In Re Other Southwest Area Rate Case (Oswa I). Shell Oil Company v. Federal Power Commission

JOHN R. BROWN, Chief Judge: This case involves rates fixed by FPC on October 29, 1971, for the so-called Other Southwest Area, and now joins SoLa I and SoLa II as OSWA I. Following the mandate of the United States Supreme Court in Phillips Petroleum Co. v. Wisconsin, 1954, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (Phillips I), FPC began its long and winding journey toward the effective regulation of the rates at which producers of natural gas in interstate commerce may sell their gas at the well-head. After several years’ attempts to regulate producers individually based upon their individual costs-of-service, FPC determined to establish the “just and reasonable” maximum rates for the well-head sales of gas on an area-by-area basis. See Wisconsin v. FPC, 1963, 373 U.S. 294, 83 S.Ct. 1266, 10 L.Ed.2d 357 (Phillips II). This method was explicitly approved by the Supreme Court in The Permian Basin Area Rate Cases, 1968, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312, and by us in Austral Oil Co. v. FPC, 5 Cir., 1970, 428 F.2d 407 (SoLa I), and again in Placid Oil Co. v. FPC, 5 Cir., 1973, 483 F.2d 880 (SoLa II), Accord, Hugoton-Ana-darko Area Rate Case, California v. FPC, 9 Cir., 1972, 466 F.2d 974. And before the last slug falls in the St. Paul linotype on this opinion area rate regulation may too be forgotten if not abandoned. For FPC has very recently announced its hopeful purpose to set uniform rates for the nation as a whole under its rule-making powers. 1 *471 So though we write with the realization that the regulatory approach may soon change, we are nevertheless mindful that we must play our role. In the present case, we are called upon to, review FPC Opinion 607 (Op: 707) which purports to establish the “just and reasonable” rate ceilings for the so-called “Other Southwest Area” (OSWA). 2 Because of the similarity in proceedings and heavy reliance by FPC on its SoLa II approach in Op: 607, many of the legal issues which we are required to decide to effectively review this case are controlled by our decision in SoLa II. 3 Yet, OSWA’s lack of total homogeneity in the various geographical production areas and FPC’s approach to them compels us to examine several aspects of Op: 607 in detail. The Op: 607 Rate Structure The maximum rates at which natural gas may be sold in OSWA, according to the terms of Op: 607, depend on two *472 factors: the “vintage” 4 of the gas and the particular OSWA sub-area from which it is produced. There are three vintages of gas based upon the date of the contract under which the gas is committed to the interstate market — pre-1961 gas, 1961-68 gas, and post-1968, “new” gas. Within these categories the maximum gas rates for OSWA may vary according to the sub-area of production as follows: —pre-1961: 14.4^,/Mcf to 19.0^/Mcf -1961-68: 17.250/Mcf to 19.00/Mcf —post-1968: 22.5^/Mcf to 25.00/Mcf 5 . Of course rates are the major work-produet of a rate case. But in OSWA, as in all of FPC’s other rate cases, there were a number of administrative appendages to the rate structure. These included : —a program to allow producers owing refunds to work off this obligation by committing new reserves to the interstate market, —a moratorium on increased rate filings under Section 4(e) of the Natural Gas Act for OSWA until July 1, 1976, —a 1.0 to 1.5(4/Mef adjustment for ungathered gas, —quality adjustments according to Btu content, and —“small producer” exemptions and special dispensation procedures. Our review of the case convinces us that these provisions should be sustained in full. Yet, we must confess our bewilderment in light of FPC’s current approach to rate regulations, especially its actions in SoLa II and Texas Gulf Coast, 6 with the rates established for “flowing” gas. As some of the producer-petitioners point out, unlike SoLa II which was based entirely on 1969 cost data, most — if not all — of these rates were established on the basis of 1962 cost data. Although on an examination of quality-pressure-geographic differentials we are convinced that in so doing FPC acted within the “zone of reasonableness”, which we accord to administrative action, we must in light of this evidence cast our enforcement of this aspect of Op: 607 — as we did in SoLa I: 5 Cir., 444 F.2d 125 (on rehearing) — in *473 a manner which gives FPC maximum flexibility to alter the rates established for flowing gas by Op: 607 both prospectively and retroactively as it deems necessary in light of existing market data. With this emphasis we give full enforcement to Op: 607. Supply and Demand in OSWA In SoLa II we chronicled the details of our current critical supply shortage of natural gas and other energy sources. As we pointed out, the proliferating national demand for natural gas has already outstripped available supply. 7 One need not consult an oracle to determine that, unless severe steps are taken to encourage exploitation of domestic reserves of natural gas, the future portends an even greater supply deficit. When it concluded its regulatory undertaking for OSWA in October 1971, FPC was conscious from its prior rate cases of the magnitude of this supply crisis. Recognizing the applicability of national and other area data to OSWA, FPC began by carefully assessing OSWA. “Other Southwest” is not a homogeneous area. Each of the four areas covered by previous area rate proceedings was generally similar throughout, with some deviations, in geology, pric *474 ing history and markets served by the gas produced in the area concerned. Other Southwest, on the other hand, has a variety of pricing histories in its different sub-areas, the geology varies in different sub-areas, and the gas produced in Texas District 9, Other Oklahoma and northwestern Arkansas goes to different markets than gas produced in other sub-areas. The importance of the intrastate market varies in the various sub-areas. The age of development and the potential for future development also differ widely throughout the Other Southwest area. For these reasons, we shall consider the various sub-areas separately, stating in each instance the facts relevant to our particular determination. Op: 607, fl 4. Annual production from OSWA has remained relatively constant at about 1.2 Tcf since 1956. But, because of the increasing national consumption of natural gas since that time, OSWA’s percentage share of the national market declined from 19.6% in 1956 to 13% in 1963, and 9% in 1969. Exploratory efforts have decreased significantly in the last decade, though the potential for the area gives cause for hope. 8 The quality of the gas in OSWA is generally inferior to that of the other major producing areas by any parameter —Btu, pressure, or purity. Also of major significance is the fact that at least 40-45% of production in OSWA is diverted to the intrastate market. 9 Based *475 upon this data, FPC set rates for the various sub-areas of OSWA. A Closer Look at Op: 607 In SoLa II FPC targeted a goal of 45 Tcf production from the Southern Louisiana Area for a five year period. It then established a rate structure which it believed would be a reasonable incentive to motivate producers to produce and dedicate that particular amount. 10 In OSWA, on the other hand, FPC began from the premise that OSWA production would never meet demand: “While we cannot expect that this area will be able to supply the potential demand upon it, it is important that its potential be fully utilized in this time of national need for all available gas.” Op: 607, |f 10. FPC projected that 11 Tcf of new reserve additions would be required over the next five years to meet the extrapolated demand for inter and intrastate gas. As in SoLa II, FPC was unable or unwilling to quantify the relationship between the rates it established and the likely response of market forces. There is no reliable evidence to indicate the amount of new gas reserves that would be discovered as the result of any specific change in rates, nor evidence as to the amount of such reserves that would be dedicated to the interstate market. We estimate that this area has probable reserves of from 15 to 18 trillion cubic feet still to be discovered. The prices established herein provide incentives, however, to the producers in this marginal area to find gas and dedicate it to interstate commerce. The prices established will enable the interstate market to compete in price with the present and potential intrastate buyers in the area. Op: 607, If 13. In spite of the strenuous arguments of several producers to the contrary, it is clear that FPC — in line with the approach it has taken in SoLa II and the Texas Gulf Coast Area Rate Case — used the average cost determinations for the production of natural gas in OSWA as a flexible point of departure. Op: 607 U 16. In both SoLa II and Texas Gulf Coast, FPC held that this point of departure would “flex” about 4^/Mcf. See SoLa II: 483 F.2d p. 902 n. 23. *476 And, as FPC pointed out, that point of departure is even harder to ascertain when the administrative agency has to compute costs on the basis of an area which is a heterogeneous amalgamation of separate sub-areas: Cost computations are notoriously imprecise. Where the districts on which the computations are based are as small as they are here, it becomes even more questionable whether the computed costs are representative. Op: 607, If 34. Basically, FPC used the same approach here as in SoLa II, that is, to price new gas on the basis of national, published data, but to price flowing gas on the basis of regional, historic data. In addition to the supply and demand information available to it and the costing data for the area as a whole, FPC also established as points of reference the various sub-area costs, the levels of both inter and intrastate prices, and the prices of gas in the adjacent producing areas. See Op: 607, f[ 16. Taking all of these factors into account it established a three-tiered rate structure as approved by the Supreme Court in Permian. There were two “vintages” of flowing gas — the first being composed of gas committed to the interstate market under a contract signed prior to January 1, 1961, and the second being gas committed to the interstate market by a contract dated between January 1, 1961 and September 30, 1968. 11 All gas committed under a contract dated after October 1, 1968 was third vintage or so-called “new” gas. The rates established for pre-1961 gas varied from 14.4?!/Mcf to 19.0?!/Mcf (with periodic, automatic escalations) depending on the sub-area of production. 12 The maximum permissible rates for 1961-68 gas ranged from 17.25?!/ Mcf to 19.0?!/Mcf (with half-penny escalations on January 1, 1965 and Oc *477 tober 1, 1968). 13 The rates for post-1968 “new” gas ranged from 22.5^/Mcf to 2E.O0/Mcf. 14 These three sets of rates comprise the entire rate structure for OSWA. What’s Wrong With The Rates The major producers 15 vigorously attack the Op: 607 rate structure set by FPC for OSWA. Their principal complaint is that the rates are not high enough. Groping for a legal theory on which to base this economic lamentation, they raise several issues. First, the majority of the major producer-protesters, the “Shell Protestants,” suggest that FPC’s continued use of cost-of-serviee as a point of departure can no longer be justified. Mobil joins this group in making its second argument that FPC has failed to take full account of the competitive effect of intrastate prices in establishing the permissible ceilings for OSWA interstate rates. Finally, the entire array of producers makes the general assertion that in several particulars the rate structure is not supported by the evidence in the record. Cost-of-service: A Point Of Departure The thrust of the Shell Protestants’ first argument is that because of the current supply shortage, it is administratively inappropriate for FPC to con *478 tinue to use the “lowest reasonable level” 16 method of determining “just and reasonable” rates. In this context they argue that the reasonability of rates should be determined by comparison to the rates for alternative, substitute or competitive fuels rather than from calculations based upon a cost-of-service with a rate of return sufficient to serve as an incentive for new production. In short, the producers apparently call for regulation of rates by market forces alone- — -the law of the jungle! 17 We recognized in SoLa I that market conditions might well justify FPC in adding non-cost incremental incentives to the rate structure. But the mere presence of a supply crisis does not compel FPC to wholly abandon a costing methodology as it carries out its responsibility to determine “just and reasonable” rates. What the producers assert as an economic proposition (and then seek as a principle of law) is that total freedom from any effective administrative regulation of rates is the only solution for the energy crisis at hand. In SoLa II we examined at length FPC’s current approach to costing methodology. SoLa II: notes 6, 19, 23. We recognized and sanctioned FPC’s administrative discretion in fixing a particular rate which falls within the “zone of reasonableness” of the entire matrix of cost components. But in focusing on the “end result” and according appropriate deference to the administrative choice in light of the great flux in cost determinations, 18 we will not allow our scrutinizing of the whole to eclipse a consideration of the parts. Administrative discretion is not tantamount to synergistic legerdemain. We must decide whether FPC has erred in including, excluding, or evaluating components of the rate structure to determine if the particular error washes out in the “zone of reasonableness,” or has such significance that the result is unacceptable. Competitive Rates: Op: 607 and The Intrastate Market The first of these factors is the producers’ contention that FPC has failed to take adequate account of the effect of *479 intrastate rates, as updated with new data — on the OSWA rate structure. Using the table taken from the Shell Protestants’ initial brief the current weighted average of intrastate sale prices is 25.21^/Mef. 19 The sub-area breakdown of intrastate rates for OSWA provides a further basis for comparisons with the rates set by PPC in Op: 607. 20 A careful examination of these rates shows that the “new” gas rates established by Op: 607 exceed the weighted average of current intrastate sales in every sub-area except Other Oklahoma. In response to this cold hard fact, the Shell Protestants suggest in their reply brief that while this may be true, FPC-determined interstate rate ceilings should correlate with maximum rather than weighted average intrastate rates. No court has held — and we do not hold today — that intrastate rate levels are a mandatory component of the interstate rate scheme. Nor do any of the producers claim that, as a matter of law, they are. FPC obviously considers this one of the relevant factors since the competition from non-federally regulated intrastate purchases affects quite directly the total available supply for both intra and inter state gas. 21 From an administrative point of view, buttressed as it would be by business practices, the use of maxima might well be both unmanageable and distorted. *480 The time has come for courts to recognize that there is a myth in much of the figures. Weighted averages are certainly permissible. In Op: 607 FPC took a realistic look at intrastate rate levels, and we can find no great incongruity between the rates set for OSWA and the prevailing rates in the intrastate market. New Rates For New Gas As to the contention of the producers that there is no record evidence to support the rates established by Op: 607 for new gas in OSWA, we must say that our reading of the record does not leave this impression. FPC was entitled to consider national cost data available to it and offered in the context of other area rate proceedings when it fashioned a rate schedule for OSWA. Two of these other rate schedules have already been sustained on judicial review. See SoLa II; Hugoton-Anadarko Area Rate Case: California v. FPC, 9 Cir., 1972, 466 F.2d 974. Given the experienced judgment which came from dealing with these cases as well as the record evidence of the instant proceeding, FPC was empowered to make a choice of costs from the permissible zone. In SoLa II, Part VII, we examined several alternative channels of relief for a producer whose special circumstances warranted higher rates than the maximum allowed by the area rate proceeding which served as anchors-to-windward. Of course all of those special relief procedures are equally applicable here. And there is a substantial indication that they are being exploited. 22 But we are also aware that — as far as the future pricing of “new” gas is concerned — area rate regulation as a regulatory method may be near to an end. For as we have previously noted FPC has issued a notice of a proposed rule-making 23 to establish “just and reasonable” rates for the well-head sales of natural gas on a national basis. While neither the terms nor the validity of this proposal are before us now, all must be aware of the administrative decision to exercise the prospective powers of § 5 of the Natural Gas Act, 15 U.S.C.A. § 717d, within a healthy regulatory framework to elicit necessary supply. In announcing its decision FPC expounded somewhat on its current approach: “We use cost as a basis for departure, as suggested in City of Detroit, although we recognize the inherent im-precisions contained in such an approach. We will look toward a range of just and reasonable costs and rates of return. We will likewise consider numerous noncost factors, including supply and demand and consequences upon the producing industry of the rate order. We will also consider the capital required to conduct the necessary exploration and development effort, prices of alternative fuels, prices of supplemental gas sources, intrastate contract rates, and the commodity value of natural gas. The end re- *481 suit will be a just and reasonable rate designed to maintain and assure adequate service to consumers and to attract the necessary capital to maintain gas exploration, . . . and production, at a level which will serve consumer needs.” 24 Our review of the costing evidence in the record, 25 the correlation between new gas rates and intrastate rates, the levels of substitute fuel prices, and other factors leads us to conclude that FPC has set new gas rate ceilings at a permissible point within the “zone of reasonableness”. The availability of individual relief and the possibility of FPC action setting national rates for new gas, while not a basis for our enforcement of Op: 607, do furnish solace to the Court. The Op: 607 rate structure for “new” gas is sustained in full. Flowing Gas Both Mobil and the Shell Protestants raise essentially three points to contest the rates for flowing gas: (i) FPC adopted the Administrative Law Judge’s proposed rates for flowing gas without adjusting the rate of return component from 10.5% to 15.0% as it had done for new gas; (ii) FPC failed to include an exploration and development adjustment and (iii) FPC returned to the Btu method of allocating expenses between oil and gas produced in association. Using cost merely as a point of departure minimizes the importance of a rate of return figure. But if one is to be used in this matrix, we find it difficult to see why FPC would consider it important enough to adjust upward for new gas but not to any degree for flowing. The rate of return approved by the Supreme Court in Permian was 12%. The SoLa II return was 15%. While we tend to defer to administrative expertise to determine the appropriate rate there is much bewilderment with FPC’s rote adherence to the 10.5% figure in OSWA. Mobil expresses dismay with FPC’s failure to provide some additional exploration and development component to flowing gas rates. In SoLa II we held that FPC may decide that gas committed under old contracts should bear its fair share of the burden for development of new resources to meet total demand. We did not hold there that it had to do so. Nor do we now. Yet it does seem administratively incongruous to allow major interstate producers to recoup exploration and development expenses from gas which they sell under old contracts if it is produced in SoLa, but not if it is produced in OSWA, especially that portion which is in North Louisiana. Certainly that is so in the absence of explanation and the fact that Op: 607 was handed down on October 29, 1971, several months after SoLa II and Texas Gulf Coast decisions. See note 6, supra. The producers also complain of FPC’s use of the Btu allocation method 26 of *482 assigning costs between jointly produced oil and gas. Making this allocation has been a problem for some time. In SoLa I FPC used the Btu method and determined that a ratio of 3.5:1 oil to gas would be appropriate in apportioning expenses. Then in SoLa II it determined to abandon this method in favor of a direct assignment of expenses based upon producer-furnished data. But to tally the proceedings and court sanctions on one side or the other is fruitless. We may assume that either method may be a permissible method of allocating the expenses, but in view of the Shell Protestants’ factual allegation that use of the direct assignment method would have made a 6.17^/Mef difference in the flowing gas rate for OSWA, we cannot lightly cast the point aside. This is especially true since FPC, on Staff’s recommendation, did abandon the Btu method in SoLa II in favor of direct assignments. Op: 598, |f/153. And in so doing it recognized the inherent judgmental factor in the Btu allocation. 27 On reading this segment of Op: 607 one might well conclude that it hailed from the pre-SoLa I era. But Op: 607 was issued in the wake of SoLa II. See note 6, supra. FPC’s failure to take account of this very serious factual allegation remains unexplained. Of course a significant fact which permeates the flowing gas structure is that FPC acted upon a 1962 cost basis in establishing these rates. Since then a lot of water has gone under the bridge and a lot of gas through the pipes. But what are we to do ? In SoLa I, 444 F.2d 125, 126-127 (on rehearing) we observed: Under section 19(b) of the Natural Gas Act, this Court has the broad remedial powers that inhere in a court of equity, and pursuant to our equitable powers we make it part of the remedy in this case that the authority of the Commission to reopen any part of its orders, including those affecting revenues from gas already delivered, is left intact. The Commission can make retrospective as well as prospective adjustments in this case if it finds that it is in the public interest to do so. Again we find it desirable to employ these flexible powers of equity to enable FPC to deal effectively with the public interest as it may see the need. Therefore, although we attach the label “enforced” to the end of this opinion, we emphasize that under our decree FPC has the authority — just as it did after SoLa I and subsequently reaffirmed by us in SoLa II — to alter or modify the maximum rates prospectively or retroactively which it established in Op: 607 for flowing, pre-October 1, 1968, gas if it believes that such a change would be in the public interest. 28 *483 Refunds In SoLa II we approved FPC’s implementation of an incentive program which permitted producers owing refund obligations to discharge them — not in cash — but rather at the rate of 1^/Mcf through the commitment of new reserves to the interstate market. Initially FPC declined to allow this refund credit for OSWA claiming that the “refunds here ordered are of such small amount that a refund credit would not provide an incentive to any materially increased exploration and development program.” Op: 607, 47. But on rehearing it recanted. “While the estimated amount of $5,000,000 (the Major Producers’ estimate) is small by comparison with total dollar revenues of the industry in this area, and although the resulting stimulus may not be great, in this time of increasing gas supply stringency every incentive should be applied which may help to alleviate the situation.” 29 Op: 607A, jf 4. Mobil attacks the refund credit system as being unduly discriminatory and preferential. Its basic premise seems to be that FPC adopted this incentive in lieu of a higher rate which might have been obtained if the refund credit had not been put into effect. This is without merit. As to the charge that the refund credit program discriminates, we enforce it on the basis of our lengthy discussion of the matter in SoLa II. We refuse to fault FPC for coping with the gas shortage in every possible way. The refund credit program is fully sustained. Moratoria FPC has imposed a moratorium until July 1, 1976 on increased rate filings under § 4 of the Act which are above the area rates prescribed by Op: 607. It is vigorously attacked by all producers in this proceeding. Moratoria are not new to area rate cases. They were sustained by the Supreme Court in Permian and by us in both SoLa I and SoLa II. Several factors prompted this action. Foremost among the justifications was the fact that some stability and rate certainty is needed if the industry is to be effectively regulated at all. Also, we cited and approved various alternative methods by which producers who are uniquely aggrieved by area rate ceilings may seek special, individualized relief. If that were all, we could merely enforce these moratoria provisions without further comment. But because our sanction in SoLa II was predicated in large measure upon factors not present here, we believe that some further comment is necessary. In SoLa II, we said: There are also other substantial reasons for rejecting the producers’ attack on the moratoria provisions. The marrow of their argument is that due to inflation and other economic factors, costs are very likely to rise substantially during the term of the moratorium. But two safeguards convince us that, if and when that contingency occurs, FPC is ready, willing, and able to make appropriate adjustments. First, the costing on 1969 data was relatively current and to a significant degree, the incentives established by Op: 598 apart from the rates themselves serve to bolster the financial position of the producers and protect them against rising costs. These are, of course, the provisions providing for the retention of large *484 amounts of capital through the refund discharge program and the periodic and contingent escalations. Second, there are several alternative methods by which a single aggrieved producer may establish higher rates as his circumstances warrant. 483 F.2d at 909. Not all of these factors are present here. While the new gas rates for OSWA are in parity with those adopted in SoLa II, the flowing gas ceilings here were not adopted on the basis of 1969 data, but rather on the basis of a stale 1962 record. Likewise, the amount 'of capital which will be retained via the refund credit program is substantially less significant in OSWA, and there are no contingent escalation provisions. Therefore, piecemeal relief on a company-by-company basis may not be effective with respect to the industry’s need for higher rates on flowing gas. So, in keeping with the flexible approach which we are adopting with respect to flowing gas rates, we do not frame our decree for all time. Rather we hold that FPC may, in light of its evaluation of the gravity of our national energy crisis and the evidence concerning flowing gas rates for OSWA, modify or rescind the moratorium if the need arises. 30 Enforced. Footnotes [1] See Notice of Proposed Rulemaking (April 11, 1973), Docket No. R-389B, 38 Fed.Reg. 10014 (April 23, 1973), [Foster Associates Report No. 891]. *471 PPC first used the abbreviated technique of rule-making for gas rate regulation in the Rocky Mountain Area. After the Tenth Circuit approved the procedure in Phillips Petroleum Co. v. PPC, 10 Cir., 1973, 475 F.2d 842, PPC established rates for that area in The Rocky Mountain Area Rate Case, Op: 658 (April 11, 1973), 49 F.P.C. -, 38 Fed.Reg. 9802 (April 20, 1973). On the same day it announced its intention of setting maximum “just and reasonable” rates for the wellhead sales of natural gas for the nation as a whole by July 1, 1973. Significantly, PPC declined to set new gas rates for the Rocky Mountain Area in Op: 658 in deference to its intent to cover that subject nationally in Docket No. R-389B. PPC’s announced purpose of using rule-making was to avoid the unnecessary delay and rate uncertainty which is attendant upon “protracted adjudicatory proceedings and subsequent court litigation”. PPC hopes the new procedure will provide the needed flexibility to effectively cope with major changes and national problems — like the current gas shortage crisis. [2] Actually, not only is OSWA not “Other” Southwest, it is not “Southwest” at all. OSWA is a heterogeneous amalgamation of six geographically, geologically, and economically distinct sub-areas lumped together by PPC for administrative, regulatory convenience. It includes all of (1) Arkansas and (2) Mississippi, (3) “Other” Oklahoma (the 56 counties in southern and eastern Oklahoma not covered by PPC’s order in the Hugoton-Anadarko Area Rate Cáse), (4) Texas Railroad Commission Districts Nos. 5, 6 and 9, (5) four counties in northwest Alabama, and (6) all of Louisiana north of the 31° parallel (that part not' covered by PPC’s order in SoLa II). Separate “sub-area” treatment was also given to Mississippi’s offshore reserves. See note 5, infra. The major geological feature of OSWA is the Ouachita Front, a fault in the earth arcing northward from northeastern Mississippi into Arkansas and then westward and southerly to the Big Bend area of Texas. Oil and gas above the fault are produced from the ancient rocks of the Paleozoic era, while production below the fault comes from the relatively young rocks of the Mesozoic and Cenozoic periods. And the geological distinctions do not even divide themselves at this juncture, for within these two categories there are a myriad of uplifts, basins, synclines, and the like. [3] Specifically, several of the petitioners have challenged (i) PPO’s establishment of October 1, 1968 as the division date between so-called “flowing” gas and “new” gas, (ii) PPC’s determination that casinghead gas, i. e., gas produced in conjunction with oil, is to be treated the same way for regulatory purposes as gas-well gas of the same vintage, and (iii) PPC’s failure to make special provisions for producers whose Brie-uncontrollable royalty obligations might exceed PPC’s current projections, see Mobil Oil Corp. v. FPC, 1972, 149 U.S.App.D.C. 310, 463 F.2d 256, cert, denied sub nom., 1972, 406 U.S. 976, 92 S.Ct. 2409, 32 L.Ed.2d 676, reversing FPC’s ruling after our initial primary jurisdiction reference’ to it, J. M. Huber Corp. v. Denman, 5 Cir., 1966, 367 F.2d 104; Weymouth v. Colorado Interstate Gas Co., 5 Cir., 1966, 367 F.2d 84. Because of the extended review which we gave these matters in SoLa II, these provisions of Op: 607 are enforced without further discussion. Of course, SoLa II is also helpful in our determination of the other legal issues presented in this case, including the costing methodology employed by PPC to determine both new and flowing gas rates, the provision which allows for a refund discharge through the commitment of new reserves to the interstate market, and the Op: 607 moratorium on increased rate filings under § 4(e) of the Act until October 1, 1976. But we shall speak more of these anon. [4] We discussed the anomaly of determining the vintage on the basis of the date of sale in SoLa II: 483 F.2d p. 892 n. 9. Interestingly, the “vintage” of casinghead gas is determined, not by the date of the contract first committing it to the interstate market, but rather by the date of discovery. See Op: 607A, If 2. In its recent Appalachian and Illinois Basin Area Rate Case, Op: 639, - F. P.C. -, now pending review in the Fifth Circuit, Docket No. 73-1329, FPC took steps to eliminate the “vintaging” of gas by providing that new gas rates shall be applicable, to the extent allowed by contract, to successor contracts between previously contracting parties. Both Order 455 and the proposed rule-making in Docket No. R-389B, see note 1, supra, also abandon the date of contract anomaly by tying the maximum permissible rate to the date of the well. But these administrative decisions must run the course of judicial review, and we note them only in passing. [5] OSWA includes the as yet untapped gas potential of the offshore federal domain contiguous to the Mississippi shoreline. In order to maintain parity with production from the federal domain lying off the southern shores of Louisiana, FPC established the same rates — 26f!/Mcf with a l^/Mcf escalation on October 1, 1974 — for the Mississippi off-shore domain as in SoLa II. For the reasons we stated in SoLa II: 483 F.2d p. 902 and n. 24, we enforce this determination without further discussion. [6] Rates for the prolific Texas Gulf Coast Area were established by FPC on May 6, 1971, in Op: 595, 1971, 45 F.P.C. 674, now pending review in the D.C. Circuit, New York Public Service Commission v. FPC, Docket No. 71-1828. FPC’s opinion in SoLa II followed close on its heels. Op: 598, 1971, 46 F.P.C. 86, ' was rendered on July 16, 1971. It is important to put OSWA into this temporal perspective. Op: 607, 1971, 46 F.P.C. 900, was issued on October 29, 1971, just 71 days after SoLa II and only 176 days after Texas Gulf Coast. [7] The Reserves-to-Production (R/P) ratio for OSWA declined from 11.0 in 1964 to 9.8 in 1969. This decline was largely due to inadequate findings. The Findings-to-Produc-tiou (F/P) ratio has been below unity since 1965. Staff’s projections indicate that this trend will continue: OTHER SOUTHWEST PRODUCTION, RESERVE ADDITIONS AND R/P RATIO Year Staff Report No. 2, “National Gas Supply and Demand, 1971-1990,” (February 1972). CA75207 [8] Several producers contend that FPC has failed to take a full account of the potential for natural gas production from OSWA. Staff credits the data of the Potential Gas Committee (PGC) which makes the following projections for OSWA. There are about 86 Tcf of potential natural gas reserves. This figure is about four times the proven reserves of the area and comprises approximately 10.1% of the reserve potential for the lower 48 contiguous states. The amount is estimated by PGC to be divided into two depth categories so that 73 Tcf are above 15,000 feet with only the remaining 13 Tcf between 15,000 and 30,000 feet. The real uncertainty which enshrouds OSWA’s potential becomes apparent from the categorization of these reserves: (i) only 10 Tcf (about 11.6% of the potential) are in the “probable” category, while (ii) 23 Tcf (about 26.8%) are “possible”, and (iii) 53 Tcf (61.6%) are “speculative”. The producers, however, suggest that even this somewhat optimistic view fails to include all of the areas encompassed within OSWA. According to their approximations, based upon data from the Potential Gas Agency at the Colorado School of Mines, OSWA has a total potential of some 164 Tcf — 13 probable, 40 possible, and 111 speculative. Given this substantial deviation from FPC’s factual premise, these producers conclude, “To the extent that the Commission’s unduly low area ceiling rates were predicated on the assumption that the area contains a minimal potential, clearly such finding is erroneous and must be set aside.” While we are pleased to hear that OSWA’s potential might exceed current estimations by FPC, we fail to see how this makes any difference in our review of the case since FPC established a rate structure which according to its own words would “fully utilize” the resources of OSWA. [9] And even this broad statement is somewhat misleading. Focusing on this one particular aspect of OSWA’s total factual picture gives some indication of the wide variances from sub-area to sub-area within OSWA. FPC acted on the basis of the following data with respect to intrastate sales: 7 Reports (Form 15) filed by pipelines with the Commission indicate jurisdictional sales of 1.210 trillion cubic feet in 1969, or 56.2 percent of the 2.152 trillion feet of production reported by the American Gas Association (AGA) for 1969 in the Other Southwest Area. By sub-areas, the comparable figures in billions of cubic feet are: AGA Form 15 Production Sales Percent; Other Oklahoma 592 260 44 Texas R.R. Dist. 9 181 60 33 Arkansas 166 138 83 Texas R.R. Dist. 6 437 217 50 Northern Louisiana 488 410 84 Mississippi 166 125 75 *475 All sales in Texas B..R. District 5 were intrastate in 1969, although there have been some interstate sales this year. No statistics are available for Alabama, but the volume is very small. The percentages are subject to a slight distortion because AGA production includes gas used in the field and never sold. Thus, the competitive effect of intrastate rates on interstate ceilings would be a critical factor in Texas or Oklahoma where the intrastate market claimed from 50-100% or 56% of production respectively, but relatively insignificant in Northern Louisiana or Mississippi where only 16% or 25% of production was diverted to intrastate consumption. These factual deviations are indicative of the complexity of FPC’s task in OSWA. It is because of such matters that reviewing courts assess administrative actions under such rubrics as “end result,” “zone of reasonableness,” and even “kid gloves.” See generally, SoLa II; 483 F.2d pp. 888-890. [10] FPC adopted a triumvirate of incentives in SoLa II. First, the rate structure itself —particularly the 26^/Mcf. rate for off-shore gas — was calculated to bring forth 15 Tcf. Second, FPC adopted a program by which producers could work-off the $150,000,000 refund obligation at the rate of l£ Mcf for each new Mcf of gas committed to the interstate market, in hope of producing another 15 Tcf. Third, FPC allowed for a contingent serial escalation of 1%^ Mcf on flowing gas rates in half-penny intervals when the industry as a whole committed 7%, 11}4, and 15 Tcf of SoLa production to the jurisdictional market. In Op: 607 FPC initially put all the eggs in the rate basket for OSWA. But on rehearing it decided to allow the same credit against refund obligations which it had used in SoLa II. Op: 607A, $4. [11] Actually, with respect to the Mississippi and Alabama sub-areas of OSWA, there was only one vintage of “flowing” gas. The rate for that gas was 19.0^/Mcf, but it was subject to half-penny automatic escalations on January 1, 1965 and again on October 1, 1968. [12] Prior to January 1, 1965 From January 1, 1965 Through September 30, 1968 From October 1, 1968 Other Oklahoma 17.5 18.4 19.4 Texas Railroad District No. 9 17.8 18.7 19.7 Northern Arkansas 17.0 17.9 18.8 Texas Railroad District No. 6 15.0 17.0 19.1 Northern Louisiana (at 15.025 psia) 16.7 18.6 20.6 Southern Arkansas 14.4 16.25 18.25 Mississippi and Alabama (at 15.025 psia) 19.0 19.5 20.0 [13] Prior to January 1, 1965 From January 1, 1965 Through September 30, 1968 From October 1, 1968 Until January 1, 1972 Other Oklahoma 18.4 18.9 19.4 Texas Railroad District No. 9 18.7 19.2 19.7 Northern Arkansas 17.8 18.3 18.8 Texas Railroad District No. 6 18.1 18.6 19.1 Northern Louisiana (at 15.025 psia) 19.6 20.1 20.6 Southern Arkansas 17.25 17.75 18.25 Mississippi and Alabama (at 15.025 psia) 19.0 19.50 20.0 [14] Texas District 9 24 Northern Arkansas 23 Other Oklahoma 23.75 Texas Districts 5 and 6 23.5 Southern Arkansas 22.5 Northern Louisiana 25 Mississippi and Alabama 18 25 [15] Led by the named petitioner, the Shell Oil Company, the primary group of producers challenging the Op: 607 rate scheme includes the Amoco Production Co., the California Co., Continental Oil Co., Gulf Oil Corp., Humble Oil & Refining Co. (now Exxon), Signal Oil & Gas Co., the Superior Oil Co., and Texaco, Inc. Aligned on the brief with these petitioners are intervenors Amerada Hess Corp., Ash-land Oil, Inc., Atlantic Richfield Co., the Marathon Oil Co., Murphy Oil Corp., Skelly Oil Co., Sun Oil Co., Tenneco Oil Co., and the Union Oil Co. of California. Eor convenience’s sake we shall refer to this group as the “Shell Protestants.” “Mobil appears as a loner challenging virtually every utterance of FPC. Shell, Signal, the California Co., and all of their intervenor-friends — on the other hand —have intervened against Mobil’s petition to the extent that it challenges (i) the refund-discharge provisions of Op: 607A, (ii) FPC’s decision to price casinghead gas on par with contemporary gas-well gas, and (iii) the “new” gas division date of October 1, 1968. From FPC’s point of view Exxon may have changed its stripes along with its name. See SoLa II: 483 F.2d p. 903 n. 27. In SoLa II, with the exception of Mobil and Amoco, nearly all of these producers supported FPC’s holding. Here they attack it. Of course the difference may lie largely in the fact that SoLa II was written according to the terms of a settlement compromise. [16] FPC has also rejected the notion that it should use “lowest reasonable cost.” In George Mitchell and Associates, Op: 649, “Opinion and order granting special relief and terminating proceedings, - F.P.C. - (Feb. 21, 1973) it said: “Lowest reasonable cost” has no meaning in regulation unless its determination encompasses consideration of reliability and adequacy of supply. If we are so concerned with price as a measure of profit that we ignore the effect of price on supply, we fail in our essential function. FPC is using cost-of-service, but only as a point of departure. [17] We do not mean to intimate, however, that the level of substitute or competitive fuel prices is not a probative factor in making the required determination of the propriety of the “end result.” See FPC v. Hope Natural Gas Co., 1944, 320 U.S. 591, 64 S.Ct. 281, 88 L.Ed. 333; The Permian Basin Area Rate Cases, 1968, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312; SoLa II. Nor do we hold that FPC could not, under the structure of the Act conclude that, in the light of record evidence, rates at the level of those for competitive fuels would be “just and reasonable.” This is far from the contention that on this episodic record covering a heterogeneous amalgamation of geographically unrelated areas FPC was compelled as a matter of law to do so. But these are matters for another day. FPC is charged by the Natural Gas Act with the responsibility for regulating the wellhead sales of gas. Of course it would be possible to amend the act in favor of total deregulation, and the current administration has proposed a bill to do just that with respect to new gas. See H.R. 7507, 93rd Cong., 1st Sess. (1973) (Introduced by Congressman Staggers on April 18, 1973). But until this obligation is lifted from FPC, it must determine as an administrative matter, the manner in which it will regulate. [18] FPC has repeatedly recognized the imprecision of costing calculations. In SoLa II; 483 F.2d p. 902 n. 23 we quoted from FPC’s Texas Gulf Coast Area Rate Case, Op: 595, 1971, 45 F.P.C. 674, 687. It bears repeating: “The cost computations used in this and other area rate proceedings seem to be mathematically precise. They are not. Allocations of costs are by nature matters requiring a substantial amount of judgment.” See also, SoLa II; 483 F.2d p. 899 n. 19. [19] 1969 First Half 1970_ _7/1/70 And Later Current Price a/ Current Price a/ Current Price a/ Area Annual Volume Wtd. Avg. Range Annual Volume Wtd. Avg. Annual Range Volume Wtd. Avg. Range (Bcf) ... .(4/Mcf)______ (Bcf) _ _(4/Mcf)_ (Bcf) -.....W/Mcf)_____ Permian Basin 146 14.57 8.26-23.99 103 21.47 15.60-23.07 137 23.90 8.96-28.50 South Louisiana 10 20.38 19.50-23.68 72 22.98 20.50-30.00 25 26.22 20.25-39.56 Texas Gulf Coast 148 19.39 12.05-22.13 38 18.39 10.50-24.38 75 22.19 11.00-30.11 Hugoton-Anadarko 6 17.32 15.00-19.33 13 21.55 18.00-24.04 45 22.65 9.25-35.36 Other Southwest 7 17.85 12.27-21.45 12 18.69 14.00-21.53 52 25.21 4.40-28.92 Rocky Mountain 0.7 11.57 9.75-12.00 8 18.05 6.83-19.01 20 17.32 6.00-25.00 California 9 31.26 25.00-35.25 1 30.43 25.00-31.00 11 34.09 27.00-37.00 Michigan 1 38.00 35.70-43.72 4 36.00 36.00 19 40.87 36.00-48.30 a. Inclusive of tax reimbursement, additive and deductive adjustments for gathering and Btu. The prices for the contracts dated in 1969 and the first half of 1970 are as of August 1970; the prices for subsequent sales are as of September 1971. CA91281 [20] 1969 First Half 1970 7/1/70 And Later Current Price a/ Current Price a/ Current Price a/ Annual Area Volume Wtd. Avg. Range Annual Volume Wtd. Avg. Range Annual Volume Wtd. Avg. Range (Bcf) _____W/Mcf)______ (Bcf) _____W/Mcf)_..... (Bcf) .....(<S/Mcf)_..... Arkansas 0.2 16.00 16.00 0.2 18.75 18.75 North Louisiana 2.7 21.45 21.45 0.3 20.58 19.50-21.45 Mississippi 1.0 20.96 20.96 _ Oklahoma 0.5 16.06 15.00-18.27 1.6 15.86 14.00-16.00 37.8 27.13 11.17-28.92 Texas District 5 1.9 13.91 12.27-17.64 1.0 18.50 18.50 9.9 21.80 18.00-27.45 Texas District 6 1.6 17.14 16.08-17.64 7.1 18.67 17.50-19.00 4.0 15.72 4.40-18.30 Texas District 9 0.9 21.53 21.53 -- -- -- a. Inclusive of tax reimbursement, additive and deductive adjustments for gathering and Btu. The prices for the contracts dated in 1969 and the first half of 1970 are as of August 1970; the prices for subsequent sales are as of September 1971. EA9129] [21] As we have previously pointed out, the weight which this factor has, from a purely economic standpoint, varies drastically from sub-area to sub-area within OSWA. See note 9, supra. [22] George Mitchell and Associates, Op: 649, “Opinion and order granting special relief and terminating proceedings,” -F.P.C.(Feb. 21, 1973) was such a proceeding granting special relief to a producer in OSWA. The readiness of FPO to entertain such petitions and the effectiveness with which they are processed bolsters the reassurance which we expressed in SoLa II, Part VII. [23] Of course, we make no intimations as to the validity of the rule-making process as a ■ procedural issue or the national rate concept as a legal issue at this juncture. We note that our Brothers of the Tenth Circuit have sanctioned the informal rule-making device as an acceptable procedural mechanism for the determination of “just and reasonable” rates for the Rocky Mountain Area. See Phillips Petroleum Co. v. FPC, 10 Cir., 1973, 475 F.2d 842. See note 1, supra. Rule-making was also used in Op: 639,-F.P.C.-■, now pending review in Fifth Circuit Docket No. 73-1329, relegating producers in the Appalachian and Illinois Basin Area to the optional procedures of FPC Order No. 455, “Statement of Policy Relating To Optional Procedure for Certificating New Producer Sales of Natural Gas,” promulgating 18 C.F.R. § 2.75 (August 3, 1972), now pending judicial review in the D.C. Circuit, Moss v. FPC, [No. 72-1837] and APGA v. FPC [No. 72-1846], for increased rates on new gas. [24] Notice of Proposed Rulemaking (April 11, 1973). Docket No. R-389B, 38 Fed.Reg. 10014 (April 23, 1973) [Foster Associates Report No. 891 at 3]. [25] For example, one major cost component is the drilling data — cost and yield per foot. In SoLa II FPC found that “drilling costs per foot should range upward from about $25.00 per foot,” and that “productivity estimates should cluster around 600 Mcf per foot drilled.” Op: 598, flf 120-21. No one challenges the additional finding that drilling costs vary greatly with the depth. The producers suggest, however, that $30.-OO/foot would be the appropriate drilling cost figure to use for OSWA. [Shell initial brief, at p. 50]. There is no compelling record evidence that a different figure should be used for OSWA than for SoLa. This is especially true when one considers the fact that 73 Tcf of the FPC estimated 86 Tcf reserve potential of OSWA are above 15,000 feet. See note 8, supra. [26] Exxon has filed a helpful supplemental memorandum detailing the Btu methodology. The problem is essentially this. Many dry holes are drilled in the course of the search for oil and gas. We are informed that 10,800 such holes were drilled in 1970 at a cost of approximately $873,000,000. Insofar as gas and oil are produced conjunctively, and the search is made for both, these expenses call for some allocation against the revenues of each. Likewise, exploration and development ex *482 penses for successful efforts must be apportioned. Eschewing volumetric comparison FPC has in the past allocated these costs based upon the relative production of energy, measured in Btu’s, of each fuel. See SoLa I, 428 F.2d 407, 422 n. 30. The thermodynamic breakdown yields a ratio of 4:1, but a further adjustment to account for the industry’s geographical technological ability to drill directionally solely for gas reduces the ratio to 3.5. To illustrate, if 10 Btu’s of liquids and 10 Btu’s of gas are produced in the test year and if $100 was expended in unsuccessful E&D, the calculation would be as follows : (a) 10 Btu (Liquids) X 3.5=35 10 Btu (Gas) X 1.0=10 (b) Ratio of 35 to 45=0.78 Ratio of 10 to 45=0.22 (c) 0.78 X $100=$78 (Allocated to Liq-quids) 0.22 x $100=$22 (Allocated to Gas) [27] Our discussion of FPO’s use of the Btu method of allocating exploration and development expenses between jointly produced oil and gas in no way pertains to the Shell Protestants’ challenge to the so-called Btu “gap” in quality adjustments. See Shell initial brief at pp. 60-63. That argument has not been neglected — only rejected. [28] Naturally since fund orders are obtained derivatively from the flowing gas rates this flexibility also extends to allow FPO to alter the total refund obligations accordingly if it chooses to modify flowing gas rates. *483 The same flexibility applies to any changes which FPC might want to make regarding the moratoria provisions. [29] The New York Public Service Commission also points out that the refund credit program may be somewhat of a disincentive since producers who desire to elect the benefits under the new Optional Procedure for Certificating New Sales promulgated by Order 455. (See SoLa II; Part VII), must discharge all due refunds in cash. Thus, the incentives cancel out. We think this is a matter within the judgment of FPC. The refund discharge program of OSWA is not to be discarded merely because it affords the producers an opportunity to choose which of two incentive plans, one perhaps more attractive than the other, will be selected. [30] See note 28 and related text, supra.