BREITENSTEIN, Circuit Judge.
Petitioner Cities Service Gas Company seeks a review of the Federal Power Commission’s Opinion No. 542 and accompanying orders. See 39 FPC 1034. The effect of that order is to reduce the jurisdictional rates of Gas Company by a disallowance of a portion of the gas costs and to require a refund of excess collections made since April 23, 1964.
The situation is that an interstate pipeline owned certain gas producing properties which it spun off to an affiliate. Through a series of corporate transactions the stock of the affiliate was transferred to the parent company of the pipeline and sold by the parent to an unaffiliated company. The basic question is whether, in arriving at the rates to be charged by pipeline to its customers, the gas shall be priced on the basis of pipeline’s cost of service or on the basis of the price fixed by the contract between pipeline and the unaffiliated producer. By a three to two decision, the FPC overruled the Examiner and held that cost of service controlled. Subsidiary questions go to the determination of the cost of service.
Gas Company operates an interstate pipeline which the Natural Gas Act, 15 U.S.C. § 717 et seq., places under FPC jurisdiction. For about 40 years it has supplied gas to consumers and industrial customers in Kansas, Oklahoma, Nebraska, and Missouri. In 1943, the FPC determined its rates on a cost-of-service basis, 3 FPC 459, and its action was upheld in Cities Service Gas Company v. Federal Power Commission, 10 Cir., 155 F.2d 694, cert. denied 329 U.S. 773, 67 S.Ct. 191, 91 L.Ed. 664. Prior thereto Gas Company had acquired leases covering a substantial acreage in the Texas Panhandle Field in Texas and in the Oklahoma-Hugoton Field in Oklahoma. On that acreage there are about 300 producing wells from which gas is transmitted interstate.
In April, 1953, Gas Company transferred the producing properties at their net book cost to Cities Service Gas Producing Company. , The purpose of the transfer was to facilitate compliance with an order of the Oklahoma Corporation Commission. Cities Service Producing was a wholly owned subsidiary of Gas Company. Gas Company contracted with its affiliate to take production at 6.79610 per Mcf for gas from the Texas field and at 9.82620 per Mcf for Oklahoma gas. The contract provided for an upward revision to reflect the prevailing field price at the wellhead. In December, 1953, the price of the Texas gas was increased to 7.18630.
In March, 1962, Gas Company transferred all the stock of Cities Service Producing to Empire Gas and Fuel Company as a stock dividend. At that time [414]*414Empire owned all the common stock of Gas Company. In July, 1962, Empire was merged with Cities Service Company, the parent company in the Cities Service system. The Examiner found that the transfer to Empire and the merger of Empire and Cities Service Company were steps in an overall plan of corporate reorganization and simplification.
On May 8, 1963, the parent company sold all of the stock of Cities Service Producing to Continental Oil Company, which is not affiliated with the Cities Service system. The sale price of $24,-250.000 was found by the Examiner to be the fair value of the stock. Cities Service had a capital gain of about $21,-450.000 from the transaction. Continental changed the name of the company to Continental Gas Producing Company. The FPC authorized the change in name of the holder of the pertinent certificate. On April 30,1965, Continental Producing was dissolved and all of its assets transferred to Continental Oil. The Examiner found that this transaction was “for the purpose of reducing unnecessary costs and achieving tax benefits.” Continental then applied to FPC for a certificate recognizing the change in ownership of the producing properties.
After the 1954 decision in Phillips Petroleum Company v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 Cities Service Producing applied for, and the FPC issued, a grandfather certificate authorizing the rates of 7.1863$ and 9.8262$ per Mcf for gas respectively produced in the Texas and Oklahoma fields in question. See Cities Service Gas Producing Company v. Federal Power Commission, 10 Cir., 233 F.2d 726, cert. denied 352 U.S. 911, 77 S.Ct. 149, 1 L.Ed.2d 118. In 1955, Cities Service Producing filed schedules increasing its rates for sales to Gas Company to 8.8129$ and 10.1480$ per Mcf for gas from the respective fields. The FPC consolidated these proceedings with increased rate filings made by the Gas Company. The proceedings were terminated by an FPC approved settlement. The filed rates were allowed to remain in effect but the parties agreed that the termination of the proceedings was not a determination of the reasonableness of the rates of Cities Service Producing.1
On two subsequent settlements of Gas Company’s rate cases, the allowances for gas from Cities Service Producing were on the basis of Moo of a cent less than the latter’s filed rate in the first case and of Moo of a cent less in the second case. These allowances were made because the municipal interests, intervenors therein and herein, were unwilling to recognize the Cities Service Producing filed rates in the determination of Gas Company’s cost of service. In its order approving the settlement in Docket No. RP64-9, the FPC said, 33 FPC 1292, 1294:
“The issues relating to the allowance in Cities Service’s cost of service for gas purchased from Continental Gas Producing Company (formerly Cities Service Gas Producing Company) are reserved in accordance with Article X of the settlement and subject to notice as provided in Section (3) of that Article.”
Thereafter, on the motion of the municipal intervenors the FPC consolidated the Continental certificate proceeding, Docket No. G-2737, with the Gas Company rate proceeding, Docket No. RP64-9. After an evidentiary hearing, the Examiner found that “[i]f cost of service of gas from the Producing Properties is [415]*415the measure of the allowance to Pipeline [Gas Company] for such gas,” the cost of service is 3.380 per Mcf and that this required a reduction in Gas Company’s jurisdictional sales of 1.00 per Mcf. In reaching this figure the Examiner allowed a cost reduction of $1,042,368 in Gas Company’s overall cost of service because of the depletion allowance claimed by Continental Producing on its tax returns.
The Examiner did not allow the cost-of-service rate. Instead he approved the contract rate saying that the FPC was aware of the potentiality of the alienation of producing properties and “had neither announced nor even intimated the existence of regulatory prohibitions” and that Gas Company is “entitled to fair and timely notice of new or changed Commission policy and standards imposing new or changed obligations and duties.”
On the certificate application of Continental, the Examiner held that Continental was a bona fide transferee for value and successor to the interest of its former subsidiary. He recommended the grant of the certificate on condition that it was without prejudice to “future proceedings or objection relating to the operation of any price or related provisions in the gas * * * contracts.”
On review, the FPC adjusted the cost of service on a unit basis to 3.470 per Mcf by taking into account royalties which the Examiner deemed inconsequential. By a three to two vote the FPC reversed the Examiner’s holding that the contract price governed and held that cost of service controlled. It said that “as of the time of the sale Cities was, or should have been, aware of the great likelihood that in any contested rate case gas ‘purchased’ from an affiliated company would be priced on a cost-of-service basis.” The FPC ordered refunds of excess collections made since April 23, 1964. It upheld the Examiner on the grant of the certificate requested by Continental.
Commissioner Carver dissented. In his opinion the FPC decision was improper prospective rule making; failed to treat consistently the transferor Cities Service and the transferee Continental; and produced an “excessively onerous and harsh end result.” He pointed out the pendency of the “Pipeline Production Area Rate Proceeding,” 35 FPC 497, and said that the decision of the FPC left “little room for intellectual maneuver” in that case. He specifically stated that “it cannot be found that the trans-feror wilfully acted contrary to prescribed standards of regulated conduct.”
Commissioner O’Connor disagreed with the action of the majority because the consumers had not borne the risk of development of the gas reserves and should not receive the benefit of a straight cost-of-service treatment. He concluded that it is inequitable to apply either (1) straight cost-of-service treatment, or (2) fair-field-or-contract-price treatment. He would compromise by “eliminating the deduction for depletion in the pipeline’s cost of service attributable to these properties now owned by Continental.” This treatment, he said, would alleviate administrative problems and permit a cost-of-service rate which “more accurately reflects the actual positions of the parties.”
The lack of unanimity among the experts gives us concern. Perhaps the division of opinion is to be expected in this unusual case. Under the FPC order, Gas Company is required to pay Continental an average of 9.150 per Mcf and yet when the same gas is priced for sale by Gas Company an allowance is made for 2.080 per Mcf. This action excludes from Gas Company’s cost of service over $3,500,000 annually of actual out-of-pocket gas purchase cost. The anomalous result arises from the spin-off by Gas Company of the producing properties which had been dedicated by it to interstate transmission and sale. The spin-off was followed by the alienation of the properties to a non-affiliate in an arm’s length business transaction which returned a profit to the parent of Gas Company in the amount of $21,450,000.
[416]*416In fixing consumer rates for gas produced from pipeline owned properties, the FPC with the approval of the courts has used the cost-of-service approach. See Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 64 S.Ct. 281, 88 L.Ed. 333; Colorado Interstate Gas Co. v. Federal Power Commission, 324 U.S. 581, 65 S.Ct. 829, 89 L.Ed. 1206; and Panhandle Eastern Pipe Line Co. v. Federal Power Commission, 324 U.S. 635, 65 S.Ct. 821, 89 L.Ed. 1241. Indeed, the approach has been used in fixing consumer rates for Gas Company. See Cities Service Gas Company v. Federal Power Commission, 10 Cir., 155 F.2d 694, cert. denied 329 U.S. 773, 67 S.Ct. 191, 91 L.Ed. 664. When the FPC has departed from the cost-of-serviee approach, it has been reversed by the courts on appeal. See City of Detroit, Mich, v. Federal Power Commission, 97 U.S. App.D.C. 260, 230 F.2d 810, cert. denied Panhandle Eastern Pipe Line Co. v. City of Detroit, Mich., 352 U.S. 829; 77 S.Ct. 34, 1 L.Ed.2d 48; cf. Mississippi River Fuel Corp. v. Federal Power Commission, 102 U.S.App.D.C. 238, 252 F.2d 619, cert. denied 355 U.S. 904, 78 S.Ct. 331, 2 L.Ed.2d 260; and Willmut Gas and Oil Co. v. Federal Power Commission, 112 U.S.App.D.C. 27, 299 F.2d 111. The spin-off to the affiliate did not change the situation. Intracompany transactions cannot be used to create an artificial or inflated price to be charged consumers. See Colorado Interstate Gas Co. v. Federal Power Commission, 324 U.S. 581, 606-608, 65 S.Ct. 829, 89 L.Ed. 1206.
The fact that the First Phillips decision, Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035, which made independent producers subject to the Act, postdated the spiri-off does not change the situation. That decision made the affiliate subject to FPC jurisdiction. It did not change the obligation of Gas Company to its consumers. In Second Phillips, Wisconsin v. Federal Power Commission, 373 U.S. 294, 83 S.Ct. 1266, 10 L.Ed.2d 357, the Court affirmed the FPC’s 1960 decision that independent producer rates should be determined on an area, rather than cost-of-serviee basis. This does not concern us because our problem relates to pipeline production rather than independent production. We recognize the pendency of the pipeline rate cases relating to “cost allowances for pipeline gas production.” 31 FPC 1595; see also 35 FPC 497. We assume that if those cases result in a new policy, it will be applied to the production involved herein. We agree with the FPC that the possibility of a new policy does not detract from the validity of the action here taken.
The FPC concluded correctly that the 1949 decision in Federal Power Commission v. Panhandle Eastern Pipe Line Co., 337 U.S. 498, 69 S.Ct. 1251, 93 L.Ed. 1499, is not in point. There the Court held that FPC had no authority over the spin-off of undeveloped gas leaseholds which had been a part of the rate base of the pipeline. This lack of authority is not determinative of the consequences of such action if it causes a detriment to the pipeline’s ratepayers. Panhandle predated First Phillips. Furthermore, the continuing validity of Panhandle is clouded by the Rayne Field case, United Gas Improvement Co. v. Continental Oil Co., 381 U.S. 392, 85 S.Ct. 1517, 14 L.Ed.2d 466, which held that FPC had jurisdiction over the sale of proven reserves to a pipeline.
We conclude that the transfer of the properties to the affiliate did not foreclose the FPC from using the cost-of-service approach as if the properties remained in the Gas Company. The question is whether the situation is changed by the alienation of the properties to a non-affiliate.
The transaction between Cities Service and Continental was a stock sale. Gas Company argues that the FPC action was an unlawful attempt to regulate indirectly a sale of common stock over which the FPC had no jurisdiction. It relies on California v. Federal Power Commission, 369 U.S. 482, 489, 82 S.Ct. 901, 906, 8 L.Ed.2d 54, wherein the Court said that the Act “confers jurisdiction [417]*417on the Commission over the acquisition of assets of natural gas companies, not over stock acquisitions in them.” In that case one natural gas company acquired nearly all the stock of another and the United States brought suit under the Clayton Act to require a divestiture. While the suit was pending, the FPC authorized the merger of assets of the two companies. The Court held that the FPC should have awaited the decision in the anti-trust suit.
Our case is different. The FPC recognizes that under the Act it has no jurisdiction over security transactions relating to natural gas companies. The lack of power in this regard does not foreclose the FPC from fixing appropriate rates under the Act. If the FPC action is reasonably related to its statutory obligation to protect consumers against excessive charges, that action cannot be condemned on the ground that it affects transactions which the FPC cannot control as such. Under the Act the primary function of the FPC is to protect consumers against exploitation by excessive rates and charges. See Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 612, 64 S.Ct. 281, 88 L.Ed. 333, and Atlantic Refining Co. v. Public Service Commission of New York, 360 U.S. 378, 388, 79 S.Ct. 1246, 3 L.Ed.2d 1312.
A regulated utility may not impose unnecessary costs upon its consumers. See Acker v. United States, 298 U.S. 426, 430-431, 56 S.Ct. 824, 80 L.Ed. 1257, and El Paso Natural Gas Co. v. Federal Power Commission, 5 Cir., 281 F.2d 567, 573, cert. denied California v. Federal Power Commission, 366 U.S. 912, 81 S.Ct. 1083, 6 L.Ed.2d 236. If the properties in question had been retained by Gas Company or an affiliate, cost of service would have determined the rate. We believe that the alienation of the properties to a non-affiliate, even though made in good faith and for value, does not change the situation. The parent company, Cities Service, received a $21,450,000 profit. Gas Company seeks a further profit by basing its gas cost on the price fixed by contract made between it and an affiliate and now binding on it and a non-affiliate. We believe that the use of the contract price can only result in a windfall to the Cities Service system through the imposition of increased charges on the consumers.
We are not impressed with the argument that the use of the cost-of-service approach unreasonably imposes a new standard. Before the 1953 spinoff to the affiliate, the FPC had treated pipeline production on a cost-of-service basis and had been upheld by the courts. The Supreme Court had warned against intracompany transactions which increased the price to consumers. We agree wth the FPC that at the time of the spin-off to the affiliate Gas Company was, or should have been, aware that gas purchased from the affiliate might be priced on the basis of cost of service. Gas Company knew that the issue of appropriate just and reasonable rates for gas so purchased was reserved in the grant of the original certificate to the affiliate, Cities Service Producing, and in the subsequent rate proceedings. See 1954 order in Docket No. G-2737 and 1956 order approving settlements, 15 FPC 1448, 1455. In our opinion the effect of such reservations could not be dissipated by the alienation of the properties to a third party.
Gas Company contends that the FPC action violates the filed-rate doctrine because its allowance for gas purchase costs must be based on the regulated suppliers’ filed rates and that such rates may not be attacked collaterally. It relies on Montana-Dakota Utilities Co. v. Northwestern Public Service Co., 341 U.S. 246, 71 S.Ct. 692, 95 L.Ed. 912. That case holds that rates on file with the FPC are binding on the parties and the courts until changed by the FPC. The decision is not pertinent here because the filed rates remain the effective rates between Gas Company and Continental. We are concerned with neither rebates nor reparations. The filed-rate doctrine is intended to prevent discriminatory rate payments and may [418]*418not be used as a shield to protect intra-system cost write-ups and related transactions.
We conclude the FPC acted properly and did not abuse its discretion in pricing the gas on the basis of Gas Company’s cost of service. The remaining questions relate to the determination of that cost of service.
The Gas Company attacks on several fronts the cost-of-service determination and the findings on which it is based. We are confronted with an array of figures which are supported or assailed in accordance with the views of the contestants. The municipal intervenors computed cost of service on the basis of the year ending June 30, 1963. Both the Staff and the Examiner adopted their computations. The FPC agreed with the Examiner except that it added $47,500 to the cost because of certain royalties on the Texas production.
During the test year gas sales from the properties to Gas Company were 50,-716,515 Mcf. The total cost is computed at $1,762,560 or 3.470 per Mcf. This figure is adjusted in minor respects and decreased $755,607 on the theory that if Gas Company had retained the properties it would have received a depletion allowance in this amount for federal income tax purposes. The cost of service is computed at $1,053,400 or 2.080 per Mcf. Actually Gas Company paid $4,642,573, or 9.150 per Mcf, for this gas. Thus, Gas Company when it sells the gas to its consumers receives about $3,500,000 a year less than it pays Continental for the same gas.
In arriving at cost of service the FPC allowed $5,400 for exploration and development expense. This represents the average of the actual expenditures for exploration and development for the five years 1959-1963. The Gas Company complains that this allowance is pitifully small and compares it with the allowance of 4.080 per Mcf in the Permian Basin area rate proceedings. See 34 FPC 159, 218, affirmed, Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312. As we see it, the problem of allowances for exploration and development is for .the experts. In Permian the Court said that the FPC is under no obligation to permit recovery of all exploration costs. Ibid at 825, n. 115, 88 S.Ct. 1344. Here the FPC allowed charges actually incurred. The Gas Company seeks to obtain hypothetical development costs not actually incurred. The FPC did not abuse its discretion in rejecting such a request. See Panhandle Eastern Pipe Line Company v. Federal Power Commission, 113 U.S.App.D.C. 94, 305 F.2d 763, 766, cert. denied, 372 U.S. 916, 83 S.Ct. 719, 9 L.Ed.2d 722.
The next problem is the reduction of the cost of service by the percentage depletion allowance claimed by Continental Gas Producing Company in its tax returns. The basis for this treatment is that Gas Company cost of service must be determined as if it still owned the properties. While it is difficult to compare the figures, we accept the Gas Company position that such, reduction amounts to $755,607 annually.
The allowance is computed on the basis of the 9.150 contract rate. Gas Company says that the basis should be 3.470, the cost-of-service value. The theory is that if Gas Company had retained ownership and the gas was priced on the basis of cost of service, the depletion allowance would have been based on the cost-of-service price.
The trouble is that we are dealing with a hypothetical situation. Actually Gas Company gets no depletion allowance because it is not a producer. There is no dispute over the tax benefits available to the producer, Continental. Because the allowance is a proper ingredient in the rate structure, it is necessary to determine the depletion allowance which Gas Company would have received if it had retained ownership.
The Internal Revenue Code, 26 U-S.C. §§ 611 and 613, permits a statutory depletion deduction in computing taxable income for oil and gas wells in [419]*419the amount of 27%% of gross income from the property (less rents or royalties) but not exceeding 50% of taxable income from the property (computed without the allowance for depletion). Internal Revenue Regulations, § 1.613-3 (a), 26 C.F.R. 1.613-3(a), define gross income from the property, in the case of gas wells, as the price at which the gas is sold at or near the well, or if it is not so sold gross income from the property “shall be assumed to be equivalent to the representative market or field price of the * * * gas before * * * transportation.” The acceptance of the theory that for rate making purposes Gas Company still owns the properties means that the gas must be treated as if not sold where produced because Gas Company produced, then transmitted, and then sold. Accordingly, the basis of determination of the depletion allowance for tax purposes is the representative market or field price. See Hugoton Production Company v. United States, 349 F.2d 418, 427, 172 Ct.Cl. 444, and Shamrock Oil & Gas Corporation v. Commissioner of Internal Revenue, 5 Cir., 346 F.2d 377, 379, cert. denied 382 U.S. 892, 86 S.Ct. 185, 15 L.Ed.2d 149.2 We do not equate representative market or field price with the price allowed for rate purposes and determined on a cost-of-service basis.
The record shows that the contract price of 9.150, the figure used by the FPC to determine the depletion allowance, is less than both the going field price and the weighted average cost of gas from the field. As it is thus being credited with less depletion than allowed by the regulations, Gas Company has no cause to complain. Furthermore, there is no evidence in the record of gathering or transportation costs which might justify a reduction from the contract price. See Panhandle Eastern Pipe Line Co. v. United States, Ct.Cl., 408 F.2d 690, 716-717.
The Gas Company would have us take the cost-of-service allowance for rate purposes to be either the “gross income” or the “taxable income” as those terms are used in the pertinent sections of the Internal Revenue Code. We reject the argument. In our opinion the FPC did not abuse its discretion in reducing the cost of service by the depletion allowance based on the contract price. We recognize that the subject of depletion allowance is controversial and that the problem of determining gross income from mineral production continues to be a concern of both the Internal Revenue Service and the courts. We assume that in the event of any change the FPC will give appropriate consideration thereto in a reexamination of Gas Company’s cost of service.
In allocating the depletion allowance to jurisdictional sales the FPC used the factor of 83%. The Gas Company asserts that it should have used 65.7%. This depends on the construction of a stipulation made during the hearing before the Examiner. The pertinent provision is set out in the margin.3 The Gas [420]*420Company argues that the use of the 83% factor is permissive and dependent upon a finding that the negative income tax credit for production should be credited to Gas Company’s income taxes for gathering, storage, and transmission, rather than gas supply. We believe that such a finding is inherent in the FPC treatment of the negative income tax and, accordingly, the stipulation requires the use of the 83% factor.
The FPC used a 6.5% rate of return on the rate base of the producing properties in arriving at the cost of service for the produced gas. Gas Company says that the rate is unsupported by the record and inadequate. An expert witness for the municipal group used the 6.5% rate in his cost calculations. Gas Company says that he was not an expert on the rate of return issue and supported the rate by no economic data. Be that as it may, Gas Company neither cross-examined him on the point nor introduced countervailing evidence. The FPC did not abuse its discretion in relying on the only evidence in the record which touched the point.
The rate is claimed to be inadequate because production of gas carries an inherently greater risk than transportation of gas. The Gas Company points out that in Permian the FPC allowed, and the Court approved, a 12% rate of return. See Permian Basin Area Rate Cases, 390 U.S. 747, 808, 88 S.Ct. 1344, 20 L.Ed.2d 312. Permian dealt with independent production, not pipeline production. The FPC has consistently held that the need for any extra return allowance for production properties of a pipeline must be clearly demonstrated. See El Paso Natural Gas Co., 28 FPC 688, 695-697; Southern Natural Gas Co., 29 FPC 323, 335, 338; and Union Producing Co., 31 FPC 41, 47-48. The record before us does not demonstrate a need for the higher return. To the contrary it shows that the properties are highly developed. The exploration and development expenditures during the test period fail to show a high risk justifying the claimed rate of return.
The FPC computed the jurisdictional rate reduction by dividing the reduction in the jurisdictional cost of service ($2,488,678) by the jurisdictional sales volume (255,794,708 Mcf) for the test year. On this basis the rate reduction should be 0.970 per Mcf. The FPC rounded this off at 1.00. On the quantities involved the additional 0.030 results in a substantial sum. In its petition for rehearing before the FPC, and in its briefs in this court, Gas Company estimates, and FPC does not deny, that the use of the 0.970 figure would reduce the refund requirement by more than $400,000.
The FPC justified its action by commenting that it conformed to Gas Company’s “practice of filing its tariff schedules rounded off to the nearest [loth cent per Mcf.” Nothing before us shows such practice.
Indeed, as heretofore noted, the rates accepted in the issuance of the grandfather certificate, and in increases thereof, went to Moooth of a cent. Gas Company says, and FPC does not deny, that the tariffs of other producers go to Viooth of a cent. The FPC argument that the rounding off was permitted by the stipulation does not persuade us. We see nothing therein which can be construed as an agreement by Gas Company to accept a rounding off to %oth of a cent.
The order of the FPC is affirmed in all respects except the rounding off of the rate reduction to 1.00. The case is remanded with directions to fix the rate reduction at 0.970.