CITIES SERVICE GAS CO. v. FEDERAL POWER COMMISSION et al. (STATE CORPORATION COMMISSION OF KANSAS et al., Interveners)
No. 2813
Circuit Court of Appeals, Tenth Circuit
April 30, 1946
Rehearing Denied July 5, 1946
155 F.2d 694
A witness for the shipper testified that the replacement value of the thirteen sheets of steel was $8,064.18. The shipper‘s witness testified that the replacement value represented the value of the steel plates at Seattle. No other evidence in the record exists as to the value of the steel lost overboard. The carrier urges that the measure of damages may not be based on the replacement cost of nondelivered cargo. In the absence of any contrary evidence, “the value at Seattle” may be taken as the market value. Furthermore, the amount of injury suffered is the sum in question and not necessarily the market value of the goods lost.22 The Supreme Court has said:
“The test of market value is * * * but a convenient means of getting at the loss suffered. It may be discarded and other more accurate means resorted to, if, for special reasons, it is not exact or otherwise not applicable.” 23
The judgment appealed from is affirmed.
Donald C. McCreery, of Denver, Colo. (Paul W. Lee, George H. Shaw, Wm. A. Bryans, III, and Charles J. Kelly, all of
Harry S. Littman, of Washington, D. C. (Charles V. Shannon and Stanley M. Morley, both of Washington, D. C., John Randolph, of Saint Joseph, Mo., William E. Kemp and Jerome M. Joffee, both of Kansas City, Mo., Louis E. Clevenger, of Topeka, Kan., and Floyd Green, of Oklahoma City, Okl., on the brief), for respondents.
Before PHILLIPS, HUXMAN and MURRAH, Circuit Judges.
MURRAH, Circuit Judge.
This appeal brings here for review under
Petitioner is a wholly owned subsidiary of the Empire Gas and Fuel Company, which is in turn controlled by the Cities Service Company. Organized February 1, 1922 as the Natural Gas Pipe Line Company, petitioner acquired the properties of a number of other producing and transportation companies; was reorganized in November 1926 under its present name, and acquired the properties of still other producing and transportation companies, all the latter of which were owned or controlled by its parent, the Cities Service Company. As a result of these and other transactions with affiliated companies, petitioner, at all times presently material, was one integrated natural gas system, devoted to the production, transportation and sale of natural gas for resale for ultimate public consumption, and direct sales to industrial customers. As such, it owned extensive proven and producing gas reserves in the Panhandle Field of Texas, the Hugoton Field in Kansas and Oklahoma, and numer
During the test year of 1941, petitioner sold for resale 61,425,000 M.c.f. of natural gas, for which it received $12,903,500, and sold direct 40,700,000 M.c.f. for $4,335,500. The petitioner produced from its own wells in the Panhandle of Texas, Kansas and Oklahoma, 43% of its total natural gas requirements, and the remainder was purchased in the states of Kansas and Oklahoma, for which it actually paid the total sum of $2,716,722, or an average of $.0458 per M.c.f.
In arriving at a rate base for the purpose of determining the reasonableness of petitioner‘s regulable interstate wholesale rates, the Commission adopted and used the prudent investment formula, or actual legitimate cost, less existing depreciation and depletion, plus working capital. After adjustments to the Company‘s plant account as of December 31, 19411 the Commission found from the evidence that the actual legitimate cost of all the properties used and useful in the production and transmission of all the natural gas sold by it to be $66,977,654. From this amount, it deducted $20,779,558 for existing depreciation, and $1,024,891 for depletion of reserves, added $1,576,357 to cover construction work in progress, and $1,818,194 as a reasonable allowance for working capital, thus arriving at “the reasonable rate base for Cities Service Gas Company as an assembled whole and a natural gas utility” in the sum of $48,567,756.2 The Commission allowed an annual rate of 6 1/2% on this rate base or a return of $3,156,904, which it found to be “fair and liberal.”
For the year 1941, petitioner‘s books showed operation, exploration and development cost in the sum of $10,625,724. Of this sum, the Commission disallowed $380,000 as excessive profits realized by one of petitioner‘s affiliates, Cities Service Oil Company, under a contract for the extraction of natural gasoline and other residuals, for the asserted reason that the affiliate‘s profits under the contract exceeded by that amount a fair return on the property devoted to the process. It also
In order to arrive at the cost of service for the jurisdictional sales, the Commission allocated the total cost of service between jurisdictional and non-jurisdictional sales, and by applying the so-called “demand and commodity” method, it found that $7,264,986 represented the total cost of service, including a fair return, for the jurisdictional sales, while $3,580,273 represented the cost of service for direct or non-jurisdictional sales. By subtracting the allocated cost of service for the jurisdictional sales from the gross revenue for such sales ($12,764,651), the Commission concluded that the petitioner‘s rates were excessive by the sum of $5,499,665. However, it made an additional allowance of $1,053,794 for cost of service for the petitioner‘s gas sales, subject to its jurisdiction, from a proposed transmission line connecting its properties in the Hugoton Field to its other marketing facilities, thus arriving at the ordered reduction in the wholesale rates.
The petition for rehearing contains thirty-three specifications of error, and they are brought forward in the petition for review under
Jurisdiction of the Commission and scope of review
It is of first importance to take account of the respective provinces assigned to the Commission and the courts on review in order that we may perform the functions assigned to us without trespass upon the administrative prerogatives. The primary aim of the
It hardly seems necessary or appropriate to reiterate what has already been so emphatically said concerning the “broad area of discretion” committed to the Commission in the exercise of its statutory jurisdiction, to determine just and rea-
Regulation of Producing and gathering of natural gas
Petitioner contends that in arriving at its rate order, the Commission exceeded its statutory authority by exercising regulatory jurisdiction over the production and gathering of natural gas.
It is true that the adopted rate base includes all of the production and gathering facilities of the petitioner, and it is also true that the
It is thus clear that under the prevailing view, the Commission did not exceed its jurisdiction by the inclusion of the production and gathering facilities in the rate base for purposes of determining just and reasonable rates for the transportation for resale of natural gas.
Rate Base
As we have seen, the Commission‘s adopted rate base for the purpose of calculating the allowable return is predicated solely upon actual legitimate cost of all properties devoted to the enterprise.5 All proffered evidence of fair value was rejected for the asserted reason that the actual cost was accurately ascertainable from the books and records of the Company; that reproduction cost was at best “synthetic” and not taken from the books, did not purport to represent cost of actual investment, therefore the consideration of fair value or reproduction cost was unnecessary. The petitioner argues that fair value is inherent in ratemaking as the end product of the process, and that evidence of it is certainly admissible and its rejection reversible error. In particular, petitioner complains not only of the Commission‘s inclusion of its leaseholds and natural gas rights in the rate base at their nominal cost to its predecessors before they were first devoted to public service, but also of its disallowance of certain items which it contends represents actual legitimate cost.
Petitioner owned 720,252 acres of proven leaseholds and natural gas rights, consisting of approximately 113,000 acres in the Panhandle Field of Texas, 180,000 acres in the Hugoton Field in Oklahoma, and approximately 425,000 acres located in other parts of Oklahoma and Texas. As of December 31, 1941, these producing properties were carried on petitioner‘s books at a capital cost of $2,207,758, and petitioner contends that the actual legitimate cost of these leases as of the above date was $2,174,122. The Commission included all these leaseholds in the rate base as used and useful in rendering gas service, but found that only $1,644,349 of the amount claimed should be included in the rate base as actual cost of the leasehold. The balance of $529,733, representing past operating expenses, cost of abandoned leases, and capitalized interest thereon, was disallowed for the stated reason that since these expenses had been treated as operating expenses by the affiliated company which had acquired them, they could not be brought forward as capital cost in the rate base.
Most of the leaseholds and natural gas rights were originally acquired by petitioner‘s affiliates (especially those in the Texas Panhandle), while exploring for oil, and at a time when gas was considered a nuisance, and enormous quantities were being wasted because there was no marketable use for it. Consequently, large blocks of acreage (including 63,000 acres in one block in the Texas Panhandle), were acquired at a nominal cost, and in consideration of covenants to develop and pay royalties. When in 1935 these leases were sold and transferred to petitioner as a reservoir for markets which had been tapped in metropolitan areas, by the construction of large transmission lines from the producing area, they had of course become exceedingly valuable to the enterprise.
The Commission rejected proffered evidence of the fair value of these leaseholds as an essential part of the natural gas utility, on the grounds that it was wholly “immaterial and irrelevant” to the determination of just and reasonable rates, based upon actual investment of the properties devoted to the regulated business. The Texas Panhandle leases, on which was located 98 producing wells, and which in 1941 supplied 43% of the gas sold by petitioner, were included in the rate base at an actual legitimate cost of $392,610.84 (including top ground equipment). These leases were transferred by the Empire Gas and Fuel Company to the Cities Service Pipe Line Company in 1928, and in 1935
In substance, the petitioner argues that although actual legitimate cost may be a permissible rate-making formula under the
There are some who hold to the principle that “realization from the risk of an investment in a speculative field, such as natural gas utilities, should be reflected in the present fair value.” See Mr. Justice Reed dissenting in the Hope Gas case, supra, 320 U.S. at page 622, 64 S.Ct at page 297, 88 L.Ed. 333. But if, under the prevailing view, the economic merits of a rate base is of no judicial concern (see special concurring opinion in Federal Power Commission v. Natural Gas Pipeline Co., supra, 315 U.S. at page 606, 62 S.Ct. at page 752, 86 L.Ed. 1037, and concurring opinion in Driscoll v. Edison Light & Power Co., 307 U.S. 104, 122, 59 S.Ct. 715, 83 L.Ed. 1134), we have not the right to intercede unless it is conclusively shown that failure to give consideration to the fair value of properties, including the valuable leasehold estates, will prevent the company from operating successfully as a public utility. It is said that “rates cannot be made to depend upon ‘fair value’ when the value of the going enterprise depends on earnings under whatever rates may be anticipated.” Hope Natural Gas Co. case, supra, 320 U.S. at page 601, 64 S.Ct. at page 287, 88 L.Ed. 333. In other words, fair value is the end product and not the means of the rate-making process.6 Fair value is no longer deemed an essential ingredient of an economic rate base for rate-making purposes. Federal Power Commission v. Natural Gas Pipeline Co., supra; Hope Natural Gas Co. case, supra; Colorado Interstate Gas Co. v. Federal Power Commission, 324 U.S. 581, 65 S.Ct. 829, 89 L.Ed. 1206.
In the Colorado Interstate Gas Company case, vast acres of gas producing properties of the Canadian Gas Company, located in the same Texas Panhandle Field, were put in the rate base of an integrated gas utility at their nominal cost to the utility‘s predecessors. We approved the action of the Commission in disallowing the difference between the actual original cost of the leases, and the sale price of the same to the utility first devoting them to public use, on the grounds that the difference between the actual cost and their cash sale price to an affiliated company was a “synthetic inflation“, which had no place in the field of rate making. In support of certiorari, the Canadian River Gas Company, as the owner of the properties devoted to the integrated enterprise, strenuously complained of the refusal of the Commission to include the producing properties in the rate base at the cash sale price paid by the company first devoting them to public use. That point was taken on certiorari, 323 U.S. 807, 65 S.Ct. 427, 89 L.Ed. 644, and specifically treated on appeal. 324 U.S. at page 604, 65 S.Ct. at page 840, 841, 89 L.Ed. 1206. The majority of the court could not “say as a matter of law that the Commission erred in including the production properties in the rate base at actual legitimate cost“. 320 U.S. at page 605, 65 S.Ct. at page 841, 89 L.Ed. 1206. But see Mr. Justice Jackson concurring, 320 U.S. at page 610, 65 S.Ct. at page 843, 89 L.Ed. 1206, and dissent of the late Mr. Chief Justice Stone, 320 U.S. at page 616, 65 S.Ct. at page 845, 89 L.Ed. 1206. A like contention was made and rejected in Panhandle Eastern Pipe Line Co. v. Federal Power Commission, 324 U.S. 635, 648, 65 S.Ct. 821, 89 L.Ed. 1241.
In view of these pronouncements, we regard the question no longer a debat-
The exclusion of $529,723, representing past operating expenses, cost of abandoned leases, and capitalized interest, from the rate base, is fully supported by the Hope Gas case, wherein the majority of the Court expressed its views in the words of the Commission, “No greater injustice to consumers could be done than to allow items as operating expenses and at a later date include them in the rate base, thereby placing multiple charges upon the consumers.” 320 U.S. at page 599, 64 S.Ct. at page 286, 88 L.Ed. 333.
Existing depreciation and depletion
As we have seen, the Commission deducted from the actual legitimate cost of the properties $20,779,558 for accrued and existing depreciation, and $1,024,891 for depletion of the producing properties. In so doing, it followed the recommendations of its staff, which computed both the annual and accrued depreciation on the average ascertained service life of the various classes of property included in the rate base. The accrued depreciation was calculated as the sum of the annual depreciation expense from the beginning of the property, less total net cost of the property retired. This formula was used and approved both in the Hope Gas case and the Colorado Interstate Gas case, and has been acclaimed by the American Public Utility Bureau as the most practical and reasonable method of determining accrued depreciation under the actual legitimate cost formula of rate-making.7
We do not understand that the petitioner finds fault with the so-called “straight line economic life” method of determining annual and accrued depreciation, but it does contend that depreciation is a fact, not a mere book entry or accounting concept, and that in arriving at its depreciation reserve, the staff witness forsook actualities for pure theory.
The staff witness who, for the guidance of the Commission, prepared an exhibit setting forth the estimated average service life of all the depreciable properties of the petitioner as of December 31, 1941, and the scope of his study, method used, source of material, and descriptions of field inspections, testified that in accordance with the Commission‘s uniform system of accounts, he took into consideration “wear and tear, decay, action of the elements, inadequacy, obsolescence, changes in the art, changes in demand, and requirements of public authorities“; that although the recommendations are not based on observed depreciation or percent condition, he did make a field inspection of the company‘s properties for the purpose of observing physical deterioration, measure of protection afforded by maintenance, actual existence of items of property, and other conditions which would affect his judgment of the service life of the property. The witness further testified that he studied the records of the petitioner and its predecessors, and considered the history of development of these companies, obtained dates of installation of the property, and where the property was reclaimed, the information concerning the “reclaim“. He made a detailed study of 2,020 pipe inspection reports which the Company had made in the fall of 1940. He testified that his estimates of the service life of each class of property, and the annual rate of depreciation assigned thereto, coincided with those used by the Company in setting up its annual depreciation on its books. The pipe used in the transmission lines represents approximately 70% of the petitioner‘s investment, and the petitioner complains of the witness’ failure to make any actual inspection of this pipe for the purpose of observing the deterioration in use. The witness counters that he was prevented from doing so by the refusal of petitioner to dig the “bell holes“, and that instead his inspection of the retired pipe, and his examination of the Company‘s
From the evidence before it, the Commission found that the petitioner had more than recovered its depreciation reserve through annual charges to depreciation expense prior to December 31, 1941. The petitioner offered no evidence concerning the economic service life or depreciation rates, and as against its objections that the staff witness made no examination of much of the property, including the pipe lines, to determine actual wear and tear or deterioration, and failed to give consideration to the actual condition of the property involved, we must conclude that the evidence is sufficient to support the Commission‘s ultimate findings and conclusions.
Natural gasoline operations of the Cities Service Oil Company
Under a contract with the petitioner, the Cities Service Oil Company, an affiliate, extracts natural gasoline, butane, propane and other residuals from the natural gas in petitioner‘s pipe lines, and for that purpose owns and operates processing plants at Tallant, Oklahoma, and Wichita, Kansas. For the products thus extracted, the Oil Company pays to petitioner “7¢ per M.c.f. of 1,100 BTU, equivalent gas for the loss in the heat value of the gas resulting from the extraction“. The Commission found that since the extraction process rendered the natural gas more readily marketable and transportable, but reduced its heat content and consumed a certain volume of it, and was profitable, the gas customers were entitled to a “fair proportion of the net earnings derived from the processing operation“. Following what it considered a comparable situation in the Hope Gas Company case, the Commission credited the petitioner‘s operating expense with the profits of the Oil Company under its contract in excess of the cost of processing, plus a 6 1/2% return on the ascertained actual cost of the properties devoted to the process, less depreciation, plus working capital. Thus, it found that the average excess profits for the years 1939 to 1942 was $380,000, and that this amount constituted a fair guide for the future.
While conceding the Commission‘s authority to scrutinize the contract between the two affiliates for the purpose of determining its reasonableness, petitioner insists that the Commission was unauthorized to segregate these two particular plants from the Oil Company‘s other properties, and to treat them as if they belonged to the petitioner, thereby ignoring the separate corporate entity of the two companies, and denying them the right to contract with respect to a function which was not in fact a part of the petitioner‘s business as a public utility. Petitioner challenges the authority of the Commission to fix a return of 6 1/2% on properties not within its jurisdiction, and argues that in any event, it failed to take into consideration the character and risk of the business involved.
In the Hope Natural Gas Company case, 4 Cir., 134 F.2d 287, 307, the court sustained the procedure employed by the Commission, on the theory that the extraction process in that case was “in reality a part of Hope‘s natural gas business, although carried on by an affiliate.” If the extraction process is in reality an essential part of the business of transporting and marketing the natural gas, the Commission was justified in ignoring the contract between the two affiliates for the purpose of determining just and reasonable rates. Otherwise, a regulated gas utility would be permitted to syphon off its profits to affiliates through the guise of contracts for the performance of essential functions of the integrated business.
In our case, a staff witness testified to the effect that the extraction process was a necessary function of the business of transporting and delivering natural gas to market by means of a pipe line system, and that such process was essential to the transportation and sale of the natural gas. As against countervailing evidence, the Commission chose to adopt the views of its staff witness, and we are unable to say as a matter of law that the Commission‘s findings on this technical point are legally erroneous.
The Commission refused to allow as a part of the deductible cost of service or expense for the year 1941 Federal income tax paid by the Company in the sum of $1,882,148.26. This allowance is based on the thesis that if the rates and charges on the regulable sales had not exceeded an amount sufficient to return 6 1/2% on the adopted rate base, the tax liability would not have been incurred, consequently it cannot be allowed as an expense. In other words, the petitioner may not charge as an expense that which it cannot lawfully earn. The effect of the disallowance was to assign all Federal income tax liability for the year 1941 to non-regulable sales, and the petitioner argues that to saddle this liability on the non-jurisdictional earnings amounts to a regulation and substantial curtailment of the non-regulable earnings by setting up a “tax priority” against such earnings.
If, as the Commission found, there would be no Federal income tax liability under the 1941 rates on a permissible return from the adopted rate base, the Commission was certainly justified in refusing to allow the item as an expense, because if it had permitted the item to remain in the total cost of service before allocation, it would have been justified in allocating the entire amount to the jurisdictional sales. The petitioner challenges the Commission‘s computations, which show that the permissible earnings would not result in tax liability, but offers no affirmative computations tending to show its tax liability upon the permissible rate. The Commission did no more than allocate to the non-jurisdictional sales the cost of earnings which were solely attributable to it. We must therefore assume on this record that the Commission‘s statement in that regard is correct, and that it was legally justified in eliminating the Federal tax liability as an item of cost.
Allocation of cost of service
Petitioner complains of the Commission‘s failure to separate the physical properties of petitioner devoted to interstate transportation and sale for resale, from the properties and facilities devoted to the transportation and direct sale of natural gas, over which it admittedly has no jurisdiction. The Commission recognized that the Company‘s facilities and operations were devoted in part to natural gas service which was not subject to its jurisdiction, and that this service consisted principally of gas sales made directly to large industrial consumers. Accordingly, it recognized the necessity of effecting a separation of the jurisdictional from the non-jurisdictional. This it did by adopting its staff‘s proposed method of dividing the total cost of allowable expenses and return into two categories, (1) costs related to production and purchase of gas, and (2) those related to transportation and delivery. Costs predominately related to production and purchase were classified as commodity or variable costs (sometimes called volumetric), while those relating to transportation and delivery were classified as “commodity, demand and customers cost“. In general, costs which varied with the volume of gas delivered were classified as variable or commodity costs. Costs which did not vary with the volume of gas sales, but which were predominately fixed, were classified as demand or capacity costs; those incurred predominately in proportion to the number of meters in service were classified as customer costs. The total commodity costs thus determined were allocated to regulable and non-regulable sales in a ratio that the customers’ annual consumption bore to the total M.c.f. sales from the system in the year 1941. The demand costs were allocated between the regulable and non-regulable sales in the ratio that the customers’ consumption on the peak day (January 3, 1942) bore to the total system M.c.f. sales on that day. The petitioner contends that the Commission‘s allocation of the cost of service as a method of effecting a separation of the regulable from the non-regulable is erroneous in both principle and application.
The Commission used the allocation of cost of service as “the most practical and businesslike method” of effecting a separation of the regulated and non-regulated business in the Colorado Interstate case under circumstances not unlike the present, and we approved the use of
In making the allocation of cost of service, the Commission followed the recommendations of its staff, who approached the problem as an engineering and economic one, and who gave a detailed analysis of the method of allocation for the record. One member of the staff described the problem of allocation of joint costs as one “that engineers and economists have been studying for many years, not only in the utility industry, but in all other industries in which joint costs are present“, and observed that allocations “require the exercise of informed judgment and use of procedures which appear to be reasonable in view of the particular operations and circumstances of the system in each case“.
It would serve no useful purpose for us to further detail or itemize the cost allocations. If some of the specific allocations appear to be illogical and unfair, they necessarily pose technological problems of accounting and finance upon which the administrative judgment has been declared virtually supreme. We shall not criticize that which we are powerless to correct. If allocation of cost of service is a fundamentally correct and permissible method of effecting a separation of the regulable from the non-regulable sales, we cannot say on this record that the application of the formula is so wholly unrelated to the facts as to produce an illegal or reversible result.
The judgment is affirmed.
PHILLIPS, Circuit Judge (dissenting).
My associates are of the opinion that the questions here presented are foreclosed by recent decisions of the Supreme Court. Were I certain of the correctness of that conclusion, my task would be simple. It is my view, however, that certain of the important questions here presented are left at large by the opinions of the Supreme Court in the gas rate cases, and I am, therefore, impelled to state my views.
It has been authoritatively determined by the Supreme Court that, in determining the value of property included in the rate base, the Commission is not bound to the use of any single formula or combination of formulae;1 and that if the Commission conforms to the requirement of the statute fixing its authority and proceeds, after notice, and accords fair hearing and fixes “rates which enable the company to operate successfully, to maintain its financial integrity, to attract capital, and to compensate its investors for the risks assumed” such rates cannot be condemned as invalid, even though they produce only a meager
I.
The Commission‘s Jurisdiction.
Section 1(b) of the
The “shall not” provision of this Act expressly withholds from the Commission jurisdiction over direct sales of natural gas, over local distribution thereof, over facilities used for local distribution, and over production or gathering of natural gas. It confines the Commission‘s jurisdiction expressly and solely to transportation of natural gas in interstate commerce, and to the sale in interstate commerce of natural gas for resale for ultimate public consumption. See the construction of analogous provisions of the
II.
The Rate Base.
The Commission adopted and applied a rate base purporting to embrace all the property of the Cities Service Gas Company.4 It found that $66,977,654 was the actual legitimate cost of the property in service on December 31, 1941. It deducted therefrom $21,804,449 for accrued depreciation and depletion. It added $1,576,357 for construction work in progress and $1,818,194 for working capital, thereby arriving at a rate base of $48,567,756. From the actual earnings of the Company in the test year, it subtracted an amount equal to 6 1/2 per cent of the rate base, thereby arriving at what it found to be excess earnings before allocation. It then allocated the properties and earnings as between the jurisdictional, or sales for resale, and the nonjurisdictional, or direct sales, by a so-called cost of service method apportioning approximately 70 per cent to sales for resale, and 30 per cent to direct sales. It thereby found that the earnings from sales for resale were excessive to the extent of $5,499,665.
It found the estimated cost of the proposed Hugoton Pipeline to be $15,000,000. It determined that 6 1/2 per cent of that amount, or $975,000, was a fair return thereon and that 3 1/2 per cent of $15,000,000, or $525,000, was a fair allowance for depreciation. Of the aggregate of the two latter amounts, it apportioned $1,053,794 to jurisdictional sales and $446,206 to nonjurisdictional sales. It allowed $1,053,794 as a tentative additional allowance for the cost of procuring gas. It deducted that amount from $5,499,665, and thereby arrived at $4,445,871 as the amount of the rate reduction.
III.
The Treatment of Petitioner‘s Leaseholds and Natural Gas Rights in the Rate Base.
Petitioner owns gas leases in the Texas Panhandle field, fields in Kansas and Oklahoma, and in the Hugoton field. The Commission included in the rate base what it found to be the legitimate cost to petitioner‘s predecessors of such leases, administrative cost of acquisition, and cost of physical structures. At the time such properties were devoted to public use the leases, because of development, had greatly enhanced in value.
Where no bonus or consideration was paid for a lease, the Commission allowed no cost in the rate base for the lease itself. For example, 68,086 acres of leases in the Panhandle field, constituting one of the most valuable proven gas reserves in
For 424,969 acres in the Oklahoma and Kansas fields, exclusive of the Hugoton field, the Commission allowed an acquisition cost of $545,374.18, which amount included bonuses where paid and a small amount expended for title papers and title examinations.
For 182,182 acres in the Hugoton field, the Commission allowed $542,501, which amount included bonuses paid and a small amount expended for title papers and title examinations.
The aggregate of the foregoing amounts, after deducting depletion, was included in the rate base as the adjusted cost of the leases.
Thus, the allowances in the Oklahoma and Kansas fields were approximately 11.4 cents per M.c.f. of gas reserves, whereas, the allowances in the Panhandle field and the Hugoton field were a nominal fraction of a mill per M.c.f. of gas reserves.
The Commission‘s treatment of gas reserves more graphically appears from the tabulation set forth in the margin.6
Ordinarily, the owner of land in an unproven area cannot risk the cost of exploration for oil and gas. It is more desirable for the ordinary landowner to lease his land on a royalty basis. Exploration in unproven areas involves the cost of geological and geophysical investigation, drilling costs, and, if oil or gas is found in paying quantities, the incidental costs
While the accuracy of geological and geophysical reports through the adaptation and use of the seismograph and other scientific instruments has been greatly improved, whether oil or gas will or will not be found in paying quantities can only be determined through drilling. Not infrequently, oil or gas is discovered by an adventurous driller on structures where the report of the geologist is unfavorable, and frequently an area, as to which the report from the geologist is very favorable, is found, on drilling, to be barren of oil or gas. It follows that one who expends large sums for investigation and drilling in unproven areas assumes the risk of losing his entire outlay in the venture.
Under the test laid down in Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 605, 64 S.Ct. 281, 88 L.Ed. 333, with respect to the end result theory, the return must compensate the investor, among other things, for the risk assumed, and enable the concern whose rates are fixed to attract capital.
Does a rate base on the nominal consideration paid for a lease in an unproven area compensate for the risk assumed by the lessee who expends large sums for investigation and for drilling, knowing the entire expenditure may be lost?
From time to time, petitioner, as it exhausts its present gas reserves, either will have to acquire additional reserves through acquisition and development of leases in unproven areas, or will have to abandon the production end of its business and buy gas from other producers. Can it hope to attract capital for acquisition of such new reserves when its earnings are based on the nominal cost of new leases, and when such new leases, although gas is discovered in paying quantities, will go into the rate base at the nominal cost, and no consideration will be given to their greatly enhanced value through development, nor to the risks assumed in such development?
In his concurring opinion in Colorado Interstate Gas Co. v. Federal Power Commission, 324 U.S. 581, 610, 65 S.Ct. 829, 843, 89 L.Ed. 1206, Mr. Justice Jackson said that the rate base method adopted produced “delirious results.” He further said: “These cases furnish another example of the capricious results of the rate-base method in this kind of case. The Commission has put five of the most important leaseholds, containing approximately 47,000 acres, in the rate base at $4,244.24, something under 10 cents per acre. Three such leases are put in the rate base at zero. This is because original cost was used, and these were bought before discovery of gas thereon. The Company which took the high risk of wildcat exploration is thus allowed a return of 6 1/2 per cent on nothing for the three leases and a return of less than $300 a year on the others. Their present market value is shown by testimony to be over 3 million dollars.”
While the question under consideration was raised in the Colorado Interstate Gas Co. case, supra, it was not directly passed on by this court, and was not within the scope of the review granted by the Supreme Court. In the opinion, 324 U.S. at page 605, 65 S.Ct. at page 289, 89 L.Ed. 1206, it said: “* * * we cannot say as a matter of law that the Commission erred in including the production properties in the rate base at actual legitimate cost. That could be determined only on consideration of the end result of the rate order, a question not here under the limited review granted the case.”
It seems to me that on a consideration of the end result, the rates fixed, for the reasons indicated, are unjust and unreasonable.
Section 6 of the
Here, it seems to me, nominal cost of leases is an arbitrary and unreasonable criterion, and that it was necessary for the Commission, for rate-making purposes, to ascertain other facts bearing on the determination of the fair value of the property included in the rate base.
IV.
Regulation of Production and Gathering Facilities.
Section 1(b) of the
In Colorado Interstate Gas Co. v. Federal Power Commission, 324 U.S. 581, at page 616, 65 S.Ct. 829, at page 845, 89 L.Ed. 1206, the late Chief Justice Stone, in his dissenting opinion, in which three of the Associate Justices joined, said: “* * * It [the Commission] valued the wells and gathering facilities at their prudent investment cost of many years ago, a valuation drastically less than their present market value. It then restricted petitioner‘s return to 6 1/2% of the rate base, including the wells and production facilities, constituting approximately two-thirds of the total rate base. It thus subjected petitioner‘s production and gathering property to the same regulation as that which the statute imposes upon petitioner‘s property used and useful in the interstate transportation and sale of gas for resale. This, we think, the Natural Gas Act in plain terms prohibits.”
Here, the Commission included all the gas reserves and all the gathering and production facilities in the rate base and fixed the return that might be earned thereon through direct sales. It thus regulated the return, through direct sales of gas, from leases and gathering and production facilities. I do not think the Congress intended to subject such properties to that sort of regulation. It would be a work of supererogation for me to undertake to add to the reasons so ably expressed by the late Chief Justice for his conclusion.
Is the question still open? In the Hope case, the question was not passed upon by the Supreme Court, United States Court of Appeals, or the Commission.9 The only issue presented related wholly and specifically to constructed physical facilities.
It is true that Mr. Justice Jackson concurred in the Colorado Interstate Gas Company case, but he reiterated his views expressed in the Hope case, and again severely criticized the methods used by the Commission, and based his concurrence with respect to the question here under consideration on the ground that the Commission was “free to take evidence as to conditions and events quite beyond its regulatory jurisdiction where they are thought to affect the cost of that whose price it is directed to determine.”
But it seems to me that the Commission did more. It is true that its final action was a rate order. However, the effect of such order was to regulate the return from the gas reserves and production and gathering facilities of petitioner from direct sales, on the basis of what it found to be the legitimate cost of such properties, and thus to exercise its rate-making jurisdiction over such properties. I have no quarrel with my associates for feeling that they are bound by the decision in the Colorado Interstate Gas Company case, but feel that the question is enough at large that it is not inappropriate for me to express my views.
V.
Excess Profits from Natural Gasoline Operations.
Petitioner and Cities Service Oil Company10 are subsidiaries of Empire Gas & Fuel Company. The Oil Company extracts gasoline, butane, and propane from part of the natural gas produced by petitioner. While this operation is profitable and ren-
The Commission determined the Oil Company‘s net investment in property devoted to the extraction of residuals from petitioner‘s gas and allowed a rate of return thereon, after providing for operating expenses, depreciation, and taxes, of 6 1/2 per cent. It concluded that the excess of the revenues received by the Oil Company, thus computed, represented excess profits, which should be credited to the natural gas operations of the petitioner. It thus regulated the rate of return received by the petitioner from direct sales of residuals extracted from the natural gas produced by petitioner and regulated the earnings of the Oil Company, an affiliate of petitioner.
Since the contract between petitioner and the Oil Company was between affiliated corporations, the Commission had the right to inquire into and scrutinize the fairness of the contract price and, if the price paid by the Oil Company was not fair and reasonable, to fix a reasonable price for the residuals sold to its affiliate. There are many contracts entered into at arm‘s length between producers of natural gas and extractors of residuals in the Panhandle field, and there would have been no difficulty in determining the reasonable market value of such residuals.11 But that the Commission did not do. In substance and effect, it undertook to regulate the charges the petitioner should make for the direct sales of its residuals on the basis of a fair return on the properties of the Oil Company, matters which were clearly not within the regulatory jurisdiction of the Commission.
VI.
Federal Income Taxes.
The Commission, in arriving at the amount of the rate production with respect to indirect sales, made no allowance for federal income taxes. It assigned all of such taxes to the earnings from direct sales. The Commission undertakes to justify its action on the theory that if all of petitioner‘s rates were subject to regulation, and petitioner had been limited to an overall fair return of 6 1/2 per cent, it would not have paid any federal income taxes. I am unable to determine from this record any basis for that conclusion. On its face, it would seem that a return which would not result in net earnings subject to federal income taxes is unreasonably low. Petitioner‘s single system serves both direct sale purchasers and purchasers who resell for ultimate public consumption. The unregulated direct sales business in general has a higher load factor than the regulated sales for resale business, and the combination of the two types of business works to the advantage of both classes of purchasers. Moreover, federal income taxes are levied upon the petitioner‘s business as a single operating unit. For all other purposes than federal income taxes, the Commission treated the petitioner, its property, its revenues, its expenses, its return, jurisdictional and nonjurisdictional, as unitary. But, for the specific purpose of tax computation, the nonjurisdictional earnings in excess of 6 1/2 per cent are saddled with all federal income taxes. It seems to me, therefore, that there should have been a reasonable allocation of federal income taxes between jurisdictional and nonjurisdictional earnings.
I think the order of the Commission should be set aside.
Notes
| Natural gas rights and leaseholds | $ 1,644,349 |
| Storage gas rights and leaseholds | 346,931 |
| Transmission and gathering lines, compressor stations, gas wells and all other property in service | 64,986,374 |
| Total actual legitimate cost | 66,977,654 |
| Less existing depreciation and depletion | 21,804,449 |
| Total investment in plant in service | 45,173,205 |
| Construction work in progress | 1,576,357 |
| Working capital | 1,818,194 |
| Rate Base | 48,567,756 |
| Operating expenses | $ 4,666,232 |
| Annual depreciation | 1,709,060 |
| Annual depletion | 70,871 |
| Taxes | 1,068,535 |
| Exploration and development costs | 295,439 |
| Total | $ 7,810,137 |
TEXAS PANHANDLE FIELD
| Acres | Per cent of total acreage | Cost allowed in rate base | Gas reserves 12/31/41 M.c.f. | Production 1941 M.c.f. |
| 68,086 | 66.67 | zero* | 1,089,383,786 | |
| 34,041 | 33.33 | $ 554,697.08 | 544,679,135 | |
| 10,975 | (non-productive) | 0 | 0 | |
| * Allowance for title papers and title examination 1,776.74 | ||||
| TOTAL 113,102 | $ 556,473.82 | 1,634,062,921 | 42,122,613 or 97.83% of petitioner‘s total production | |
OKLAHOMA AND KANSAS FIELDS
(exclusive of the Hugoton Field)
424,969 acres | $ 545,374.18 | 4,794,964 M.c.f. | 1,029,157 M.c.f.
HUGOTON FIELD
182,182 acres | $ 542,501.00 | 1,821,820,000 M.c.f. | (not in production in 1941)
TOTAL 720,253 | $1,644,349.00