Colorado Interstate Gas Co. v. Federal Power Commission , 65 S. Ct. 829 ( 1945 )

Mr. Justice Douglas

delivered the opinion of the Court.

The Federal Power Commission after an investigation and hearing entered orders under § 5 of the Natural Gas Act of 1938 (52 Stat. 823, 15 U. S. C. § 717d) finding the interstate wholesale rates of petitioners to be excessive by specified amounts per year and requiring petitioners to reduce the rates accordingly. 43 P. U. R. (N. S.) 205. The Circuit Court of Appeals for the Tenth Circuit affirmed the Commission’s orders. 142 F. 2d 943. The cases are here on petitions for certiorari which we granted, limited to the few questions to which we will presently advert.

Petitioners (to whom we will refer as Canadian and as Colorado Interstate) had their origin in an agreement made in 1927 between Southwestern Development Co. (Southwestern), Standard Oil Co. (N. J.) (Standard) and Cities Service Co. (Cities Service). It was the purpose of the agreement to bring natural gas from the Panhandle field in Texas to the Colorado markets, including Denver and Pueblo. Southwestern agreed to transfer through a wholly owned subsidiary, Amarillo Oil Co. (Amarillo), certain gas leaseholds and producing properties to a new subsidiary (Canadian) which it would organize for that purpose. Standard agreed to form a new corporation (Colorado Interstate) and to finance its construction of pipeline facilities which would connect with Canadian’s facilities and transport gas from those points in the Panhandle field to the Colorado markets. Cities Service agreed to use its best efforts to obtain franchises through its subsidiaries under which the natural gas could be distributed in certain cities in Colorado including Denver and Pueblo. The gas was to be sold to Colorado Interstate by Canadian at cost (as defined in the contract) for at least 20 years from 1928; We will return to other details of this tripartite agreement and of the organization and financing of Canadian and Colorado Interstate. It is sufficient here to say that the companies were incorporated, the pipeline was built, and the business put into operation. Although Canadian and Colorado Interstate are separate companies, the Commission found that their properties have been operated as a single enterprise.

Canadian produces from its own properties all the gas which it sells. It has about 300,000 acres of natural gas leaseholds and on December 31, 1939, was operating 94 wells. Its gathering system consists of approximately 144 miles of pipe. It owns and operates a transmission line which connects with its gathering system in the Panhandle field and ends about 85 miles distant at a point near Clayton, New Mexico. Canadian sells some of its gas at the wellhead and along the Texas portion of its transmission line for consumption in Texas. It also sells gas for resale in Clayton, New Mexico. But the chief portion of the gas in its transmission line is sold at that point to Colorado Interstate. The pipeline of Colorado Interstate extends to Denver. It sells the gas to various distributing companies for resale by them in Colorado and in a few points in Wyoming.¹ Colorado Interstate also sells gas from this pipeline direct to industrial customers in Colorado for their own use.

It is thus apparent that the pipeline from Texas to Colorado serves three different uses: (a) intrastate transportation and sale in Texas; (b) interstate transportation and sale to industrial customers; and (c) interstate transportation to distributing companies for resale. Only some of those activities are subject to the jurisdiction of the Commission. For § 1 (b) of the Act provides:

“The provisions of this chapter shall apply to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate public consumption for domestic, commercial, industrial, or any other use, and to natural-gas companies engaged in such transportation or sale, but shall not apply to any other transportation or sale of natural gas or to the local distribution of natural gas or to the facilities used for such distribution or to the production or gathering of natural gas.”

It is around the meaning and implications of that provision that most of the present controversy turns.

Allocation of Cost of Service. The questions raised by Colorado Interstate and some of those raised by Canadian relate to the failure of the Commission (1) to separate the physical property used in common in the intrastate and interstate business; (2) to separate that used in common in the sales of gas to industrial consumers and the sales of gas for resale; and (3) to separate the property used exclusively in intrastate business or exclusively for industrial sales. The Commission thought it unnecessary to make such a separation of the properties. It noted that nowhere in the evidence presented by petitioners was there “a complete presentation of the entire operations of the company broken down between jurisdictional and non-jurisdictional operations.” 43 P. U. R. (N. S.), p. 232. And it concluded, “All that can be accomplished by an allocation of physical properties can be attained by allocating costs including the return. The latter method is by far the most practical and businesslike.” Id., p. 232. The Commission adopted the so-called “demand and commodity” method for allocating costs. Cf. Arkansas Louisiana Gas Co. v. Texarkana, 96 F. 2d 179, 185. It took the costs and divided them into three classes— volumetric, capacity, distribution.² Costs relating to the production system were treated as volumetric.³ These included rate of return and depreciation and depletion on leases and wells. These volumetric costs were allocated to the customers in proportion to the number of Mcf’s delivered to each customer in 1939. The larger share of the transmission costs of the Denver pipeline were classified as capacity costs. Supplies and expenses of compressing systems, maintenance of compressing system equipment and accruals for its depreciation were classed as volumetric. And one-half of the return and income taxes on the Denver pipeline and one-half of operating labor on the compressing system were classed as volumetric, the other half being classed as capacity. Capacity costs were allocated to the customers in the ratio that the Mcf sales to each customer on the system peak day of February 9, 1939, bore to the total sales to all customers on that day. Distribution costs were composed in part of depreciation, taxes, and return on investment in metering and regulating equipment through which gas is delivered at individual stations to each customer. These were allocated to each customer in the ratio which the investment for each customer bore to the total investment in such facilities which were available to serve all customers. Distribution costs also included operating and maintenance expenses incurred in operating the metering and regulating stations. These were allocated on the basis of the number of stations.

The function which an allocation of costs (including return) is designed to perforin in a .rate case of this character is clear. The amount of gross revenue from each class of business is known. Some of those revenues are derived from sales at rates which the Commission has no power to fix. The other part of the gross revenues comes from the interstate wholesale rates which are under the Commission’s jurisdiction. The problem is to allocate to each class of the business its fair share of the costs. It is of course immaterial that the revenues from the intrastate sales or the direct industrial sales may exceed their costs, since the authority to regulate those phases of the business is lacking. To the extent, however, that the revenues from the interstate wholesale business exceed the costs allocable to that phase of the business, the interstate wholesale rates are excessive. The use of that method in these cases produced the following results:

Canadian

Revenues Costs Excess Revenue Over Costs

Regulated.. Unregulated $2,151,000 242,000 $1, 590, 000 188,000 $561,000 54,000

Colorado Interstate

Excess Revenue Revenues Costs Over Costs

Regulated. $4,438,000 $2,373,000 $2,065,000 Unregulated. 1,335,000 1,204,000 131,000

The Commission did not include in the rate reductions which it ordered any of the excess revenues over costs from the unregulated business. The reductions ordered were measured solely by the excess revenues over costs in the regulated business, viz., $2,065,000 in case of Colorado Interstate and $561,000 in case of Canadian.

Colorado Interstate and Canadian make several objections to that method. They maintain in the first place that a segregation of the physical property based upon use is necessary so that the payment due for the use of that property which is in the public service may be determined. Reliance for that position is rested on the Minnesota Rate Cases, 230 U. S. 352, 435, and Smith v. Illinois Bell Telephone Co., 282 U. S. 133, 146. Those were cases which involved state regulation of intrastate rates of companies doing both an intrastate and interstate business. But the rule fashioned by this Court for use in those situations was not written into the Natural Gas Act. Congress indeed prescribed no formula for determining how the interstate wholesale business, whose rates are regulated, should be segregated from the other phases of the business whose rates are not regulated. Rate-making is essentially a legislative function. Munn v. Illinois, 94 U. S. 113. Congress, to be sure, has provided for judicial review of the Commission’s orders. § 19. But that review is limited to keeping the Commission within the bounds which Congress has created. When Congress, as here, fails to provide a formula for the Commission to follow, courts are not warranted in rejecting the one which the Commission employs unless it plainly contravenes the statutory scheme of regulation. If Congress had prescribed a formula it would be the duty of the Commission to follow it. But we cannot say that under the Natural Gas Act the Commission can employ only one allocation formula and that that formula must entail a segregation of property. A separation of properties is merely a step in the determination of costs properly allocable to the various classes of services rendered by a utility. But where, as here, several classes of services have a common use of the same property, difficulties of separation are obvious. Allocation of costs is not a matter for the slide-rule. It involves judgment on a myriad of facts. It has no claim to an exact science. Hamilton, Cost as a Standard for Price, 4 Law & Cont. Prob. 321. But neither does the separation of properties which are not in fact separable because they function as an integrated whole. Mr. Justice Brandéis, speaking for the Court in Groesbeck v. Duluth, S. S. & A. R. Co., 250 U. S. 607, 614-615, noted that “it is much easier to reject formulas presented as being misleading than to find one apparently adequate.” Under this Act the appropriateness of the formula employed by the Commission in a given case raises questions of fact, not of law.

Colorado Interstate claims that the Commission’s formula ignored or at least failed to give full effect to the priority which the wholesale gas has over direct industrial sales — a priority recognized in the contracts with industrial users and in the municipal franchises. But over the years the interruptions or curtailments in service to direct industrial customers appear to have been slight.⁴ Moreover, to the extent that the priority accorded wholesale gas was actually exercised during the test year (1939) the allocation of costs made by the Commission gave full effect to it. As we have seen, volumetric costs were allocated to the customers in proportion to the number of Mcf’s delivered to each customer during the year; capacity costs were allocated in the ratio that the Mcf sales to each customer on the system peak day bore to the total sales on that day. The formula used reflected all actual curtailments of load to each customer during the year and on the system peak day.

Colorado Interstate objects because the Commission treated the transmission line as a unit. It points out that some laterals and equipment (such as metering stations) are used exclusively for making wholesale sales, some are used exclusively for making intrastate sales or direct industrial sales, and some are used in common in varying degrees by the several classes of business. It is pointed out, for example, that the line north of Pueblo is used almost exclusively by the regulated business but that under the Commission’s formula the pipeline was treated as if all the gas went into the pipe in Texas and came out at the Denver city gate. These objections are partially met by the manner in which distribution costs, to which we have referred, were allocated. But that is no more than a partial answer since they pertained only to metering and regulating equipment. The laterals were not segregated. They, however, appear to be used more commonly for direct industrial rather than for wholesale sales; and we are not convinced that the direct industrial sales were saddled with greater costs than they would have been had the laterals been segregated. The gravamen of this complaint is that the industrial sales are being burdened with costs of a part of the system which the direct industrial gas never uses. That contention points up our earlier observation that judgment and discretion control both the separation of property and the allocation of costs when it is sought to reduce to its component parts a business which functions as an integrated whole. The Commission found that but for the direct industrial market at Pueblo, Colorado and the wholesale market at Denver, the pipeline would not have been constructed. 43 P. U. R. (N. S.) p. 210. It is therefore obviously fair to determine transmission costs for the pipeline as a whole and not to compute them on a mileage demand basis. In that way the beneficiaries of the entire project share equitably in the cost. To allow the costs to accumulate the closer the gas gets to Denver would be to assume that the extension to Denver was a separate project on which the earlier customers were in no way dependent. These circumstances illustrate that considerations of fairness, not mere mathematics, govern the allocation of costs. Cf. Wabash Valley Electric Co. v. Young, 287 U. S. 488, 499. What we have said also answers Canadian’s complaint that the wholesale sales in Texas for consumption in the towns of Dalhart, Hartley, and Texline, Texas, are burdened with too large a share of transmission costs, Wo can see in this situation no difference between those customers and the ones located at more distant points on the pipeline.⁵

Colorado Interstate objects to that part of the Commission’s treatment of transmission costs whereby it assigned 50% of the return to capacity costs and 50% to volumetric costs. The contention is that the entire return on the transmission facilities should be apportioned to capacity costs on the theory that the volumetric costs have no relation to the property required for meeting the maximum demands of the wholesale business and that the method employed departs from the requirements of a fair return on the property devoted to the public service. But, as we have seen, capacity costs were allocated to customers in the ratio that the Mcf sales to each customer on the system peak day bore to the total sales to all customers on that day. It is not apparent why direct industrial sales should carry a lighter share of the costs merely because their use of the pipeline may be less on the system peak day. As the Commission points out, if the method advanced by Colorado Interstate were used, the amount paid by the industrial customer for transportation of the gas through the pipeline would be measured not by the customer’s use throughout the year, which might be substantial, but by its use on the system peak day which might be slight. In that event the industrial customer would obtain to an extent free transportation of gas.

Colorado Interstate also makes objection to the selection and use of February 9, 1939, as the system peak day and the allocation of the capacity cost component of the transmission costs on the basis of use on that day. It is argued that the mean temperature for that day was 8° Fahrenheit above zero, that much lower mean temperatures are experienced in the Colorado area, that as the temperature drops the load of resale gas rapidly increases, and that if these capacity costs were allocated on the basis of use during the coldest day the resale gas would carry a greater portion of them. We do not stop to develop the point. We have carefully considered Colorado Interstate’s contention. As we read the record, if either of the days selected by Colorado Interstate were taken as the system peak days, there would be allocated to the industrial gas a larger portion of these capacity costs than the Commission allocated. On that showing we cannot say that the choice of February 9, 1939, was unfair.

Colorado Interstate and Canadian object to the Commission’s use of the return. The Commission included in the total cost of service for these companies a 6% per cent return on the rate base.⁶ In other words, the 6y2 per cent return was computed on the basis of all the property used by petitioners in their various classes of business — intrastate sales, direct industrial sales, and interstate wholesale sales.⁷ Now it is apparent that if the reduction ordered was based on the excess of revenues from all classes of business over the aggregate costs, the result would be to reduce to a common level the profits from each class. In that case, whenever a company was making a higher return on its unregulated business than the rate of return allowed for the regulated business, the excess earnings from the unregulated part would be appropriated to the entire business. When the unregulated business was being operated at a loss or at less than the return which was allowed, excess earnings from the regulated business would be appropriated to the unregulated business. A low rate might therefore be concealed by siphoning earnings from the unregulated business; a high rate might be built up by making the regulated business share the losses of the unregulated one.

It is said that that is what happened here. But that is not true. As we have seen, the Commission ordered a rate reduction based solely on the excess of revenues over costs (including return) derived from the regulated business. None of the excess revenues over costs (including return) from the unregulated business was included in that reduction. If the Commission in determining costs of the unregulated business had used a higher rate of return, it would have increased the costs of that business and reduced the excess revenues allocable to it. But since under the Commission’s method of allocation the amount of that excess would not be reflected in the reduction ordered, there would be no difference in result.

The cases are presented as if the 6% per cent allowed by the Commission on the rate base limits the earnings from the whole enterprise to 6% per cent. That also is not true. The return merely measures the earnings allowed from the regulated business. As we have noted, the excess of earnings which Colorado Interstate makes from direct industrial sales (on the basis of 6% per cent return) is $131,000 annually. The Commission pointed out (43 P. U. R. (N. S.) p. 230) that if Colorado Interstate “retains these earnings in excess of a 6% per cent rate of return on its sales to these customers, its rate of return on its entire business is increased to approximately 8 per cent after placing into effect the reductions in rates ordered herein.”

Of the other objections made by Canadian and Colorado Interstate on this phase of the case, we need mention only one.⁸ It is contended that the findings of the Commission on the allocation of costs are inadequate and that the cases should be remanded to the Commission so that appropriate findings may be made. The findings of the Commission in this regard leave much to be desired since they are quite summary and incorporate by reference the Commission’s staff’s exhibits on allocation of cost. But the path which it followed can be discerned. And we do not believe its findings are so vague and obscure as to make the judicial review contemplated by the Act a perfunctory process. Cf. United States v. Chicago, M., St. P. & P. R. Co., 294 U. S. 499; United States v. Carolina Freight Carriers Corp., 315 U. S. 475.

Canadians Sales to Colorado Interstate. The Commission ordered a blanket reduction of $561,000 in the sales price of all types of gas sold by Canadian to Colorado Interstate. A substantial part of that gas is sold to Colorado Interstate for resale to direct industrial customers. Canadian maintains that the Commission has no authority to fix the rate on the sale of that portion or class of gas to Colorado Interstate. Sec.' 1 (b) of the Act, however, provides, as we have noted, that the provisions of the Act apply “to the sale in interstate commerce of natural gas for resale for ultimate public consumption for domestic, commercial, industrial, or any other use.” Canadian, however, seeks support for its position in the declaration in § 1 (a) of the Act that “the business of transporting and selling natural gas for ultimate distribution to the public is affected with a public interest.” But we find no warrant for saying that the words “ultimate distribution to the public” imply distribution to domestic users alone. Industrial users are as much a part of the “public” as domestic users and other commercial users. And the distribution to one is as “ultimate” as the distribution to the other. Moreover, that declaration of policy may not be used to take out of § 1 (b) of the Act the express provision subjecting to regulation gas sold for resale for “industrial use.” Furthermore, the declaration of policy contained in § 1 (a) is not as narrow as Canadian suggests. For § 1 (a) goes on to say that federal regulation in matters relating to “the transportation of natural gas and the sale thereof in interstate and foreign commerce is necessary in the public interest.” Sales for resale to industrial users is embraced in the broad sweep of that language. Canadian also seeks support for its position from the proviso in § 4 (e) of the Act that the Commission shall not have authority to suspend the rate “for the sale of natural gas for resale for industrial use only.” Canadian infers from that provision that such rates are not subject to regulation by the Commission. The short answer, however, is that the authority of the Commission to suspend rates is restricted to rates over which it has jurisdiction. If the Commission had no authority over the rates in question, the proviso in § 4 (e) would be unnecessary. Accordingly, it seems clear that all of the gas sold by Canadian to Colorado Interstate for resale, including that sold for resale for industrial use, is subject to rate regulation by the Commission.

There is the further suggestion in Canadian’s argument that since the Commission treated Canadian and Colorado Interstate as an integrated system for purposes of allocation of costs, it should have limited its rate reduction to those rates over which it would have jurisdiction if the two companies were in fact one. It is argued that in such event there would be no sales between Canadian and Colorado Interstate and the latter’s direct sales to industrial users would not be subject to the jurisdiction of the Commission. The difficulty is that Colorado Interstate purchases its gas from Canadian and the purchase price is the interstate wholesale rate which is an operating expense on which Colorado interstate’s resale rates are computed. Moreover, Canadian as required by § 4 (c) of the Act has its rate to Colorado Interstate in a rate schedule on file with the Commission. Unless and until a new rate schedule was filed or the old schedule changed by the Commission, that rate would have to be exacted by Canadian and paid by Colorado Interstate. § 4 (d). That rate therefore could hardly be maintained if Colorado Interstate were allowed as an operating expense a lesser amount for the gas it purchases from Canadian.

Producing and Gathering Facilities. Sec. 1 (b) which we have already quoted states that the provisions of the Act “shall not apply ... to the production or gathering of natural gas.” The Commission determined a rate base which includes Canadian’s production and gathering properties as well as its interstate transmission system. The return allowed by the Commission was limited to 6% per cent of the rate base so computed. The Commission made an allowance for working capital to enable Canadian to carry on its production and gathering operations. The Commission made an allowance for Canadian’s operating expenses which included the cost of producing and gathering natural gas. The Commission applied its formula for allocation of costs to Canadian’s production and gathering properties as well as to its other facilities. Thus Canadian contends that contrary to the mandate of § 1 (b) the Commission has undertaken to regulate the production and gathering of natural gas. Reliance for that position is sought from other provisions of the Act. It is pointed out that § 1 (a) declares t*hat “the business of transporting and selling natural gas” for ultimate distribution to the public is affected with a public interest and that federal regulation “in matters relating to the transportation of natural gas and the sale thereof” in interstate commerce is necessary in the public interest. Transportation and sale do not include production or gathering. Other sections emphasize that distinction. Thus § 4 and § 5, the rate regulating provisions of the Act, refer to charges for the “transportation or sale of natural gas, subject to the jurisdiction of the Commission.” Sec. 7 (a) relates to the extension or improvement of “transportation facilities”; § 7 (b) to the abandonment of “facilities subject to the jurisdiction of the Commission”; § 7 (c) to the construction or extension of facilities for the “transportation or sale of natural gas, subject to the jurisdiction of the Commission.” It is pointed out that apart from § 1 (b) only a few sections of the Act refer to “production.” Sec. 5 (b) gives the Commission power to investigate “the cost of the production or transportation of natural gas by a natural-gas company in cases where the Commission has no authority to establish a rate governing the transportation or sale of such natural gas.” This goes no further, it is said, than to aid state regulation. Sec. 9 (a) authorizes the Commission to ascertain and determine and by order fix “the proper and adequate rates of depreciation and amortization of the several classes of property of each natural-gas company used or useful in the production, transportation, or sale of natural gas.” Sec. 9 (a) further provides that no natural-gas company subject to the jurisdiction of the Commission shall charge to operating expenses “any depreciation or amortization charges on classes of property other than those prescribed by the Commission, or charge with respect to any class of property a percentage of depreciation or amortization other than that prescribed therefor by the Commission.” These are said, however, to be no more than' accounting requirements and distinct from the fixing of rates to be charged for public utility or transportation services. That distinction is emphasized, it is said, by the proviso in § 9 (a) that “Nothing in this section shall limit the power of a State commission to determine in the exercise of its jurisdiction, with respect to any natural-gas company, the percentage rates of depreciation or amortization to be allowed, as to any class of property of such natural-gas company, or the composite depreciation or amortization rate, for the purpose of determining rates or charges.” The provisions of § 10 (a) which give the Commission authority to require reports from natural-gas companies as to their assets and liabilities, the “cost of maintenance and operation of facilities for the production” of natural gas and the like are said to be mere information requirements quite consistent with the absence of power to regulate the production and gathering of natural gas.⁹ See Interstate Commerce Commission v. Goodrich Transit Co., 224 U. S. 194. And the authority given the Commission by § 14 (b) is said merely to supplement the Commission’s powers under sections of the Act. Sec. 14 (b) grants the Commission power to determine “the adequacy or inadequacy of the gas reserves held or controlled by any natural-gas company” and “the propriety and reasonableness of the inclusion in operating expenses, capital, or surplus of all delay rentals or other forms of rental or compensation for unoperated lands and leases.” This is said to supplement the Commission’s authority over the construction, extension, or abandonment of facilities or service under § 7, the determination of amortization rates under § 9 (a), and the accounting requirements of § 8.

Support for Canadian’s position is also sought in the legislative history of the Act. It is pointed out that the declared purpose of the legislation was to occupy the field in which this Court had held the States might not act. See Federal Power Commission v. Hope Natural Gas Co., 320 U. S. 591, 609-610. And it is noted that Senator Wheeler, who sponsored the legislation in the Senate, said during the debate in answer to an inquiry whether the bill undertook to regulate the production of natural gas or the producers of natural gas: “It does not attempt to regulate the producers of natural gas or the distributors of natural gas; only those who sell it wholesale in interstate commerce.” 81 Cong. Rec. p. 9312.

From these various materials it is argued that the Commission has no authority to include producing or gathering facilities in a rate base or to include production or gathering expenses in operating expenses. It is said that when the Commission follows that course, it regulates the production and gathering of natural gas contrary to the provisions of § 1 (b) of the Act. It is argued that the correct procedure is for the Commission to allow in the operating expenses of a natural-gas company, whose rates it is empowered to fix, the “fair field price” or “fair market value, as a commodity, of the gas” which finds its way into the transmission lines for interstate transportation and sale.

This is precisely the argument which West Virginia, appearing as amicus curiae, advanced in the Hope Natural Gas Co. case. We rejected the argument in that case. 320 U. S. pp. 607-615, particularly p. 614, n. 25. We have reviewed it here at this length in view of the seriousness with which it has been urged not only by Canadian but also by the Independent Natural Gas Association of America which appeared amicus curiae. But we adhere to our decision in the Hope Natural Gas Co. case and will briefly state our reasons.

A natural-gas company as defined in § 2 (6) of the Act is “a person engaged in the transportation of natural gas in interstate commerce, or the sale in interstate commerce of such gas for resale.” Canadian is such a company. It is plain therefore that the Commission has authority to fix its interstate wholesale rates. § 5. It is obvious that when rates of a utility are fixed the value of its property is affected. For as we stated in the Hope Natural Gas Co. case, value is “the end product of the process of rate-making not the starting point.” 320 U. S. p. 601. When a natural-gas company which owns producing properties or a gathering system is restricted in its earnings by a rate order, the value of all of its property is affected. Congress of course might have provided that producing or gathering facilities be excluded from the rate base and that an allowance be made in operating expenses for the fair field price of the gas as a commodity. Some have thought that to be the wiser course. But we search the Act in vain for any such mandate. The Committee Report stated that the Act provided “for regulation along recognized and more or less standardized lines” and that there was “nothing novel in its provisions.” H. Rep. No. 709, 75th Cong., 1st Sess., p. 3. Certainly the use of a rate base which reflects the property of the utility whose rates are being fixed has been customary. 2 Bonbright, Valuation of Property (1937) ch. XXX; Smith, The Control of Power Rates in the United States and England (1932), 159 Annals 101. Prior to the Act that method was employed in the fixing of the rates of gas, as well as electric, utilities. See Willcox v. Consolidated Gas Co., 212 U. S. 19; Cedar Rapids Gas Co. v. Cedar Rapids, 223 U. S. 655; Newark Natural Gas & Fuel Co. v. Newark, 242 U. S. 405; Railroad Commission v. Pacific Gas & Electric Co., 302 U. S. 388; Lone Star Gas Co. v. Texas, 304 U. S. 224. We do not say that the Commission lacks the authority to depart from the rate-base method. We only hold that the Commission is not precluded from using it. There are ample indications throughout the Act to support that view. Sec. 6 (a) empowers the Commission to investigate and ascertain the “actual legitimate cost of the property of every natural-gas company, the depreciation therein, and, when found necessary for rate-making purposes, other facts which bear on the determination of such cost or depreciation and the fair value of such property.” As we have noted, § 9 (a) gives the Commission authority not only to require natural gas companies to carry proper and adequate depreciation and amortization accounts but also to fix such rates for “the several classes of property of each natural-gas company used or useful in the production, transportation, or sale of natural gas.” And § 14 (b), as already stated, not only gives the Commission authority to determine the adequacy or inadequacy of gas reserves of a natural-gas company but also empowers it to determine the “propriety and reasonableness of the inclusion in operating expenses, capital, or surplus of all delay rentals or other forms of rental or compensation for unoperated lands and leases.” Sec. 9 (a) and § 14 (b), though designed not to limit the power of state regulatory agencies, plainly were designed to aid the Commission in its rate-making functions. These provisions ¹⁰ all suggest that when Congress designed this Act it was thinking in terms of the ingredients- of a rate base, the deductions which might be made, and the additions which were contemplated. No exclusion of property used or useful in production of natural gas was made. That type of property was not singled out for special treatment; it was treated the same as all other property. We must read § 1 (b) in the context of the whole Act. It must be reconciled with the explicit provisions which describe the normal conventions of rate-making.

That does not mean that the part of § 1 (b) which provides that the Act shall not apply “to the production or gathering of natural gas” is given no meaning. Certainly that provision precludes the Commission from any control over the activity of producing or gathering natural gas. For example, it makes plain that the Commission has no control over the drilling and spacing of wells and the like. It may put other limitations on the Commission. We only decide that it does not preclude the Commission from reflecting the production and gathering facilities of a natural gas company in the rate base and determining the expenses incident thereto for the purposes of determining the reasonableness of rates subject to its jurisdiction.

That treatment of producing properties and gathering facilities has of course an indirect effect on them. As we have said, rate-making like other forms of price fixing may reduce the value of the property which is being regulated. Federal Power Commission v. Hope Natural Gas Co., supra, p. 601. But that would be true whether or not a rate base was used. Canadian would be the first to object if the gas which it owns was given no valuation in these proceedings. Obviously it has value. The Act does not say that the Commission would have to value it at the fair field price if the Commission abandoned the rate-base method of regulation. We held in the Hope Natural Gas Co. case that under the Act it is “the result reached not the method employed which is controlling. ... It is not theory but the impact of the rate order which counts. If the total effect of the rate order cannot be said to be unjust and unreasonable, judicial inquiry under the Act is at an end.” 320 U. S. p. 602. If the Commission followed Canadian’s method, excluded the producing properties and gathering facilities from the rate base, valued the gas at a price which would reduce the earnings to the level of the present order, the effect on the producing properties and gathering facilities would be precisely the same as in the present case. Since there is no provision in the Act which would require the Commission to value the gas at the price urged by Canadian, the problem on review would be whether the end result was unjust and unreasonable. The point is that whatever method for rate-making is taken the fixing of rates affects the value of the underlying property. Hence § 1 (b) could be read as petitioners read it only if Congress had put a floor under producing properties and gathering facilities and fixed a minimum return on them.

These considerations lead us to conclude that § 1 (b) does not prevent the Commission from taking into account the production properties and gathering facilities of natural gas companies when it fixes their rates.

Original Cost of Production and Gathering Facilities. The Commission found the actual legitimate cost of Canadian’s property, including its producing properties and gathering facilities, to be $10,784,464 as of December 31,1939. It deducted $2,134,629 for accrued depreciation and depletion. It added $150,738 for working capital and $571,923 for gross plant additions to December 31, 1941. The result was a rate base of $9,372,496 which the Commission rounded to $9,375,000. The Commission rejected estimates of reproduction cost new less observed depreciation because they were “too conjectural to have probative value” and adopted original cost as “the best and only reliable evidence as to property values.” 43 P. U. R. (N. S.) pp. 213, 214. Canadian maintains that if its leaseholds are to be included in the rate base, it was improper to value them as the Commission did. Canadian offered evidence that their present market value was much higher. It also offered evidence of a commodity market value of natural gas per Mcf which would give a much higher value to the production phase of Canadian’s business. We do not stop to develop the details of these lines of evidence. We cannot say that the Commission was under a duty to put the leaseholds into the rate base at the valuation urged by Canadian unless we revise what we said in Federal Power Commission v. Natural Gas Pipeline Co., 315 U. S. 575, 586, and overrule Federal Power Commission v. Hope Natural Gas Co., supra. We held in those eases that the Commission was not bound to the use of any single formula in determining rates. And in the Hope Natural Gas Co. case we sustained a rate order based on actual legitimate cost against an insistent claim that the producing properties should be given a valuation which reflected the market price of the gas. In those cases we held that the question for the courts when a rate order is challenged is whether the order viewed in its entirety and measured by its end results meets the requirements of the Act. That is not a standard so vague and devoid of meaning as to render judicial review a perfunctory process. It is a standard of finance resting on stubborn facts.¹¹ “From the investor or company point of view it is important that there be enough revenue not only for operating expenses but also for the capital costs of the business. These include service on the debt and dividends on the stock. Cf. Chicago & Grand Trunk R. Co. v. Wellman, 143 U. S. 339, 345-346. By that standard the return to the equity owner should be commensurate with returns on investments in other enterprises having corresponding risks. That return, moreover, should be sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital. See Missouri ex rel. Southwestern Bell Tel. Co. v. Public Service Commission, 262 U. S. 276, 291 (Mr. Justice Brandeis concurring).” Federal Power Commission v. Hope Natural Gas Co., supra, p. 603.

Hence, 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.

Cost to Canadian’s Affiliate. As we have seen, Canadian and Colorado Interstate had their origin in an agreement made in 1927 between Southwestern, Standard, and Cities Service. Pursuant to that agreement Southwestern organized Canadian, a wholly owned subsidiary, to which were transferred the gas leaseholds and producing property owned by Amarillo, a wholly owned subsidiary of Southwestern. The cash consideration for this transfer was $5,000,000, which was advanced by Standard at 6 per cent interest. Colorado Interstate was organized by Standard to construct and operate the pipeline to connect with Canadian’s facilities and to transport the gas to the Denver market and intermediate points.

Canadian issued $11,000,000 of 6% twenty-year bonds to finance its portion of the total project. Colorado Interstate purchased those bonds with part of the proceeds of $19,200,000 of its own 6% twenty-year sinking fund bonds which Standard had purchased at par. Canadian repaid the $5,000,000 advance made by Standard out of the proceeds of the sale of its bonds to Colorado Interstate. Canadian’s stock was issued to Southwestern and is carried on Canadian’s books at $1.00. Canadian entered into a “cost” contract with Colorado Interstate whereby Canadian agreed to produce and sell gas to Colorado Interstate at “cost” for twenty years which might be extended by Colorado Interstate. Under the contract, “cost” included Canadian’s operating expenses, interest at 6%, and amortization (in lieu of depreciation, depletion and retirements) of all of Canadian’s indebtedness over the twenty-year period. It was also provided that Canadian’s “cost” under the contract should be decreased by any profits which it might obtain from other sources including any local sales. Thus it was obvious that Canadian under this “cost” contract would have no profits available for dividends on its stock.

But in accordance with the agreement Colorado Interstate issued $2,000,000 par value 6% preferred stock and 1,250,000 shares of no par common. Cities Service received 15% of the common stock. The rest of the common stock and all of the preferred was divided equally between Southwestern and Standard. The latter paid $2,000,000 in cash for its share of preferred and common. Southwestern received not only preferred and common stock, but also $5,000,000 in cash from the proceeds of the $11,000,000 of bonds which Canadian issued and which were to be amortized over twenty years as part of the “cost” of gas sold to Colorado Interstate by Canadian.

Canadian contends that the Commission should have included $5,000,000 in the rate base for the gas leases and producing properties acquired from Amarillo. The original cost of the properties to Amarillo was $1,879,504. That is all the Commission allowed. It said, “Any treatment which would permit the capitalization of such amounts would open the door to the renewal of past practices of the utility industry when properties were traded between affiliated interests at inflated prices with the expectation that the public would foot the bill.” 43 P. U. R. (N. S.) p. 215. We agree. Southwestern owned the producing properties at the beginning, of the transaction through one subsidiary; it owned them at the end of the transaction through another subsidiary. As between Southwestern and its subsidiaries there was no more than an intercompany profit. If Amarillo rather than Canadian had entered the project, had sold a bond issue to Southwestern and with part of the proceeds paid off a $5,000,000 loan to Standard, certainly the amount of that payment would not be properly included in its rate base. We fail to see a difference in substance when another wholly owned subsidiary is utilized by Southwestern. The fact that the negotiations between Southwestern and Standard were at arm’s length has no bearing on the present problem. The end result is that property has been transferred at a write-up from one of Southwestern’s pockets to another. The impact bn consumers of utility service of write-ups and inflation of capital assets through intercompany transactions or otherwise is obvious. The prevalence of the practice in the holding company field gave rise to an insistent demand for federal regulation. See S. Doc. No. 92, Pt. 84-A, 70th Cong., 1st Sess., Utility Corporations, Final Report of the Federal Trade Commission (1936); Bonbright & Means, The Holding Company (1932), ch. VI; Barnes, The Economics of Public Utility Regulation (1942) pp. 95 et seg.

American T. & T. Co. v. United States, 299 U. S. 232, is not opposed to our position. It merely indicates a proper treatment for an intercompany transaction where in fact an additional investment is shown to exist.

Affirmed.

Me. Justice' Roberts and Me. Justice Reed dissent from so much of the opinion as approves the allocation by the Commission of investments and expenses to the non-regulable transmission properties. They concur in the dissent of the Chief Justice in Canadian River Gas Co. v. Federal Power Commission, post, p. 615.

1 The latter resales are made by Colorado-Wyoming Gas Co. which transports the gas from a point near Littleton, Colorado to Cheyenne, Wyoming. The proceedings against this company were consolidated with those against Canadian and Colorado Interstate. The Commission also ordered a reduction in the rates charged by Colorado-Wyoming Gas Co. That order is here for review on certain points in No. 575, post, p. 626.

2 The Commission in its report characterized volumetric costs as variable costs and capacity costs as fixed costs. 43 P. U. R. (N. S.) p. 232.

3 A residual refining credit was determined and deducted from production costs.

4 Fifteen times in some 12 years.

5 So far as appears Canadian presented no evidence showing the cost of these intrastate sales.

6 As we have said, the return on leases and wells was treated as volumetric costs; 50 per cent of the return on the Denver pipeline was treated as volumetric and 50 per cent as capacity costs; and return on investment in metering and regulating equipment was treated as distribution costs.

7 As respects the accounting for the cost of money invested in the enterprise see Schlatter, Advanced Cost Accounting (1939), ch. XII; Neuner, Cost Accounting (1942), p. 277; Lawrence, Cost Accounting (1930), ch. 22.

8 It is objected that the allocation made by the Commission results in discrimination between purchasers of gas from Colorado Interstate as indicated by the fact that costs allocated to one customer who is distant from Denver are greater than costs allocated to another customer at Denver. But all the Commission did was to order an aggregate reduction in the wholesale rates of $2,065,000 so as to produce a fair return. The adjustment of the rate schedules for various delivery points has not yet been made. See Federal Power Commission v. Natural Gas Pipeline Co., 315 U. S. 575, 584.

9 Another section of the Act which refers to “production” is § 11 (a). It gives the Commission certain functions to perform where two or more States propose compacts dealing with the conservation, production, transportation, or distribution of natural gas.

10 §§ 5 (b), 6 (a), 9 (a), 10 (a), and 14 (b).

11 Cf. the British standards described in Smith, The Control of Power Rates in the United States and England, 159 Annals 101, 103, 104.