Staff, predict a severe gas shortage, with disastrous effects on consumers and the economy alike. This Court has little inclination to join the Commission in presiding over such a result.

Indeed, the Hope case interprets the policy of the Act as involving both consumer interests and the autonomous interests of the industry. The Commission must balance the investor and the consumer interests. 320 U.S. at 603, 64 S.Ct. at 288.

390 U.S. at 792, 88 S.Ct. at 1373.

The Commission’s most specific finding as to demand appears to be that “there seems no doubt that natural gas will be a major and vital source of energy for many years to come.” 4 Joint Appendix, pt. 1, at 664d. This assessment is practically useless and should be made with far greater specificity in future proceedings. The Commission also stated that “[w]e must reject the findings-to-production and reserves-to-production ratios as not substantially indicative for fixing ceiling *436rates in this proceeding.” 4 Joint Appendix, pt. 1, at 529d. But see note 122 infra. The ratios need not have been directly considered in price computation, but the effect of the price on them should have been assessed.

AVe agree that the econometric studies were fatally defective, for the reasons set out in the examiner’s decision. 3 Joint Appendix, pt. 1, at 380d-408d. Their most basic and serious defect is their tacit underlying hypothesis that demand will call forth sufficient exploration to meet it regardless of cost or profit considerations. The examiner quoted the following argument advanced by Amerada: Although we approve the Commission’s action in rejecting these studies, we do not approve of its failure to consider supply in relation to demand. It should be pointed out that in doing so the Commission has itself committed an error similar to Staff’s. The error is not so serious as that of utterly failing to consider the profit incentive, but the Commission lias assumed, without supporting findings, that the cost-plus-return price will be sufficiently profitable to elicit supply to meet demand, whatever the level of demand. This is circular pricing. If demand rises and cannot be satisfied out of reservoirs that are easily enough found to allow the entrepreneur his profit, demand will not be satisfied. Having found that rigorous mathematical equations could not solve this problem, the Commission should have confronted it in a semiquantitative or qualitative way.

See 4 Joint Appendix, pt. 1, at 667d-73d.

We do not think reviewing courts should accept such conclusionary findings as this after the “experiment” justification for affirmance no longer applies. The Commission should have looked directly to sources and availability of capital.

*4* Joint Appendix, pt. 1, at 683d. The finding as to the total expected revenue is eommendably specific. However, it is useless to persons not privy to the Commission’s expertise, because the Commission has simply stated a figure floating in a vacuum and concluded without more that this figure will “foster an active exploratory program.”

*4* Joint Appendix, pt. 1, at 664d.

See FPC, Staff Report on National Gas Supply and Demand 11 (1969) (projecting FP ratio as declining steadily from 0.92 in 1969 to 0.73 in 1975).

THe New York Commission states that “In every major appeal, the producers’ ‘major issue’ has been the claim that if the producer position were rejected, the result would be a wide-spread shortage of natural gas Reply Brief for New York Public Service Commission at 14. In Permian, the Supreme Court noted that one party had characterized the producers’ concern for the RP ratio as a “neurotic preoccupation.” 390 U.S. at 817, 88 S.Ct. at 1386 n. 103. The producers there had argued that the ratio should be kept at a minimum of 20 to 1, and there was substantial evidence that lower ratios were acceptable. The Court evaluated the significance of these ratios as follows:

See, Address by Chairman White, A Regulator Looks at the Electric and Gas Industries with a Sidelong Glance at Investment Analysis, before the Financial Analysts Federation, May 16, 1969; Address by Commissioner O’Connor, Prospects for Future Gas Supplies, before the National Ass’n of Regulatory Utility Commissioners, October 7, 1969; Address by Commissioner Brooke, before the Independent Natural Gas Ass’n of America, September 9, 1969; Address by Commissioner Bagge, The FPC and Area Pricing: The Need for Re-examination, before the Gas Industry Seminar at Oklahoma State University, May 13, 1969. We take judicial notice of the concerns these speeches express. See C. McCormick, Evidence § 328 at 704 (1954). (We do not, of course, take judicial notice of the specific facts they state for the purpose of resolving contested issues. Id.)

Staff Report at 1.

See note 91 supra (Econometric studies).

A critical ratio will ultimately be reached in each area below which the RP ratio cannot be decreased, meaning that at that point production cannot be increased without reserve additions, according to the Staff Report. But reserve levels at any given time are determined by previous levels of exploration, and there is a lag before new exploration results in addition of usable reserves. Staff has calculated the critical RP ratio for Southern Louisiana at approximately 8. It has projected the future of the RP ratio and determined that the critical level will be reached about 1973 or 1974 under a “business as usual” regulatory program. At that time production, having kept up with demand, will not be capable of being increased, and deficiencies will come about which production from other areas will not be able to pick up because of lack of delivery lines and because they will be approaching the critical ratio. See Staff Report at 14-17.

Staff Report at 4.

The supply of natural gas is, of course, ultimately limited not by exploration but by the amount of recoverable reserves. The Potential Gas Committee, a group of experts from all segments of the gas industry, has recently estimated the total recoverable reserves in and offshore to the United States and Alaska at 1,227 trillion cubic feet, divided into probable supply, possible supply, and speculative supply. Consumption in 1968 was 19 trillion cubic feet. Address by Commissioner O’Connor, supra note 98. In other words, production for something over sixty years would exhaust this estimated supply even at present levels. The situation is aggravated by (1) growing demand and (2) increasing difficulty of finding reserves as one goes from probable to speculative supply areas. See Terry, Future Life of the Natural Gas Industry, in Economics of the Gas Industry 275 (Southwest Legal Foundation ed. 1962). Of course, supply from other countries, pipelined in or brought in as liquid (LNG), synthetic gas, and other sources, could have an impact on this problem. Staff Report at 47-76. Farsighted gas regulation, however, would take into account the rational development of this depletable supply, perhaps even to the extent of having that development influence present area rates. See note 121 infra.

Staff Report at 19 (graph showing supply, demand, and deficiency projections into the late 1980’s).

See notes 39, 91 supra (concerning econometric studies and rate of return).

See notes 5-13 supra.

As we have previously stated, reliance on Permian is justified by the “experiment doctrine.” The case had been commenced seven years before Permian and the Commission’s opinion issued five months after Permian. Nevertheless we think some deference to the expectations of the Supreme Court would have been appropriate, if only to show the Commission’s awareness of them, especially in light of the advance warning given by the opinion of the Tenth Circuit.

390 U.S. at 800, 88 S.Ct. at 1377. The Supreme Court had difficulties similar to ours with noncost elements. 390 U.S. at 815, 88 S.Ct. at 1385 n. 97. The Court charitably observed that “the Commission’s exposition of these questions might have been more carefully drawn.”

It should not be possible, for example, for a party on appeal to characterize a noncost element as a “phantom” tax allowance. The characterization in this case is absurd, but the possibility for it arose as a result of the Commission’s timid treatment of the matter. See note 43 supra. It would be far better if both courts and parties got down immediately to the real issue — whether the noncost element can be justified.

See 390 U.S. at 815, 88 S.Ct. at 1385, nn. 97-99 and authorities therein cited.

The natural gas industry, even though regulated, is subject to antitrust legislation, and the policies of that legislation should not conflict with the impact of the rate order. If a significant decline in the number of competitors appeared probable, it would be a matter of concern in antitrust law even in a large, fragmented market. See United States v. Von’s Grocery Co., 1966, 384 U.S. 270, 86 S.Ct. 1478, 16 L.Ed.2d 555.

In this connection, the Commission might well consider the recommendations of Mr. Justice Douglas in Permian rather than emphasizing, as it has in its brief, that his was a “solitary” dissent. The use of average costs without examination of results troubled him and troubles us. We agree, as did Justice Douglas, that the Commission may certainly use average costs, but it should make some finding of effects so that it will be sure that their use is in the public interest. The majority opinion in Permian is authority for the proposition that the Commission does not have to make the assessment Justice Douglas would have required, but the making of that assessment would by no means be incompatible with the majority opinion and would be in the public interest. Cf. notes 77-80 supra and accompanying text.

D.C. Transit System, Inc. v. Washington Metropolitan Area Transit Comm., 1965, 121 U.S.App.D.C. 375, 350 F.2d 753.

324 U.S. 581, 612, 65 S.Ct. 829, 843, 89 L.Ed. 1206 (concurring opinion of Mr. Justice Jackson).

390 U.S. at 792, 88 S.Ct. at 1373. We interpret “the purposes for which, it has chosen to act” to mean that conduct and level of performance, or other characteristics, that the Commission is trying to elicit from the regulated industry, and the public interest that it is trying to further thereby.

See Staff Report at 11 (chart showing past and projected production). Staff forecasts about six percent.

This proposition, we think, is a logical corollary of the proposition that cost pricing is ultimately circular. See notes 48-49, 91, supra. If present demand is satisfied at a price at which only promising areas are explored, there is no assurance that the same price will cause higher demand to be satisfied. Indeed, there is assurance that it will not if increased production requires exploration of less promising (i. e., more expensive) areas, because entrepreneurs will not explore those areas. The Commission has found that there are huge virgin areas in Southern Louisiana “untouched by the drill,” but this finding, without more, does not show that these areas will be developed to satisfy increasing demand at the price set.

In particular, it should make predictions as to the probability of an anomaly in the supply-demand relationship, such as the imminent reaching of a critical ratio. See Staff Report at 15.

We are well aware that the producers have not helped the Commission to make this prediction. See 4 Joint Appendix, pt. 1, at 885d. Nevertheless, it is the Commission’s responsibility to make a prediction of this nature as best it can. Indeed, we think the process of area regulation is only as good as are numerous such forecasts made by the Commission, either tacitly or expressly. We would prefer they be express.

For example, the Commission has power to curtail wasteful uses of natural gas. FPC v. Transcontinental Gas Pipe Line Co., 1961, 365 U.S. 1, 81 S.Ct. 435, 5 L.Ed.2d 377. Besides using price as a tool to elicit supply, we think it probably has power to use it to provide for the orderly consumption of limited reserves. Cf. note 103 supra.

We have had difficulty, for example, with the Commission’s categorical elimination of the FP ratio from consideration as compared with its use of the FP ratio to calculate new-gas exploration costs. 4 Joint Appendix, pt. 1, at 529d, 546d. The latter reflects either arbitrary, intentionally circular pricing or a judgment that preserving a certain FP ratio does matter. This is an example of a conflict whose resolution would go to the very heart of our doubts about this case. See also notes 50-51 supra.

See, e. g., 390 U.S. at 815, 88 S.Ct. at 1385 nn. 97-98.

Section 16 of the Natural Gas Act, 15 U.S.O. § 717o (1963), gives the Commission power to “perform any and all acts, and to prescribe, issue, make, amend, and renoind such orders as it may find necessary or appropriate to carry out the provisions of this chapter” (emphasis added).