El Paso Natural Gas Co. v. Sun Oil Co.

MEMORANDUM ORDER SUTTLE, District Judge. This is a suit under the Natural Gas Act of 1938. 1 Its genesis is in the differential between the unregulated price of intrastate gas and the regulated price of interstate gas. El Paso Natural Gas Company produces natural gas for the interstate market. Plaintiffs claim that the Defendants must first seek certification from the Federal Power Commission (FPC) before they can collect overriding royalties in excess of the regulated interstate rate. Plaintiffs seek a declaratory judgment 2 that Defendants are natural gas companies selling gas for resale in interstate commerce. The suit reduces to the following proposition. 3 Where certain agreements, by which lessees transferred working interests in oil and gas properties to a regulated pipeline, provided for payments of overriding royalties on a scale initially set at a certain number of cents per Mcf of production and escalated that amount per Mcf over an initial term of years, and provided for arbitration of the amount of payments after the initial term if the parties were unable to agree on the amount, and where a subsequent arbitration award placed the amount of the override payments in excess of the FPC regulated price, are those agreements “sale[s] in interstate commerce of natural gas for resale” within the meaning of § 5 of the Natural Gas Act of 1938 (15 U.S.C. § 717d)? Since this Court’s jurisdiction coincides with the FPC’s jurisdiction over “sale[s] in interstate commerce of natural gas for resale,” from January 21 to March 4, 1976, this Court heard evidence to determine its jurisdiction. 4 Between April 23 and April 27, 1976, the Court heard arguments on the evidence. On November 22,1976, the Court heard arguments on the law. The Court concludes that it lacks jurisdiction and enters the following findings of fact and conclusions of law. FINDINGS OF FACT (1) Plaintiff El Paso Natural Gas Company (El Paso), a regulated interstate pipeline, is producing natural gas from its own leases in the San Juan Basin (Basin). In July 1950, the FPC certified El Paso to build a natural gas transmission line from the Barker Dome Field in the Basin to California. FPC certification established El Paso as the dominant economic force in the Basin, because El Paso, the only pipeline having access to interstate markets, was the only potential purchaser of Basin gas. After certification, El Paso acquired extensive leasehold interests in the Basin, 5 including the leaseholds involved in this litigation. *966 All the agreements at issue in this case were executed after El Paso had completed its transmission line. (2) The Defendants were originally lessees 6 holding working interests in certain oil and gas properties in the Basin. Under agreements denominated Gas Lease Agreements (GLAs) the Defendants transferred certain of their working interests to El Paso. (3) The GLAs in issue (GLAs 47, 52, 60, 61, 63, 66, 76, 78, 106, 125, 129, 172, 348 and 349) provided that El Paso would receive the rights to develop and market natural gas in one or more productive formations. 7 The agreements typically provided 8 that: (a) El Paso was obligated to drill each 320 acre drilling unit on the acreage transferred. If El Paso failed to drill a 320 acre unit, the unit reverted to the lessee. (b) El Paso was obligated to pay for wells located on the property which met a certain specified productivity. 9 (c) El Paso had the option of returning acreage which proved to be noncommercial. (d) El Paso was obligated to make a minimum payment if the amount of overrides on gas produced were less than that minimum amount. 10 (e) El Paso was obligated to pay an amount per Mcf that was equivalent to the amount El Paso paid for similar gas under similar agreements; i. e. a favored nations clause. (4) El Paso was obligated to pay an overriding royalty of a specified number of cents per Mcf of production. The amount to be paid per Mcf escalated over a fixed period of time (initial term). After the initial term expired, the amount of the override was to be redetermined by the parties. If the parties were unable to agree on the amount of the override payments, they were obligated to arbitrate. (5) No agreement at issue specified an up-front payment tied to an estimate of reserves. 11 (6) The San Juan Basin is a distinct geological entity located in the four corners area of New Mexico and Colorado. The Basin takes its name from its structure. In cross-section, the Basin is a bowl shaped depression. Formations lying several thousand feet below the surface at the center of the Basin rise to the surface at its edge. *967 The surface outcrops of the formations mark the Basin’s perimeter. (7) Three formations in the Basin are gas productive. 12 From the shallowest to the deepest the formations are the Pictured Cliffs, the Mesa Verde, and the Dakota. All three formations are tight in that each formation is characterized by low to moderate permeability and low porosity. (8) Recovery of natural gas from each productive formation is a function of the variations in the permeability and in the porosity of the formation. Because the Basin’s geologic structure does not reveal those variations in any productive formation, geologic structure has little or no direct influence upon the localization of recoverable gas reserves. Actual drilling is the only method of locating recoverable gas saturations. (9) Because the productive formations are tight, even where drilling located recoverable reserves, completed wells delivered gas in low .volumes. (10) Two consequences do flow from wells in the Basin because large volumes of gas do not. First, drilling costs are significantly higher because more wells have to be drilled to supply a pipeline with commercially significant volumes of gas. Second, where the drilling costs are recouped out of the volume of gas sold,' those costs are recovered more slowly for wells of low deliverability than for those of high deliverability. 13 (11) Some properties had no drilled acreage when the respective GLA was executed. For those properties that had drilled acreage when the respective GLA was executed, the number of wells drilled was quite small in relation to the number of drilling spaces available. (12) During the 1950’s and into the 1960’s, El Paso spent substantial sums developing properties it had acquired in the Basin. (13) During each GLA’s initial term, El Paso paid the specified overrides for volumes produced from the respective properties. (14) After initial term of each GLA had expired, El Paso continued to pay overrides *968 at the highest rate set out in the original agreement. (15) When, in 1973, the level of the override for GLA 61 was to be determined again, Sun Oil Company (Sun) and El Paso could not agree on the level of that override. The parties proceeded to arbitration. (16) A Board of Arbitrators awarded Sun an override of 40 cents per Mcf. The amount of the override was based on the wellhead value of gas. The Board calculated the wellhead value of gas using the market value of intrastate gas instead of the regulated interstate rate. This override award exceeded the FPC regulated price for San Juan gas of similar vintage. (17) The interest holders under other GLAs at issue demanded an override of 40 cents per Mcf. They claimed that the arbitrator’s award to Sun triggered the favored nations clauses in their own agreements. (18) No Defendant sought a -certificate from the FPC before asserting his right to collect a 40 cent per Mcf override. (19) In its rate cases El Paso had always treated the volumes of gas produced from the properties at issue as having been produced from its own properties and never as having been purchased under gas sales contracts. (20) GLA-125 interest holders began receiving overrides after exercising options to transfer producing wells to El Paso. The interest holders sought certificates of abandonment from the FPC, because prior to exercising those options they had been selling gas to El Paso under gas sales contracts. 14 (21) El Paso was a party in the Webb-Turner 15 litigation. When El Paso took over the GLA-125 leases, El Paso sought to include in its rates its actual costs for producing gas from the GLA-125 properties. El Paso’s production costs were higher than the area rates. The Staff of the FPC and the State of California claimed that El Paso was entitled only to area rates for the gas produced on GLA-125 properties. Their theory was that GLA-125 was actually a gas sales contract like Rayne Field 16 and that the transaction should be considered a sale of gas. (22) After litigation of the issue, the FPC concluded that El Paso could include its actual costs in its rate rather than being limited to the lower area rates because: “the . . . transactions [GLA-125] should not be considered equivalent to Rayne transactions because they arose under different circumstances. . . . ” 17 The opinion specifically found that GLA-125 differed from Rayne Field in that GLA-125 did not transfer proven and substantially developed acreage: “. . . there was a transfer of natural gas in the form of reserves to an interstate pipeline company for resale, but the transactions here represented a method evolved by El Paso and the Producers to cause the exploration for and the development of necessary gas supplies. By entering into the option agreements, El Paso was not buying developed reserves but arranging to have certain leases in the San Juan explored and developed by the producing interests, who were given an option to transfer the leases to El Paso provided the wells met initial productivity tests specified in the option agreements.” 18 No appeal was taken from the decision. (23) The GLAs in issue were not transfers of leases with proven reserves, since no reasonable estimate of recoverable reserves underlying the specific acreage conveyed could be made at the time its respective GLA was executed. Because insufficient *969 drilling had been done to prove up reserves in the specific acreage transferred, the GLAs in issue were not agreements to transfer definable volumes of reserves. Actual drilling was the only method of locating and defining recoverable gas saturations on specific acreage. 19 ' The GLAs themselves indicate that the parties negotiated for acreage containing unproven reserves. First, each GLA granted El Paso the option of returning drilling sites that proved to be uncommercial. Second, no GLA provided for an up-front payment based on an estimate of recoverable reserves. Even though El Paso was bargaining from a superior position, had the parties been bargaining for proven reserves, up-front payments and no option to return would have been included in the GLAs. (24) Because little if any actual drilling had been done on any acreage when its respective GLA was executed, each GLA was an agreement to transfer acreage which was not substantially developed. Where wells had been drilled, the number was exceptionally low compared to the number of available drilling sites. Wells in the Basin generally were incapable of recovering commercially significant amounts of gas. Not only were these wells generally of such low deliverability that a producer could not hope to recoup his drilling costs, but also a significant amount of drilling remained to be done to supply a pipeline with commercially significant volumes of gas. The GLAs themselves indicate that the parties negotiated for undeveloped acreage. El Paso undertook extensive burdensome development obligations. 20 El Paso’s offer of equivalent payments for gas acquired under purchase contracts as for overrides on gas produced under the GLAs was an inducement to the lessees to shift development of their acreage to the pipeline. Each transaction made sense economically, only if undeveloped acreage were transferred, because El Paso was, in effect, trading on its status as a utility regulated on the “cost of service” basis. (25) The GLAs were not the economic equivalents of gas sales contracts. The parties did not enter into the GLAs as a means of shifting payments as in Rayne Field. Rather, these agreements arose from the unique economic situation of the parties and reflected their efforts to structure the transactions so that El Paso would explore for and develop gas reserves in the Basin. The structuring of the economic risks and benefits between the parties more closely resembles the reallocation of risks and benefits in a farm-out than in a gas sales contract. The overall economic effect of the GLAs cannot be judged by merely looking to the ultimate purchaser of gas — the consumer — to see what price he pays. Were that reduction followed blindly, all gas transactions would be equivalent to gas sale contracts, since it is an irreducible economic fact that a consumer will pay for gas he uses. (26) Plaintiff-Intervenor Pacific Northwest Pipeline Corporation (PNW) is a regu *970 lated interstate pipeline. PNW is successor in interest to certain El Paso properties. 21 (27) Defendant Mobil Oil Corporation (Mobil) was originally a lessee of certain Basin properties located in Colorado. Mobil transferred these leases to PNW in an agreement denominated a Pacific Lease Agreement (PLA-13). PNW undertook a substantial drilling obligation when it signed PLA-13. At the time of transfer PLA-13 acreage was believed to be on the northernmost fringes of the Mesa Verde production area. (28) PLA-13 is almost identical to the GLAs in issue here. PLA-13 differs in one significant respect from the GLAs. After the expiration of the initial term PLA-13 provides the amount of override is to be determined by a mechanical formula rather than by agreement or by arbitration. (29) At the time PLA-13 was executed, no wells had been drilled on the acreage. A few wells had been drilled on adjacent acreage. (30) The acreage conveyed by PLA — 13 was not proven when PLA-13 was executed. (31) The acreage conveyed by PLA-13 was not substantially developed when PLA-13 was executed. (32) PLA-13 was not the equivalent of a gas sales contract. (33) The gas produced from each of the agreements in issue traveled in interstate commerce. CONCLUSIONS OP LAW 1. Because no agreement was the economic equivalent of a gas sale contract,, and because the leases transferred were neither proven nor substantially developed at the time of the execution of those agreements, each agreement at issue in this litigation [GLAs 47, 52, 60, 61, 63, 66, 76, 78, 106, 125, 129, 172, 348, 349, and PLA-13] is not a “sale in interstate commerce of natural gas for resale” within the meaning of Section 5 of the Natural Gas Act of 1938. 22 2. No Defendant in this litigation is a “natural gas company” within the meaning of the Natural Gas Act because that Defendant claims an interest under an agreement in issue. 23 3. The failure of each Defendant to seek certification from the FPC to collect overrides does not constitute a violation of the Natural Gas Act since no Defendant had a legal duty to seek such certification. 24 4. Because the fact that leases transferred pursuant to GLA-125 were neither proven nor substantially developed was an ultimate adjudicatory fact necessarily decided in the Webb-Turner proceeding when El Paso sought to include its actual costs in its rates, because that fact was actually litigated by El Paso against the contentions of the Staff of the Federal Power Commission and the State of California, and because the Webb-Turner decision is now final, under the principle of collateral estoppel, 25 El Paso is precluded from *971 relitigating the fact that the GLA-125 leases were neither proven nor substantially developed. 5. This Court lacks jurisdiction over the subject matter because there has been no violation of the Natural Gas Act. 26 6. This Court in its sound discretion declines to continue to exercise its pendent jurisdiction over the state contract claim still pending between PNW and Mobil. Although dismissal will cause some inconvenience to the litigants, to decide the claim would involve the Court in a determination of substantive Colorado law affecting real property located in Colorado. The interest that the State of Colorado has in deciding matters concerning real property located in Colorado, and the peculiar competency of Colorado State Courts to resolve such issues force this Court to conclude that to decide the issue would be an abuse of its discretion. 27 The Court therefore ORDERS: That this case be dismissed against all Defendants for want of jurisdiction. That the costs be shared by all Plaintiffs and Intervenors equally. 28 The Clerk is instructed to enter judgment. Footnotes [1] 15 U.S.C. § 717 et seq. [2] El Paso originally sought declaratory relief in the United States District Court for the District of Columbia. El Paso brought suit after Sun .was awarded a 40 cent per Mcf override. (See Finding of Fact 16, infra) As the other Defendants sought to increase the level of their overrides, (See Finding of Fact 17, infra) El Paso brought individual actions against each of these Defendants. The United States District Court for the District of Columbia consolidated all those individual cases. The consolidated case was transferred to the Western District of Texas under the provisions of 28 U.S.C. § 1406. [3] Contract analysis would reduce the case to the following proposition: Does El Paso bear the risk of the FPC determining that the level of overrides is unjust and unreasonable, or do the Defendants bear that risk? See Initial Decision on Disputed Issues (FPC Docket RP73-109, et at, opinion issued September 29, 1976) A determination that Defendants were “natural gas companies” would shift the risks of an adverse FPC determination to the Defendants. [4] 15 U.S.C. § 717u; see 15 U.S.C. §§ 717c(a), (c); 717a(6); 717(b). [5] Because the Barker Dome transaction (GLA-32) was negotiated before El Paso was certified, the history of the Barker Dome agreement is not analogous to the agreements here at issue. In any regulated industry, entry into the market through certification is probably the most critical step. The negotiations surrounding Barker Dome reflect El Paso’s efforts to enter the San Juan Basin. Once El Paso was *966 certified, it held a virtual monopsony in the Basin since Southern Union Gas Company, the only other pipeline in the Basin, served only intrastate markets which were already fully utilized. [6] Defendants in many instances are successors-in-interest to the original lessees who negotiated the GLAs. Because being a successor-in-interest is of no legal significance, the current interest holders are treated as having been the original lessees. [7] ' The Pictured Cliffs and the Mesa Verde were the formations most commonly transferred. GLAs 348 and 349 conveyed only interests in the Dakota formation because rights to the Pictured Cliffs and Mesa Verde in the same acreage had previously been conveyed by GLA-76. Certain agreements transferred fee leases instead of transferring productive horizons because the acreage was Indian tribal land which could not be transferred horizon by horizon. [8] In GLAs 125 and 129 the lessee developed the .properties and incidentally assumed the risks of dry holes. GLAs 125 and 129 provided the lessee with an option to transfer acreage to El Paso on a well by well basis. Both GLAs 125 and 129 had total production payments based on the estimated reserves of gas in place, and provided for the redetermination of reserves. (See Finding of Fact 20, et seq., infra). [9] GLAs 125 and 129 gave lessees options to transfer on a well by well basis. (See Finding of Fact 20, infra). [10] GLA 63 had no minimum take or pay provision; instead, GLA 63 provided for a ratable take of gas. [11] The Barker Dome Agreement (GLA-32) provided for an up-front payment. See United Gas Improvement Co. v. Continental Oil Co., 381 U.S. 392, 85 S.Ct. 1517, 14 L.Ed.2d 466 (1965); Federal Power Commission v. Pan American Petroleum Corp., 381 U.S. 762, 85 S.Ct. 1802, 14 L.Ed.2d 714 (1965); Continental Oil Co. v. Federal Power Commission, 370 F.2d 57 (5th Cir. 1966), cert. denied, 388 U.S. 910, 87 S.Ct. 2114, 18 L.Ed.2d 1349 (1967). [12] The productive area of each formation does not extend to its surface outcrop. [13] For a specific leasehold a producer recovers the costs of drilling, including the costs of unsuccessful wells, by selling gas. In view of the low average deliverability of successful wells, the risks of unsuccessful drilling, the low prices El Paso offered for gas and the absence of any other buyer, no producer had any reasonable assurance of drilling commercial wells in the San Juan Basin. El Paso, on the other hand, earned a rate of return on capital invested in successful wells. Since that capital account was depreciated on units of production, El Paso’s capital accounts remained higher the more slowly successful wells delivered gas. El Paso was also able to expense the costs of unsuccessful wells. El Paso was able to pass the risk of unsuccessful drilling on to its customers. “Under this method [cost of service], the natural gas in place and the properties and equipment utilized in producing it are included in the rate base, along with the transmission, compression, and other facilities employed in transporting and selling it to the customers, at the net investment which they represent, i. e. their original cost less the reserves that have been accrued to cover their depreciation and depletion. In addition to a rate of return thereon equal to the rate of return found reasonable for the pipeline operation overall, there are included in the recoverable costs of service, upon which the charges to jurisdictional customers are based, all operating expenses chargeable to production, including such uncapitalized exploratory and development outlays as delay rentals, geological surveys, and the expenses of drilling dry holes. Thus all the costs and risks incurred in the search for gas by a pipeline are shifted from (stockholders) to the customers of the pipeline. In addition, all expenses associated with the extraction of liquid hydrocarbons . . . are also included among the allowable operating expenses, but corresponding production credits are made of the revenue from the sale of such products. Under the rate-base approach allowances for taxes on the production property are made in accordance with the actual payments made thus transferring to the rate payer all the savings of federal income taxes permitted by statute to be enjoyed by gas producers through allowances made for depletion and intangible well drilling costs.” (Opinion 568, 42 FPC 738, 756 (1969) ). [14] Webb-Turner, Opinion 642, 49 FPC 17 (1973). [15] Id. [16] United Gas Improvement Co. v. Continental Oil Co., 381 U.S. 392, 85 S.Ct. 1517, 14 L.Ed.2d 466 (1965). [17] 49 FPC at 26. [18] Id. [19] When El Paso increased its transmission facilities, El Paso, its creditors and the FPC were relying on the conclusion of DeGloyer & McNaughton (D&M) that plenty of gas existed in the Blanco-Largo field. D&M’s analysis implied that over the entire field commercially recoverable accumulations of natural gas existed. The most that could be inferred from D&M’s analysis, however, was that over the entire field there would be an average rate of success in drilling for commercially recoverable accumulations of natural gas. The report did not show, nor could it be inferred from D&M’s analysis whether or not specific acreage would contain commercially recoverable reserves; i. e. proven reserves. The D&M report points out the qualitative difference in the risk of drilling undertaken by E1 Paso, apart from El Paso’s ability to pass that risk on (see note 13 supra) and that undertaken by any other producer. The more acreage El Paso developed in the Basin the closer it could come to D&M’s average recovery rate (assuming D&M to be correct). Any other producer had a higher risk than El Paso because he took the drilling risks on a limited amount of acreage, and was simply not in a position to spread his risks over the entire field to insure an average recovery rate. [20] In GLAs 125 and 129 the lessee undertook the risk of development. (See Finding of Fact 20, supra; note 8, supra). [21] See United States v. El Paso Natural Gas Co., 358 F.Supp. 820 (D.Colo.1972), aff’d, 410 U.S. 962, 93 S.Ct. 1440, 35 L.Ed.2d 697 (1973). [22] 15 U.S.C. § 717(b); United Gas Improvement Co. v. Continental Oil Co., 381 U.S. 392, 85 S.Ct. 1517, 14 L.Ed.2d 466 (1965); Federal Power Commission v. Pan American Petroleum Corp., 381 U.S. 762, 85 S.Ct. 1802, 14 L.Ed.2d 714 (1965); Federal Power Commission v. Panhandle Eastern Pipe Line Co., 337 U.S. 498, 69 S.Ct. 1251, 93 L.Ed. 1499 (1949); Continental Oil Co. v. Federal Power Commission, 370 F.2d 57 (5th Cir. 1966), cert. denied, 388 U.S. 910, 87 S.Ct. 2114, 18 L.Ed.2d 1349 (1967); Mobil Oil Corp. v. Federal Power Commission, 149 U.S.App.D.C. 310, 463 F.2d 256 (1971), cert. denied, 406 U.S. 976, 92 S.Ct. 2409, 32 L.Ed.2d 676 reh. denied, 409 U.S. 903, 93 S.Ct. 103, 34 L.Ed.2d 166 (1972). [23] 15 U.S.C. § 717a(6). [24] 15 U.S.C. § 717c(a), (c). [25] Blonder-Tongue Laboratories, Inc. v. University of Illinois Foundation, 402 U.S. 313, 91 S.Ct. 1434, 28 L.Ed.2d 788 (1971); Tampa Phosphate R. Co. v. Seaboard Coast Line R. Co., 418 F.2d 387 (5th Cir. 1969), cert. denied, 397 U.S. 910, 90 S.Ct. 907, 25 L.Ed.2d 90, reh. denied, 397 U.S. 1030, 90 S.Ct. 1256, 25 L.Ed.2d 543 (1970). [26] 15 U.S.C. § 717u. [27] See Moor v. County of Alameda, 411 U.S. 693, 710, 93 S.Ct. 1785, 36 L.Ed.2d 596 (1973). [28] 28 U.S.C. § 1919. The Court further finds that transcript was necessary for use during the trial of the case. The costs of the transcript are to be included in the costs under 28 U.S.C. § 1920(2).