
    HUGOTON PRODUCTION COMPANY v. THE UNITED STATES
    [No. 46-60.
    Decided April 5, 1963]
    
      
      JolmP. Liyscomb for the plaintiff.
    
      Theodore D. Peyser, with whom was Assistant Attorney General Louis F. Oberdorfer, for the defendant. Edward S. Smith and Lyle M. Turner were on the brief.
    Before JoNes, Chief Judge, Reed, Justice {Bet.), sitting by designation, LaeamoRe, Dukfee and Davis, Judges.
    
   Reed, Justice {Bet.),

sitting by designation, delivered the opinion of the court:

This case presents a novel and difficult question relating to the means by which a natural gas producer must compute its percentage depletion allowance under sections 23 (m) and 114(b) (3) of the Internal Revenue Code of 1939, the corresponding and similar provisions of the 1954 Code, sections 611 and 613, and the regulations issued pursuant to these sections. The precise question has been considered only once before, by the Tax Court, in Shamrock Oil & Gas CorP. v. Commissioner, 35 T.C. 979, 1028-40 (1961).

Section 613 permits a taxpayer holding an economic interest in oil or gas wells to take as a deduction from income 27%% 0f his “gross income from the property.” This percentage depletion allowance was first added to the tax laws in 1926, primarily as a means of simplifying the administration of the “discovery depletion” allowance under which depletion had been based on the fair market value of the mineral property after the discovery of the valuable resource.

Where a producer of gas is not integrated with transportation or processing facilities, and thus sells raw natural gas at the wellhead or in the immediate vicinity of the wellhead, it is a simple matter to determine his gross income from the property: it is the gross proceeds from the sale of his gas, less royalty payments. However, where the producer transports the gas from the wellhead and/or processes the gas before sale, thus increasing its sale price, difficulties arise. From the outset, the producer has been held entitled to include in gross income for purposes of the percentage depletion allowance only so much of the proceeds from the sale of the gas as he would have received had he sold the gas at the wellhead.

In the early cases, however, no attention was directed to the problem of the means by which this figure was to be determined. In three of the cases cited in note 6—Brea Cannon Oil Co., Signal Gasoline Corp., Consumers Natural Gas Co.—a fixed percentage of the gross proceeds, and in one—Greensboro Gas Co.—a fixed amount, was stipulated to be attributable to the sale of raw gas at the wellhead.

In 1929 the first regulations bearing on the problem were adopted by tlie Government. Slight amendments were adopted in 1933 and 1936; the amended regulations applicable under the 1939 Code provided as follows:

“In the case of oil and gas wells, ‘gross income from the property’ as used in section 114(b) (3) means the amount for which the taxpayer sells the oil and gas in the immediate vicinity of the well. If the oil and gas are not sold on the property but are manufactured or converted into a refined product prior to sale, or are transported from the property prior to sale, the gross income from the property shall be assumed to be equivalent to the representative market or field price (as of the date of sale) of the oil and gas before conversion or transportation.”

These remain substantially unchanged under the 1954 Code, except that the phrase “(as of the date of sale)” has been deleted. Hence, in the case of an integrated producer, it is the “representative market or field price” at the wellhead which governs. However, the regulations go no farther. They do not define “representative market or field price” nor do they explain how gross income is to be determined if there is no representative market or field price.

The tax years in question in this action for a tax refund are 1952 through 1957. During these years plaintiff, an integrated producer-convertor of natural gas, engaged in the income producing activities detailed in our findings of fact. Suffice it to say that plaintiff sold much of its gas after processing and away from the wellhead. In this action plaintiff contends that gross income for depletion purposes should be computed by multiplying the quantity of gas which it processed and sold in each year by an amount determined to be the representative market or field price for its gas at the wellhead (less royalty payments). The Government, on the other hand, contends that there was no representative price for plaintiff’s gas during the tax years in issue, and therefore that gross income from the property should be calculated by taking the gross proceeds from the sale of plaintiff’s processed gas and its by-products and subtracting therefrom all costs attributable to gathering and processing the gas, a 10% return on the capital invested in these non-producing functions and all royalty payments. Following the terminology in Woodward Iron Co. v. Patterson, 173 F. Supp. 251, 268 (N.D. Ala. 1959), we may refer to the method of computation now urged by the plaintiff as a “market comparison” method, and to that urged by the Government as a “proportionate profits” method.

Hence, we must first determine which of these two methods is to be used. Since we conclude that the regulation requires use of a market comparison method in this case, we reach a perhaps more difficult question. The plaintiff contends that the representative market price is to be determined by considering only contracts for the sale of similar gas at the wellhead entered during each tax year in question. The Government contends that the representative price must be calculated as the weighted average price paid during the year in question for comparable gas at the wellhead under contracts in effect during that year, regardless of the year in which the contracts were entered. As to this issue, we conclude in favor of the Government. Our decision is thus in accord with that reached by the Tax Court in the Shamrock Oil do Gas case, supra.

Turning to the first question, the applicable regulations are of unquestioned validity, and are thus binding upon both parties. The regulations provide that gross income from the property shall be assumed the equivalent of the representative market or field price at the wellhead so that, if there is such a price, it must govern here. The Government does not contend that its proportionate profits formula yields such a representative price, but argues only that there is no such price, so that its alternative method may be utilized. We note that although the proportion of profits formula urged by the Government was expressly adopted in the regulations applicable to mining under the 1939 Code, the formula applied only if a representative market or field price could not be ascertained by use of the market comparison method.

The Government contends that there is no representative or field price for plaintiff’s raw gas at the wellhead. Because there are a variety of factors causing differences in the value of natural gas located within the same or nearby fields, because relatively small proportions of gas are sold at the wellhead, and because almost all such sales are under long-term contracts, it is indeed a difficult task to construct a market price at which particular gas would have sold had it been marketed at the wellhead. The determination of such a price requires that:

“there have been recent, substantial, and comparable sales of like gas to gasoline extracting plants, carbon black plants, and tbe like, from wells in the area whose availability for marketing is reasonably or substantially similar to that of the gas here involved.
* * * the test is what do * * * [purchasers] pay for gas similar in quantity, quality, and availability to market?” Phillips Petroleum Co. v. Bynum, 155 F. 2d 196, 198, 199 (C.A. 5), cert. denied, 329 U.S. 714, 67 S. Ct. 44, 91 L. Ed. 620 (1946).

If evidence of substantially comparable sales can be shown, however, the price so derived is not to be disregarded merely because it is an approximation.

In the present case, the plaintiff presented evidence of sales of gas during the tax years in question sufficiently comparable to its own gas to permit an approximation of the price at which its gas would have sold at the wellhead. The plaintiff presented evidence of 20 contracts for the sale of gas entered during the five tax years in question. Most, though not all, were for sales at the wellhead. A few were for sales from the Hugoton Field, in which the plaintiff’s fields are located, while most were for sales from the ITugoton Embayment, the larger area in which the Hugoton Field is located but which extends into Oklahoma and Texas. Plaintiff presented expert testimony to the effect that the gas involved in the particular contracts was comparable to plaintiff’s gas and that the price obtained in those contracts was the minimum amount which plaintiff would have obtained for the sale of its gas at the wellhead during the respective years.

The Government urges that the contracts do not involve gas comparable in quality and marketability to the plaintiff’s gas. But although the Government points to several differences, it presented no evidence that the differences were significant or would have affected the price which plaintiff could have obtained for its gas. For example, the Government stresses that the sales for the most part were outside the Iiugoton Field; but plaintiff’s experts testified that competition exists throughout the larger Hugoton Embayment and the Government has presented no reason to believe that the sale price would differ because of a difference in location within the Embayment. The Government points out that most of the contracts were for gas located in Oklahoma or Texas, rather than Kansas, and that “[e]ach state has its own particular regulations, restrictions, and taxes relating to the production of natural gas, all of which affect what a buyer is willing to pay for gas.” But the Government made no showing that the price established in any of the contracts offered by plaintiff was affected by any form of state regulation not present in Kansas. We should not reject the testimony of plaintiff’s experts that the conditions of sale in the three states were similar merely on the basis of the Government’s a priori reasoning that somehow the state lines must make a difference.

Finally, it should be noted that in approving a market comparison approach, with its inherent uncertainties, we are not rejecting a method free from difficulties of its own. The proportionate profits method requires determination of the precise point at which the integrated producer-convertor ceases performing the functions of a producer and assumes costs borne only by a processor. Difficult problems of cost accounting must be resolved, and an appropriate rate of return on the non-producing costs must be determined. Still further complexities arise when the taxpayer does not ultimately sell all the processed gas, but uses some for further production. See Shamrock Oil, supra, at p. 1034. We do not say that as an original matter the proportionate profits method might not prove more appropriate or feasible than .the market comparison approach, or that the Commissioner of Internal Revenue could not validly embody this method in its regulations. Indeed, we recognize that despite its complexities, the proportionate profits method has the advantages of being related directly to the taxpayer’s own income and of allowing computation of tax liability by reference only to the taxpayer’s books. Nonetheless, the CIR — not without realizing the possible alternatives and their relative advantages and disadvantages- — lias chosen the market comparison method, and he has defended its application when productive of larger revenues. On the basis of the record compiled in this case, we are convinced that the problem of determining a representative market or field price for this taxpayer’s gas is not of such unusual or inordinate difficulty as to preclude use of the method prescribed as the norm by the applicable regulations.

Having decided that the representative market price must be calculated by the market comparison method, we reach the question as to whether the comparison for a given year is to be only with contracts entered hi that year, or with all contracts under which gas was sold during the year in question.

We find little help in answering this question from the commonly accepted definitions of “market price” or from the many cases interpreting “market price” and terms of like import. Both parties cite the standard definition of “market price” given in Black’s Law Dictionary, which is as follows:

“The price at which a seller is ready and willing to sell and a buyer ready and willing to buy in the ordinary course of trade * * * The price actually given in current market dealings, and actual price at which given commodity is currently sold, or has recently been sold in open market, that is, not at forced sale, but in the usual and ordinary course of trade and competition between sellers and buyers equally free to bargain as established by records of late sales. * * *”

On the taxpayer’s behalf, it is to be noted that the definition refers to “current market dealings,” and that the currency of the transactions from which the market price is derived has been recognized repeatedly as of fundamental importance. On the other hand, the definition speaks of the “actual price at which a given commodity is currently sold.” Where, as in the case of natural gas, the commodity is sold under long-term contracts, the actual sale price at any given time for tbe market as a whole can be derived only from the price being obtained under contracts entered in years both past and present. The basic difficulty with the dictionary definition is that it does not come to grips with a market in which the price for the bulk of the goods sold has been determined in contracts entered into in previous years. Indeed, even among the cases interpreting “market price” as used in oil and gas royalty agreements, we have found none which has ever alluded to the problem raised here.

Nonetheless, it may be significant that the regulation with which we are dealing refers to “representative” rather than “current” market price. While an average price derived from contracts entered in past years which are still in effect may not be current, there is a very real sense in which it is more representative than a price derived only from recent contracts.

“Prices specified in contracts made years ago, but still effective, are just as significant a part of present markets for natural gas as those made yesterday, or those which may be made tomorrow.”

Finally, although “market value” and “market price” have often been used interchangeably, the two have different meanings. It would be consistent with the differences between these terms to hold that although the market value of gas at the wellhead is the amount that could be obtained for it under a new contract at any given time, the representative price is the price which is in fact being obtained under all existing comparable contracts.

Moreover, there is good reason to believe that the inclusion of prices established in prior years is consistent with the understanding in the gas industry of such a term as “representative market or field price.” One indication of this understanding is to be found in the history of the Federal Power Commission regulation of the rates of interstate gas pipeline companies. For a pipeline transporting gas produced by itself or by a subsidiary, the Commission at one time accepted the proposal that the field price of the gas (as determined by sales of the independent producers), rather than the actual cost of the gas to the pipelines, be used as an element in computing the pipeline’s rate base. To determine “field price” for this purpose, it was recognized both by the pipeline companies and by the Commission that prices at which independent producers were selling gas had to be taken into account without regard to when the controlling contracts had been entered:

“Averaging contract prices. — With field prices going up and expected to advance in the future, it would generally be most advantageous to the pipelines to be allowed the prices specified in the most recently negotiated contracts for gas of similar quality and other specifications. But this would present serious questions of equity with respect to many independent producers of gas who are bound to old contracts providing for substantially lower prices. Under this standard, a pipe-line company would be allowed increasing amounts on its own production as current prices increased, notwithstanding the fact that it might be buying most of its gas requirements at substantially lower prices fixed by long-term purchase contracts.
It would seem to be clearly more equitable to take into account, by some appropriate weighted average procedure, all of the effective contract prices that might be relevant to the particular situation. The fairness of this principle has, in fact, been recognized by spokesmen for the pipeline industry in their testimony regarding the application of the field price standard. As stated clearly by an executive for one of the large pipe-line companies:
£I think it should be the average field price established by arm’s length bargaining between that pipeline company or similar pipe line companies purchasing gas in and around that field * * *. Certainly that average price is a result of years of bargaining and sets a fair value for the gas.’ ”

A second indication of this understanding is provided by the interpretation which the plaintiff itself has placed on an escalator provision appearing in the contract under which plaintiff sells its processed gas to the Kansas Power & Light Company. The contract establishes an initial price of 12 cents per Mcf, exclusive of that used by the purchaser for its power plants, but provides for subsequent price adjustments on the following basis:

“The Twelve (120) Cents price will be related to the weighted average price paid for natural gas purchased in the Kansas portion of the Hugoton Field by the following companies during the year 1948:
Cities Service Gas Company
Colorado-Interstate Gas Company
Northern Natural Gas Company
Panhandle Eastern Pipe Line Company
The said weighted average price for gas purchased by the above-named companies will be again determined for the year 1958; the increase, if any, in the weighted average price paid by the above-named companies will be added to the base price of Twelve (120) Cents per MCF and shall determine the price for the next five-year period. The weighted average price shall again be determined for the purchases by the above-named companies in 1958, and the difference between the weighted average price for 1948 and 1958 shall be added to the base price of Twelve (120) Cents per MCF. However, in no event shall said price be less than Twelve (120) Cents per MCF.”

One of the plaintiff’s experts testified that in computing the “weighted average price” under the above contract, contracts in effect during the relevant years were considered regardless of the year in which the contracts were entered. The concern under the above contract, as under the depletion regulations, is to determine what in fact is being paid for comparable gas at a given time; we see no reason why a representative price should not, while an average price should, be based on sales transacted under contracts entered in previous years.

In any event, the prime question in defining representative market or field price must be the purpose for which such a price must be calculated.

“While the act of Congress and regulations adopted in pursuance thereof must be construed according to their plain import, it should be borne in mind in determining the amount of the depletion allowance that such allowance is intended to represent the amount of capital recovered in the product produced by the well, that is the value of the raw product. * * *”

We are seeking the “constructive income” from the raw gas at the wellhead. Cf., United States v. Cannelton Sewer Pipe Co., 364 U.S. at 86. We want to know the price for which the taxpayer would have sold its gas at the wellhead in each tax year in issue had its operations terminated at that point. The taxpayer argues that for this purpose we must take the price which it could have obtained under a long-term contract entered in each tax year in question. But it is obvious, as the Government points out, that the taxpayer could not have entered a new long-term contract for the sale of its gas in each of these years. To have sold its gas at the wellhead, the plaintiff would have had to enter a contract in one year, and the price fixed in that contract (modified by any escalator provisions therein) would have controlled in each of the subsequent years.

The non-integrated producer must enter such long-term contracts and obtains the benefit of rising prices only to the extent provided in any escalator clause in his contract. Hence, the weighted average method urged by the Government will tend to equalize the depletion allowance as between integrated and non-integrated producers. In holding that the depletion allowance of an integrated miner-manufacturer must be computed on the basis of the taxpayer’s constructive income from the raw mineral produce, the Supreme Court in Cannelton Sewer Pipe Co. stated:

“Bespondent’s [taxpayer’s] formula would not only give it a preference over the ordinary nonintegrated miner, but also would grant it a decided competitive advantage over its nonintegrated manufacturer competitor. Congress never intended that depletion create such a discriminatory situation. As we see it, the miner-manufacturer is but selling to himself the crude mineral that he mines, insofar as the depletion allowance is concerned.” 364 U.S. at 87. [Emphasis added.]

If it be argued that since plaintiff is integrated he is not forced to enter long-term contracts for sale at the wellhead and thus may be able to benefit directly from increases in market price, there are at least two answers. Under the market comparison, rather than the proportionate profits, method, this fact is irrelevant. We look to see what price plaintiff would have obtained for its gas at the wellhead if unintegrated, and we must disregard any increases in gross income which he obtains by virtue of the fact that he is integrated. Moreover, the fact of the matter is that the plaintiff does sell the bulk of its processed gas under a long-term contract, which includes the escalator clause set out above, so that it does not obtain the full benefit of all increases in currently established market prices.

The plaintiff contends that to base the representative price on contracts entered only in the current tax year would not discriminate in favor of the integrated producer because he will fare less well during periods of falling prices than those protected by long-term contracts. Indeed, it must be recognized that if prices were stable or fluctuated evenly over reasonably short cycles, it would make little or no practical difference whether the view of the Government or of the plaintiff was adopted. But the plaintiff is asking the court to close its eyes to the steady upward trend in the price of natural gas since the end of the second world war, and this we refuse to do. Whether or not the price of gas will fall in the future, it is at least possible that it will not and that the plaintiff’s method, based only on contracts entered in the tax year in question, would thus continually yield a higher representative price than is in fact being obtained by uninte-grated producers selling gas at the wellhead under contracts entered over many years. On the other hand, whatever the course of future prices, this is an impossibility under the averaging method urged by the Government.

Plaintiff points out that contracts for the sale of gas now generally include escalator clauses, providing for price increases to correspond with current market price increases. But the existence of these clauses does not indicate that the Government’s averaging method saddles plaintiff with archaic contract prices which no longer govern. The effect of the escalator clauses will be taken into account in computing the price obtained under the particular contract for the tax year in question. Contracts entered far in the past and without such clauses will of course tend to reduce the representative price; but we see no basis for concluding that because particular contracts were unfavorable to the seller they should not be included in the computations.

Finally, it may be observed that the weighted average method increases the number of contracts which bear on the market price of the plaintiff’s gas. Hence it will not be necessary to rely on six or less contracts for each year in question, and the larger sampling should provide greater assurance that the price derived is in fact representative.

During the hearing in this case, the Government offered as evidence of the representative price of taxpayer’s gas, contracts which antedated the tax years in question. The commissioner rejected this evidence on the theory that such contracts were not relevant to the representative price for the given tax years. Since we have held that such contracts must be taken into account, and the representative price for each tax year calculated as the average price, weighted by quantity, of comparable gas sold in the locality under a fair selection of contracts in effect during each year, we must, and do, remand to the commissioner for further findings as to the representative market or field price of the taxpayer’s gas so calculated.

FINDINGS OP PACT

The court, having considered the evidence, the report of Trial Commissioner Mastín G. White, and the briefs and argument of counsel, makes findings of fact as follows:

Introductory 8 tatement

This action was filed by the plaintiff, a producer of natural gas, to recover income taxes paid for the calendar years 1952 to 1957, inclusive. The Government filed a counterclaim. The problem in the case is to determine the amount of the plaintiff’s gross income on which the deduction for percentage depletion is to be computed and allowed for each of the years involved in the litigation.

Under Eule 38 (c), the trial was limited to the issues of law and fact relating to the right of the parties to recover, the determination of the amounts of recovery, if any, being reserved for further proceedings.

1. (a) The plaintiff is a Delaware corporation, having been incorporated on September 22,1948. Its principal office is located at Garden City, Kansas.

(b) At all times material herein, the plaintiff was engaged in the production and sale of natural gas from wells in which it had an economic interest, located in the Hugoton Field in the State of Kansas. The plaintiff sells natural gas only in the State of Kansas and is not subject to the jurisdiction of the Federal Power Commission.

(c) The plaintiff also was, and still is, engaged in tbe extraction and sale of natural gasoline and other liquefied products from the natural gas produced by it from its wells in the State of Kansas.

(d) The plaintiff’s books of account were maintained and its tax returns filed on the accrual basis for a taxable year ending on December 31.

2.The plaintiff’s income tax returns for the calendar years 1952 to 1957, inclusive, were filed with the District Director at Wichita, Kansas. Such returns disclosed income tax liabilities, all of which were paid to the District Director, as follows:

•year. Tam liability
1952_ $730, 002.27
1953_ 938,212.49
1954_ 923,818.85
1955_ 1, 214,590. 44
1956_ 1,458,364.63
1957_ 1, 641,496.00

3.Thereafter, on audit of these returns by the Commissioner of Internal Bevenue (hereinafter referred to as “the Commissioner”), additional income taxes were determined to be due from, or credits or refunds allowable to, the plaintiff. The additional taxes (exclusive of interest) were paid by the plaintiff to the District Director, and the credits or refunds were allowed, in the following amounts:

4.(a) Upon its incorporation, the plaintiff acquired undeveloped oil and gas leases which, as a whole, covered a block of approximately 97,000 acres of land lying in Stevens and Grant Counties, State of Kansas, and in the Kansas portion of the Hugoton Field. (These leases will hereafter be referred to collectively in the findings as “the Hugoton Lease Block.”) The Hugoton Lease Block covers an area that is approximately 24 miles in length and 15 miles in width at its widest point.

(b)As of the end of each of the years during the period 1950-1957, the plaintiff had in the Hugoton Lease Block gas wells capable of production, as follows:

Number of Date: wells
December 31, 1950- 60
December 31, 1951- 110
December 31, 1952_ 135
December 31, 1953- 140
December 31, 1954- 151
December 31, 1955- 152
December 31,1956- 153
December 31, 1957_ 156

(c) In general, the plaintiff’s wells were spaced 640 acres apart.

(d) All of these wells for the years 1950 through 1955 were producing from formations of the Permian Age. Of the wells capable of production in 1956 and 1957, 152 were producing from the formations of the Chase Group of the Permian Age. The other wells in 1956-1957 were from formations below the Chase Group but still of the Permian Age. These latter wells were capable of production, but none of them actually produced gas during the years in issue.

(e) The wells drilled by the plaintiff to the formations of the Permian Age were to the approximate depth of 2,500 to 3,000 feet.

(f) The natural gas in the Permian Age formations is at a pressure of about 320 pounds per square inch gauge.

5. (a) The Hugoton Field (see findings 1(b) and 4(a)) consists of the gas-producing areas of the Permian Age formations within the Hugoton Embayment. The Plugoton Field contains approximately 3 million acres, and is located in southwestern Kansas and in the Oklahoma and Texas Panhandles.

(b) The Hugoton Embayment is the more shallow part of the old Anadarko Sea. It covers a large area of about 25 million acres in the Texas Panhandle, western Oklahoma, western Kansas, and eastern Colorado.

(c) The Hugoton Embayment is productive of oil and gas, and has several major producing areas in it. The gas-producing areas in the Hugoton Embayment do not represent a common reservoir, but they are generally classified as a common geographical source of supply. Several pipeline companies purchase natural gas in the Hugoton Embayment in competition with each other.

(d) Production of natural gas in the Hugoton Embayment comes from both Permian and pre-Permian formations. Production of gas in the Hugoton Field portion of the Hugo-ton Embayment comes only from Permian Age formations.

6.During the years 1951 through 1957, the plaintiff produced the following volumes of natural gas, stated in Mcf (1,000 cubic feet), from its gas wells in the Hugoton Lease Block:

Calendar year: Volume in Mcf
1951_ - 20,071,110
1952_ . 25, 807, 624
1953_ _ 27,405, 965
1954_ - 29, 010, 328
1955_ . 30, 578, 506
1956_ . 33, 597, 016
1957_ - 37,679, 061

The volume figures in this table are stated in terms of a uniform pressure base of 14.65 pounds per square inch absolute (p.s.i.a.).

7. (a) In the natural gas industry, the heating value of natural gas is defined in terms of British thermal units (B.t.u.). One B.t.u. is the amount of heat that is required to raise 1 pound of water 1 degree Fahrenheit, beginning at 39 degrees Fahrenheit.

(b) There is a wide variation in the B.t.u. content of the natural gas produced in the Hugoton Embayment, the range being from a low of about 550 B.t.u. to a high of about 1,160 B.t.u. The plaintiff’s natural gas from the Hugoton Lease Block averages slightly in excess of 1,000 B.t.u. It is about average for the Hugoton Embayment.

8. During the years involved in this case, the plaintiff held as lessee 525 separate leases on its Hugoton Lease Block. The following summary shows the nature of the plaintiff’s obligations under various groups of its leases to account to its lessors for the one-eighth royalty on natural gas produced:

Group “A”:
The Lessee shall monthly pay Lessor as royalty on gas marketed from each well where gas only is found, one-eighth (%) of the proceeds if sold at the well, or if marketed by Lessee off the leased premises, then one-eighth (%) of its'market value at the well.
Total number of Group “A” leases — 417 Group “B”:
Lease modification by Gas Unitization Agreements. Lessee is hereby authorized by Lessor to connect such gas well or wells as may be completed on the unitized area and deliver gas therefrom on such terms and to such line or lines as Lessee may choose, including lines of Lessee, its successors or assigns, and the gas from said well or wells shall become the property of the Lessee at the mouth of the well. The Lessor’s total royalty for gas from wells where gas only is produced shall be one-eighth (%) of the market value at the mouth of the well.
Total number of Group “B” leases — 70
Approximate acreage covered by Group “A” and Group “B” leases — 84,740.51 Group “C”:
The Lessee shall pay Lessor, as royalty, one-eighth (y8) of the proceeds from the sale of the gas, as such, for gas from wells where gas only is found.
Total Group “C” leases — 16.
Approximate acreage covered — 6,034.64 Group “D”:
The Lessee shall pay Lessor as royalty one-eighth (%) of the proceeds from the sale of gas as such at the mouth of the well where gas only is found.
Total Group “D” leases — 10
Approximate acreage covered — 1,372.00 Group “E”:
Modified by Separate Agreement. The mineral owner’s total royalty for gas from wells where gas only is produced shall be one-eighth (%) of the market value at the mouth of the well.
Total Group “E” leases — 6
Approximate acreage covered — 2,400.00 Group “F”:
To pay to the Lessor, the equal one-eighth (%) of the gross proceeds, payable quarterly each year for the gas from any such well where gas only is found.
Total Group “F” leases — 1
Approximate acreage covered — 640.00 Group “G”:
To pay the Lessor the equal one-eighth (%) of the net proceeds, payable quarterly each year from the gas from any such well where gas only is found.
Total Group “G” leases — 1
Approximate acreage covered. — 160.00 Group “H”:
To pay Lessor for gas from each well where gas only is found the equal one-eighth (%) of the gross proceeds at the prevailing market rate.
Total Group “H” leases — 1
Approximate acreage covered — 320.00 Group “I”:
The production company shall pay the Santa Fe for gas, including casinghead gas or other gaseous substances, produced and sold or used off the premises or in the manufacture of gasoline or other products therefrom, the market value at the well of its proportionate part of the %th of the gas so sold or used, provided that on gas, including casinghead gas sold at the wells, the royalty shall be its proportionate part of the %th of the amount realized from said sale.
Total Group “I” leases — 1
Approximate acreage covered — 5.68 Group “J”:
Government Leases.
Total Group “J” leases — 2
Approximate acreage covered — 141.69

The reason for the variety of the plaintiff’s lease obligations with respect to its lessors was that these leases had been acquired by prior lessees over an extended period of time, and different lease forms had been used.

9. (a) The plaintiff’s natural gas from the Hugoton Lease Block contains liquefiable hydrocarbons known as propane, isobutane, normal butane, isopentane, normal pentane, normal hexane, and hexane plus. These are referred to as the heavier hydrocarbons in the gas. The plaintiff’s natural gas, because of the presence therein of nitrogen, an inert, is relatively lean from the standpoint of the liquefiable hydrocarbons that can be extracted. These liquefiable, heavier hydrocarbons are not necessary to natural gas when used as a fuel, and they have a recognized market value when separated from the raw gas. Their removal in whole or in part lowers the B.t.u. value of the remaining gas. They have not been removed from, but are still part of, the raw gas when the latter emerges at the top of the wells.

(b) At Ulysses, Kansas, the plaintiff at all material times maintained dehydration equipment for the purpose of extracting the water content from its natural gas.

(c) Also, at Ulysses, Kansas, tbe plaintiff maintained absorption and fractionation facilities for tbe purpose of extracting liquefiable products from its natural gas. During tbe years 1951 to 1957, inclusive, tbe plaintiff extracted natural gasoline, butane, propane, and butane-propane mixture from tbe natural gas treated in its plant.

10. Tbe raw gas from tbe plaintiff’s wells in tbe Hugoton Lease Block flows to tbe surface of tbe wells due to expansion or pressure differential. A valve on each wellhead controls tbe flow. At the surface, tbe gas passes from tbe wellhead into a 414 inch (outside diameter) pipe on tbe lease, and this pipe leads to meter drips approximately 75 feet away from the wellhead. Tbe meter drips are simple tanks connected to tbe line in order to accumulate free liquids in tbe gas. Tbe free liquids fall out in dropouts connected with the tanks. These free liquids condense out of tbe gas stream due to the change in temperature as tbe gas comes out of tbe well. They consist of water and some of tbe heavier hydrocarbons. This condensation is common to all of tbe plaintiff’s wells. Tbe removal of these free liquids is necessary because otherwise they would cause blockage in tbe line due to freezing. It is done before tbe gas is metered because the presence of the free liquids would cause incorrect measurements of the gas.

11. After tbe free liquids in tbe plaintiff’s gas have been removed in tbe drip tanks, tbe raw gas from each well passes to tbe metering equipment, which is located immediately beyond tbe meter drips and approximately 95 feet away from each wellhead, where tbe gas is metered. Tbe meter for each well is located in a shed. Tbe metering is done in thousands of cubic feet (Mcf) at a uniform pressure base. Metering records for each separate well are kept by tbe plaintiff. Tbe metering is done away from tbe wellhead in order to achieve accuracy of readings, for safety reasons, and to allow room to work on either tbe metering equipment or tbe well, as might be necessary. Tbe practice of tbe plaintiff in metering its raw gas away from tbe separate wellheads is in accordance with that of tbe natural gas industry.

12. (a) The purpose of metering separately tbe raw gas from each well is to determine tbe amount of gas produced from each, well in order to make royalty payments and to know whether the well is being produced in accordance with the proration orders of the Kansas State Corporation Commission, which has jurisdiction over the production and, conservation of oil and gas in Kansas. Separate metering also is of assistance in determining the condition of the various wells. It is of no significance in the ultimate sales of the plaintiff’s gas.

(b) In the Hugoton Embayment, it is common practice, where gas is purchased at the wellhead, for the buyer to install a meter at or near the wellhead to measure the gas.

13. (a) During the years 1951 through 1957, after the plaintiff’s raw gas from each well had been separately metered, most of the raw gas was moved at field pressure from the wells through a pipeline system to a central point in the Hugoton Lease Block. The well that was most remote from the central point in the plaintiff’s gathering system was located about 17 miles away. The following tabulation shows the approximate number of miles of pipe used in this system as of various dates during the period 1951-1957:

Miles of Date: pipe
June 30, 1951_ 94. 2
April 30, 1952_135.1
December 31, 1952_159.4
December 31, 1953_163. 7
December 31, 1954_170
December 31, 1955_170. 8
December 31, 1956_170. 8
December 31, 1957_176

The pipe that was employed in the movement of the gas ranged from 4 inches in size to 24 inches in size.

(b) The plaintiff’s gas was gathered and moved to one point in order that it might be dehydrated for delivery to the Kansas Power and Light Company, a Kansas corporation, under a contract of sale made prior to 1951 (see findings 27-30), and in order that liquefiable hydrocarbons might be removed from the raw gas. The processing of the gas after it was moved to a central point will be described in subsequent findings. (The portion of the plaintiff’s pipeline system from the outlet side of the metering sheds to the points where the gas was delivered and sold will sometimes be referred to hereafter in the findings as “the field lines.”)

(c) No change occurred in the raw gas during the gathering process described in paragraph (a) of this finding.

14. After most of the plaintiff’s gas had been brought to a central point during the period 1951-1957, as indicated in finding 13, it was turned over to the Kansas Power and Light Company, which operated a compressor station at that place. That corporation passed the gas through scrubbers, which cleaned the gas of any free water and dirt. The gas was then compressed by the Kansas Power and Light Company and passed to the plaintiff’s dehydration plant, which was adjacent. The compressor station was not operated in the smnmertime.

15. When the plaintiff’s raw gas was passed to the plaintiff’s dehydration plant, it still had in it water in a vapor state. The dehydration plant consisted of a vessel that contained a series of trays with bubble caps. The raw gas entered the bottom of the vessel and passed through the trays, where there was a level of diethylene glycol. This diethylene glycol had the ability to absorb and did absorb the water in the gas. The water turned into a liquid state in the glycol solution. The water-free gas then left the top of the vessel, while the diethylene glycol and water combination left the bottom of the vessel and was taken to a regeneration cycle, where the water was driven off. The glycol was then reused.

16. From the top of the dehydration plant, the water-free raw gas went to the plaintiff’s absorption tower or vessel. Up to this point, the plaintiff had not extracted the lique-fiable hydrocarbons from the raw gas. Inside the absorption tower was a series of trays with bubble caps. Each tray held a level of lean absorption oil. The raw gas entered the bottom of the absorption tower and passed up through the trays, coming in contact with the lean oil. This oil absorbed the heavier hydrocarbons into it in liquid form. The hydrocarbons thus absorbed were the hexanes, pentanes, butanes, propanes, and some ethane. The absorption oil, containing the hydrocarbons in liquid form, went to the bottom of the tower, where it was removed for further processing. The gas, after the extraction of the liquefiable hydrocarbons in the absorption tower, passed through the top of the absorption tower.

17. The gas, after passing out the top of the absorption tower, was known as residue gas. The extraction of the liquefiable hydrocarbons from the gas through the absorption process lowered the heat value or B.t.u. content of the gas.

18. The absorption oil, containing the absorbed hydrocarbons, passed out the bottom of the absorption tower to a heat exchange, where the ethane, which had no commercial value, was separated. The remaining oil and hydrocarbons then went to a lean oil still, where, by an increase in temperature and a reduction in pressure, the hydrocarbons in the oil were returned to vapor form. At this point, the hydrocarbons were once more gaseous and commingled. Further processing at another place was necessary in order to liquefy the hydrocarbons again and separate them from each other so that they would be commercially valuable.

19. (a) The reduction of the gaseous hydrocarbons to a liquid form again, and their separation from each other, were done in the fractionation phase of the plaintiff’s gasoline plant. That plant first went into operation in 1951. After the hydrocarbons in vapor form were condensed into liquid form, the next step was to separate the propanes from the other hydrocarbons in a depropanizing tower. The remaining liquid then passed to a debutanizing tower, where some of the butanes were separated. The remaining liquid was 18-pound gasoline or natural gasoline. After being separated, the liquid hydrocarbons were stored in stock tanks. No chemical change was effected in this fractionation process, and the chemical formulas of the hydrocarbons remained the same.

(b) Natural gasoline is used by industry principally as a blending agent to give motor fuel the required degree of volatility.

(c) The butanes are used in the manufacture of rubber and as a fuel. They are also used to make iso-octane, a high anti-knock compound.

20. In the natural gas industry, there are two recognized methods of separating liquefiable hydrocarbons from raw gas. The first method, a simple mechanical separator at the wellhead, is used when the liquefiable hydrocarbons are present in liquid form. The second method, which involves absorption, adsorption, or refrigeration, is used when the liquefiable hydrocarbons are present in the raw gas in a vapor state, as they were in the gas produced by the plaintiff. The second method can be used, and is used, by producers of natural gas, by purchasers of natural gas, and by independent processors. It is not economically feasible to perform such a separation at each well.

21. During the years 1951 to 1957, inclusive, the plaintiff treated the following amounts of its produced natural gas (stated in Mcf at a pressure base of 14.65 p.s.i.a.) in its dehydration equipment and absorption facilities at Ulysses, Kansas:

Tear: Volume in Mcf
1951. 12, 809, 949
1952. 26,194, 387
1953. 25,360,675
1954. 24,207, 805
1955. 25, 044,978
1956. 23,369,293
1957. 24,210,427

22.(a) During the years 1951 to 1957, inclusive, the plaintiff, by reason of the treatment of natural gas in its absorption facilities at Ulysses, Kansas, and the separation of the recovered liquids in the fractionation facilities, produced natural gasoline, butane, propane, and butane-propane mixture. The following tabulation states in gallons the amounts of these commodities sold by the plaintiff during the years 1951 through 1957, all such amounts having been produced by the plaintiff:

(b) All the products mentioned in paragraph (a) of this finding as having been sold by the plaintiff during 1951-1957 were sold to the Warren Petroleum Corporation, a Delaware corporation. The following table shows the total amount and the amount per Mcf (on a pressure base of 14.65 p.si.a.) that the plaintiff received for such products each year:

23. The amount reflected on the plaintiffs books as a charge to products extraction operation (gasoline plant) for the volumes of natural gas lost or consumed as fuel during each of the years 1951 to 1957, inclusive, is as follows:

Tear: Amount
1951. $48,913
1952. 93,848
1953. 111, 190
1954. 99, 034
1955. 90,639
1956. 86,342
1957. 86, 770

24. The daily rated designed capacity of the plaintiff’s gasoline plant is 90 million cubic feet of natural gas. Over a given year, the actual load factor of the plant varies from approximately 15 million cubic feet of gas per day to 150 million. This is occasioned by the needs of the plaintiff’s principal customer, the Kansas Power and Light Company. When the plaintiff’s gasoline plant is operated beyond its designed capacity, the plant efficiency suffers and the extraction of hydrocarbons, particularly propane, is reduced.

25.The plaintiff’s total investment in its absorption and fractionating facilities at Ulysses, Kansas, stated at cost as of December 31 of each of the years 1951 to 1957, inclusive, and the reserve for depreciation on such investment as of the same date, are shown in the following tabulation:

26.The cost to the plaintiff for the years 1951 to 1957, inclusive, of operating its gasoline plant (including depreciation) at Ulysses, Kansas (without segregation between the absorption facilities and the fractionating facilities), is set forth in the following tabulation:

Year: Cost of operation
1951_$177,871
1952 _ 868,276
1953 _ 388,676
1954_ 360,062
1955 _ 350,625
1956 _ 344,734
1957 _ 371,207

27.(a) Under the date of October 18, 1948, the plaintiff entered into a contract with the Kansas Power and Light Company, under which the former agreed to sell to the latter at least 80 percent of certain estimated volumes of natural gas produced from its wells in the Hugoton Lease Block. The minimum heating value of all gas delivered was not to be less than 950 B.t.u. The plaintiff agreed, among other things, to construct and operate a dehydration plant to dehydrate the gas sold, and to construct, operate, and maintain a gasoline plant of sufficient capacity to handle the estimated volumes to be sold. In return, the Kansas Power and Light Company agreed to reimburse the plaintiff for such dehydration at the rate of $0.0015 per Mcf on a 14.9 p.s.i.a. saturated pressure base.

(b) The contract term was 15 years, from November 1, 1949, to November 1, 1964.

(c) The initial price to be paid for gas under the contract, exclusive of that used by the purchaser for its power plants, was 12 cents per Mcf (12.005 cents on a 14.65 p.s.i.a. pressure base). As to subsequent price adjustments for this gas, the contract provided as follows:

The Twelve (120) Cents price will be related to the weighted average price paid for natural gas purchased in the Kansas portion of the Hugoton Field by the following companies during the year 1948:
Cities Service Gas Company
Colorado-Interstate Gas Company
Northern Natural Gas Company
Panhandle Eastern Pipe Line Company
The said weighted average price for gas purchased by the above-named companies will be again determined for the year 1953; the increase, if any, in the weighted average price paid by the above-named companies will be added to the base price of Twelve (120) cents per MCF and shall determine the price for the next five-year period. The weighted average price shall again be determined for the purchases by the above-named companies in 1958, and the difference between the weighted average price for 1948 and 1958 shall be added to the base price of Twelve (120) Cents per MCF. However, in no event shall said price be less than Twelve (120) Cents per MCF.

(d) For the gas consumed by the Kansas Power and Light Company in its power plants, the price under the contract was to be 15 cents per million British thermal units when the price of coal was $5.50 per ton. Increases or decreases in this price were keyed to variations of 5 cents per ton upward or downward in the price of coal.

(e) In 1957, the recoverable reserves underlying plaintiff’s 152 wells that were producing in that year were in the order of a trillion and a quarter cubic feet on a 14.65 p.s.i.a. pressure base.

28. The initial delivery of gas to the Kansas Power and Light Company under the contract referred to in finding 27 was made on November 1,1949.

29. During the years 1951 to 1957, inclusive, the plaintiff sold to' the Kansas Power and Light Company, under the contract referred to in finding 27, residue natural gas at the outlet side of the plaintiff’s absorption facilities. The annual volume sold (expressed in Mcf at a pressure base of 14.65 p.s.i.a.), the total dollar proceeds each year, and the price per Mcf each year (on a pressure base of 14.65 p.s.La.) are shown in the following tabulation:

30. During the years 1951 to 1957, inclusive, the plaintiff received from the Kansas Power and Light Company, pursuant to their contract, the following amounts for dehydrating in the plaintiff’s dehydration equipment the natural gas sold to the Kansas Power and Light Company:

Xear: Amount
1951 $33, 203
1952 37, 820
1953 36, 384
1954 34,897
1955 36,104
1956 33, 702
1957 34, 954

31. (a) During the years 1953 through 1957, the plaintiff sold to the Columbian Carbon Company, a Delaware corporation, surplus raw natural gas. The annual volume sold (expressed in Mcf at a pressure base of 14.65 p.s.i.a.), the total dollar proceeds received therefor each year, and the price per Mcf each year, are shown in the following tabulation:

(b) Prior to August 1,1957, these sales to the Columbian Carbon Company were made just off the northeast part of the Hugoton Lease Block. Beginning August 1, 1957, the gas was carried by the plaintiff off the Hugoton Lease Block through a 514-mile 8-inch pipeline to the Columbian Carbon Company’s plant. None of this gas was compressed prior to sale.

32.During the years 1954, 1956, and 1957, the plaintiff sold to Panhandle Eastern Pipe Line Company, a Delaware corporation, raw natural gas in the Hugoton Lease Block. The annual volume sold (expressed in Mcf at a pressure base of 14.65 p.s.i.a.), the total dollar proceeds received therefor each year, and the price per Mcf each year, are shown in the following tabulation:

33.During the years 1951 through 1957, the plaintiff made miscellaneous field sales of raw natural gas in the Hugoton Lease Block. These were sales to farmers in the Hugoton Lease Block for irrigation purposes. The plaintiff did not solicit the sales, and they were made only to keep good relations with the landowners. Generally, delivery of the gas was on the individual leases. The gas was not compressed prior to sale. The annual volume sold (expressed in Mcf at a pressure base of 14.65 p.s.i.a), the total dollar proceeds received therefor each year, and the price per Mcf each year, are shown in the following tabulation:

34.During the years 1951 through 1957, the plaintiff made no sales of raw or residue natural gas from natural gas produced from the Hugoton Lease Block other than the sales mentioned in findings 29,31,32, and 33.

35. The plaintiff’s total investment in that part of its field lines (see finding 13) lying in section 12 of Township 29 South, Range 37 West, and in sections 7,8,9,10,11, and 12 of Township 29 South, Range 36 West, through which raw natural gas sold to the Columbian Carbon Company was moved in effecting delivery, and the reserve for depreciation on such investment, are shown in the following tabulation as of December 31 for each of the years 1953 through 1957:

(The portion of the plaintiff’s field lines mentioned in this finding will be referred to hereafter as “the Columbian Carbon spur line.”)

36. (a) The plaintiff’s total investment at cost in its field lines (including the Columbian Carbon spur line, rights of way, and sales measuring station equipment), in its lease lines (i.e., the lines from the wells to the metering sheds (see findings 10 and 11)), and in its field measuring station structures and equipment (see finding 11), is shown in the following tabulation as of December 31 for each of the years 1951 through 1957:

(b) The reserve for depreciation on each of the investments referred to in paragraph (a) of this finding is shown in the following tabulation as of December 31 for each of the years 1951-1957:

37. (a) The annual cost (including depreciation) to the plaintiff for the years 1951 to 1957, inclusive, of moving its raw natural gas from the outlet side of its field measuring stations in the Hugoton Lease Block to the various points of sale described in findings 29, 31, 32, and 33 is shown in the following tabulation:

Year: Cost
1951. $83,472
1952. 146,656
1953. 169,612
1954. 159,367
1955. 186,524
1956. 194,573
1957. 226, 629

(b) The annual cost (including depreciation) to the plaintiff for the years 1951 to 1957, inclusive, of moving its raw natural gas (i) from the plaintiff’s wells in the Hugoton Lease Block to the outlet side of its field measuring stations, . (ii) from the outlet side of its field measuring stations to the plaintiff’s dehydration plant or to the Columbian Carbon spur line, and (iii) through the Columbian Carbon spur line to the point of sale described in finding 31, is shown in the following tabulation:

38. Tlie plaintiff accounts to its lessors or royalty holders in the Hugoton Lease Block for one-eighth of the gas produced. Its initial royalty price established in the Hugoton Lease Block was 7.1468 cents per Mcf on a 14.65 p.s.i.a. pressure base. This was in accordance with an order of the Kansas Corporation Commission prohibiting any producer in the Hugoton Field from ascribing less than 8 cents per Mcf on a 16.4 p.s.i.a pressure base for any gas taken from the field. The plaintiff paid the minimum price required to all its lessors, irrespective of the variations in the lease obligations as to royalties. This price was paid until January 1, 1951. The plaintiff was sued by some of its lessors for increased royalties, and negotiated an increase to 9.833 cents per Mcf on a 14.65 p.s.i.a. pressure base. This new price remained effective until January 1, 1954, when a new minimum price order by the Kansas Corporation Commission of 11 cents per Mcf on a 14.65 p.si.a. pressure base became effective.

39. Effective November 1, 1954, the price at which the plaintiff sold residue gas to the Kansas Power and Light Company for resale was increased 3.26 cents per Mcf on a pressure base of 14.65 saturated p.s.i.a. This price increase was in accordance with the portion of the contract referred to in finding 27 that provided for price changes in accordance with changes in the weighted average price paid by four pipeline companies. The weighted average price paid by those companies for natural gas purchased in 1953 in the Kansas portion of the Hugoton Field was $0.0813314 per Mcf on a 14.65 p.s.i.a. pressure base, which price represented an increase of $0.0326850 per Mcf over the price for 1948, as stated in finding 27.

40. (a) Under the date of June 17, 1955, Carl S. Matzen and his wife, Mary S. Matzen, (hereinafter referred to as “the Matzens”) instituted a suit against the plaintiff in the District Court of Grant County, Kansas, for the alleged failure of the plaintiff to pay the correct amount of royalties under the oil and gas lease held by the plaintiff on the Matzens’ land in Grant County, Kansas. The Matzens’ land was part of the Hugoton Lease Block. The lease on their land contained (among other provisions) the following provision with respect to the payment of royalties:

The lessee [the present plaintiff] shall pay lessor [the Matzens], as royalty, one-eighth of the proceeds from the sale of the gas, as such, for gas from wells where gas only is found * * *.

(b) Other lessors of the plaintiff in the Hugoton Lease Block likewise filed suits against the plaintiff, alleging underpayment of royalties. In all, 71 such suits were filed. They included lease obligations “A,” “B,” “C,” and “D,” as described in finding 8. One of the suits was a class action.

41. Only one of the lawsuits referred to in finding 40 went to trial. That was the Matzens’ case. On January 7,1957, the District Court of Grant County, Kansas, rendered judgment against the plaintiff and in favor of the Matzens in the amount of $535.60. In its conclusions of law, the court stated the problem as follows:

The problem presented here is to arrive at the value of gas at the well head (under the terms of an oil and gas lease that provides for % to royalty owners of proceeds from the sale of gas) where the gas is sold by Defendant [the present plaintiff] at a point distant from the wellhead and is intermingled with other gas, processed and then sold.
To arrive at the answer to this problem, it appears you should take the gross sales price of all gas sold, including processed gas, and deduct therefrom all the costs of the transportation and processing of the gas before the gas is sold, in order to arrive at the net sales price of the gas. This amount is then divided by the total volume of gas produced (M.C.F.) which arrives at the value of gas in M.C.F. at the wellhead.

On February 4, 1957, the District Court amended its conclusions of law in two respects. First, it added to gross receipts the value of the gas used in processing or lost through shrinkage. Then, it deducted from gross receipts the same dollar amount for profit belonging to the plaintiff on gathering and processing the gas. Because the two adjustments cancelled each other, the Court reached the same result as before, a price of 15 cents per Mcf. The court refused to allow any part of the plaintiff’s Federal or State income taxes as an expense of operation. The court concluded that the proceeds or value of the gas at the wellhead for purposes of royalty payments due the Matzens was 15 cents per Mcf. Thereafter, the plaintiff and the Matzens appealed the trial court’s decision to the Kansas Supreme Court.

42. On December 12, 1957, the plaintiff sent an identical letter to each of its royalty owners in the Hugoton Lease Block. In that letter, the plaintiff stated in part as follows:

Judgment of the trial court in this case has been appealed to the Kansas Supreme Court, and the appeal has been argued. A decision may reasonably be expected early in 1958. It is our expectation that this decision will enable us to establish the current royalty rate. In any event, it seems clear to us that no one can gain from bringing or maintaining additional suits; anyone so doing will only incur needless expenses. Hugoton Production Company has always paid the same royalty rate to all' of its lessors, and when the proper rate effective as of November 1, 1954, is ascertained, Hugoton expects to account to every lessor in that manner whether he has a suit on file or not.

43. On February 14, 1958, the Kansas Supreme Court rendered an opinion affirming the judgment of the trial court in the litigation between the Matzens and the plaintiff. In its opinion, the court stated in part as follows:

No dispute exists as to the amount of gas produced. Both parties here assert that Hugoton’s royalty obligation is to be determined at the wellhead rather than at the point of sale and delivery off the lease, and further, that there is no market price at the wellhead for the gas taken by Hugoton. Thus, a known amount of gas is produced and sold by Plugoton under contracts calling for a definite price; hence, there remains but one element necessary to determine proceeds at the wellhead, i.e., the price to be paid for the gas at that point. The amount due the plaintiffs as royalty is then only a matter of calculation.
*****
The language “proceeds from the sale of the gas, as such,” must be construed from the context of the leases and the custom and practice in the field at the time they were executed, and we tbink where, as here, the gas produced is transported by the lessee in its gathering system off the premises and processed and sold, its royalty obligation is determined by deducting from gross proceeds reasonable expenses relating directly to the costs and charges of gathering, processing and marketing the gas. Thus, proceeds from the sale of gas, wherever and however ultimately sold, is the measure of plaintiffs’ [the Matzens’] royalty, less reasonable expenses incurred in its gathering, transporting, processing and marketing.

No further proceedings were had in the case, and the judgment of the trial court thereafter became final.

44. On March 20,1958, the attorneys for the plaintiff [the defendant in the litigation with the Matzens] met in Wichita, Kansas, with attorneys representing the Southwest Kansas Koyalty Owners Association. The purpose of the meeting was to consider ways of disposing of the other royalty suits filed against the plaintiff. The attorneys agreed on the royalty payments to be made for the years 1956 and 1957 based upon the formula approved by the Kansas Supreme Court. They further agreed that, as to the future, the same formula would be followed for royalty computations. The Association agreed to recommend to its members that the formula be applied uniformly through the balance of the contract between the plaintiff and the Kansas Power and Light Company. The plaintiff thereupon paid the royalty prices, as so determined, to all its lessors. It has not had any further disputes with its lessors over royalty payments.

45. (a) The following tabulation shows the royalties, stated in cents per Mcf (at a pressure base of 14.65 p.si.a.), paid by the plaintiff to its royalty holders in the Hugoton Lease Block for the years 1951 to 1957, inclusive, and also reflects the increases that resulted from the litigation with the Matzens and the agreement mentioned in finding 44:

(b) The application of the formula approved by the Kansas Supreme Court in the litigation with the Matzens to the years 1951, 1952, and 1953 and the first 10 months of 1954 would produce the following prices, stated in cents per Mcf (at a pressure base of 14.65 p.s.i.a.):

Tear: Price
1951_ 13.10$
1952 _ 13.90
1953 _ 13.46
1954 (Jan.-Oct.)_ 13.93

(c) As indicated above in finding 41, one of the elements in the formula was a profit to plaintiff on gathering and processing. This element was eliminated from the formula in computing the prices for 1956 and 1957 shown above in finding 45 (a) and the prices for 1951 through 1954 shown above in finding 45(b). The result was to increase these prices by including therein all of the profit made by plaintiff on gathering and processing.

46. (a) In each of the years 1951 to 1957, inclusive, the plaintiff received gross income from natural gas, and from the liquefied products extracted therefrom, produced from wells on properties in which it had an economic working interest; and in its income tax returns for those years, it claimed deductions for percentage depletion under sections 23 (m) and 114 of the Internal Revenue Code of 1939, as amended, or the corresponding provisions of the Internal Revenue Code of 1954 (.§§ 611 and 613). For each year, the plaintiff computed its gross income from its properties first by aggregating all sales of natural gas, with the exception of local field or irrigation sales, and dividing such dollar amount by the volume of gas sold in each year. The sales of liquefiable hydrocarbons from the plaintiff’s gasoline plant were not included. The resulting price per Mcf was then applied to the volume of gas produced for the year in question to determine the gross income from the properties.

(b) The gross income from the properties, less royalties, reported on the plaintiff’s tax returns for 1952 through 1957, and the price per Mcf (on a 14.65 p.s.i.a. pressure base) used to compute the gross income, were as follows:

47. Within the times prescribed by law, the plaintiff filed with the Internal Eevenue Service claims for refund of income taxes for the years 1952 through 1957. In these claims, the plaintiff asserted that the gross income from its properties, less royalties, and the price per Mcf (on a 14.65 p.si.a pressure base), were as follows for the years 1951-1957:

The prices used on the claims for 1952 through 1957 were equal to those resulting from the application of the Matzen formula.

48. In the final determination of the plaintiff’s income tax liabilities for the years 1951-1957, made prior to the filing of this lawsuit, the Commissioner determined that the gross income from the plaintiff’s properties, less royalties paid or incurred, upon the basis of which the plaintiff was allowed deductions for percentage depletion, was as follows:

dross income as Year: determined
1951_$2,155,987.74
1952_ 2, 948,889. 34
1953_ 3, 048,058. 04
1954_ 3, 472,443.00
1955_ 3, 684, 684. 05
1956_ 4,169,823.12
1957_ 4, 781, 096. 00

Based upon such determination, the Commissioner computed and allowed deductions for percentage depletion thereon for each of the years in the following amounts:

Year: Deduction allowed
1951_ $418,048.20
1952_ 718,283. 33
1953_ 831,409.35
1954_ 954, 451.03
1955_1, Oil, 576. 00
1956_ 1,141, 508. 03
1957_1,314,801.00

49. For each of the years 1951 to 1957, inclusive (except 1954, for which the statute of limitations on assessment had expired), the Commissioner used the following formula in computing the plaintiff’s gross income from its properties for the purpose of determining the deductions for percentage depletion:

(a) The gross receipts received for (1) sales of residue gas, (2) sales of raw gas, (S) sales of the products extracted from the raw gas, (4) dehydration, and (5) an amount for gas lost or consumed as fuel (equal to the amount reflected on plaintiff’s books as a charge to products extraction operation and a credit to production) were aggregated.

(b) From the total income ascertained in (a) above, there were subtracted the costs incurred in (1) moving the plaintiff’s gas (including lease lines, field measuring station structures and equipment, and the Columbian Carbon spur line), and (2) the operation of the plaintiff’s absorption and fractionation facilities, including depreciation, as per the plaintiff’s books, on both items (1) and (2).

(c) There was also subtracted from the income ascertained in (a) above (1) an amount equal to 10 percent of the cost (unreduced by depreciation), as of the end of each year, of the investment in the plaintiff’s (i) field lines (including the Columbian Carbon spur line) and lease lines (including field measuring station structures and equipment), and (ii) absorption and fractionation facilities, and (2) an amount equal to a 10 percent return on working capital (1/6 of annual operating expenses, exclusive of depreciation).

(d) The income so reduced was divided by the volume of gas produced by the plaintiff in each year (except for the year 1951, as to which the volume sold was used).

(e) The income so reduced was determined to be the plaintiff’s gross income from the properties, and there was excluded therefrom the actual royalties paid by the plaintiff (including the retroactive payments resulting from the Mat-zen litigation) to its royalty holders.

50. The following tabulation shows the plaintiff’s gross income per Mcf (on a uniform pressure base of 14.65 p.sd.a.), as determined by the Commissioner for each of the years 1951 to 1957, inclusive, under the formula described in finding 49:

Year: Gross income per Mef
1951_$0.11979055
1952 _ .12660941
1953 _ .12355606
1954 _.12817501
1955 _ . 13928663
1956 _ .14324207
1957 _ .14639404

.51. (a) The formula referred to in finding 48 was derived from a study of the plaintiff’s operations made by a valuation engineer of the Internal Revenue Service. The formula is largely a proportionate profits method of computation for use in an integrated operation where there is no representative market or field price. In many instances, the result reached would be in the range of that negotiated between gasoline plant operators and producers dealing at arms’ length. At the time when the engineer made his investigation, he was primarily concerned with the claims for refund filed by the plaintiff for 1952 and 1953, in which depletable gross income was computed on the basis of the Matzen formula. The engineer determined first that this use of the Matzen formula resulted in including in depletable gross income manufactur- ' ing or conversion and transportation income. He then concluded that there was no representative market or field price for plaintiff’s gas within the meaning of the applicable Treasury Regulations. This conclusion was based primarily on a finding by the District Court of Grant County, Kansas, in the Matzen litigation, reading as follows:

2. It is admitted by the pleadings that none of the gas taken by the defendant [the present plaintiff] is sold by defendant at the well head and that there is no market price at that point for the gas taken by defendant. However, all gas produced by defendant is metered at the well head, and the royalty owners are paid on the basis of that measurement.

This admission by the parties in the Matzen litigation reflected the fact that none of the plaintiff’s gas had been sold at the wellhead. The engineer also concluded that there were no comparable sales of gas. He then decided to utilize a formula which would arrive at a value for the gas at the wellhead and eliminate all manufacturing, transportation, and nonproducing income.

(b) The valuation engineer, under his formula, next concluded that the operation of the plaintiff’s dehydration plant was a producing or depletable function. All gathering of the plaintiff’s gas from the wellhead on, including the initial metering of the gas, was treated as a nonproducing or transportation function. He also treated the operation of the plaintiff’s absorption and fractionation facilities as non-depletable or manufacturing-refining processes. He adopted a 10 percent rate of return on investment and working capital.

52. The plaintiff’s claims for refund (see finding 47) were disallowed by the Commissioner on the dates indicated in the following table:

Claim for year: Date of disallowance
1952-January 25, 1960
1953-November 12,1959
1954_November 4, 1959
1955-February 2, 1960
1956_February 2, 1960
1957_February 2, 1960

53. On March 29, 1961, the Internal Eevenue Service notified the plaintiff that it was chargeable with a deficiency in tax for the calendar year 1957 in the amount of $7,287.80, together with interest thereon in the amount of $1,329.77. This was based upon an administrative determination that the plaintiff’s dehydration plant was a nonproducing, instead of a producing, function. The following tabulation shows the plaintiff’s gross income per Mcf (on a 14.65 p.s.i.a. pressure base), as determined administratively by the Internal Revenue Service for each of the years 1952-1957 under the formula described in finding 49 but adjusted on the basis of considering the dehydration plant to be a nonproducing function:

Year ■ Gross income per Mcf
1952 _$0.12474685
1953 _ . 12160651
1954 _ . 12656685
1955 _ . 13768494
1956 _ .14176226
1957 _ . 14503941

54. On April 6, 1961, while this case was being tried, the Internal Revenue Service sent to the plaintiff a notice of deficiency for the calendar year 1957, determining a deficiency in tax in the amount of $352,622. The basis for this deficiency was stated in part as follows:

(b) It is determined that the basis for 27%% depletion used in the previous computation erroneously included the amount received for dehyration [sic] of natural gas. Accordingly, it is determined that a depletion deduction of $1,300,786.00 is allowable in lieu of the deduction of $1,314,801.00 previously allowed. Therefore, your taxable income is increased in the amount of $14,015.00. You have previously agreed to this adjustment by executing Form 870.
(c) It is determined that the representative or market field [sic] price for your natural gas was $0.06 per M.C.F. * * *

55. On April 10, 1961, the plaintiff paid the separate deficiencies asserted by the Internal Revenue Service on March 29 and April 6, 1961 (see findings 53 and 54). On April 18, 1961, the plaintiff filed with the District Director at Wichita, Kansas, its claim for refund relating to the separate determinations of March 29 and April 6, 1961, respectively. Thereafter, on April 18, 1961, this claim was disallowed. The plaintiff, by appropriate amendments to its petition, pleaded the foregoing facts.

56. In the early 1920’s, it became known that there was a very large reserve of natural gas in the Texas Panhandle area of the Hugoton Embayment, and it became evident that there was possibly a large reserve in the Hugoton Field portion of the Embayment. The major oil companies controlled most of the acreage in the Texas Panhandle area. There was very little demand locally for natural gas, except for the manufacture of carbon black, and this use commanded a very low price. In order to create markets for their gas in the major cities to the north, these oil companies banded together, pooled reserves, and financed the laying of long-distance gas transmission lines. Some of the pipeline companies so created were Cities Service Gas Company, Colorado Interstate Gas Company, and Natural Gas Pipeline Company of America. Other pipeline companies operating early in the Hugoton Embayment were Panhandle Eastern Pipe Line Company and Northern Natural Gas Company. They controlled substantial reserves of natural gas. All of these companies operated pipelines in the Hugo-ton Embayment during the years 1951 through 1957. In addition, other pipeline companies operating in the Embayment in those years were Kansas-Colorado Utilities, Inc., Kansas-Nebraska Natural Gas Company, and Michigan-Wisconsin Pipe Line Company.

57. In the 1930’s, the supply of natural gas in the Hugoton Embayment greatly exceeded the demand, and there was a market only for a very small percent of the reserves. In 1935, the pipeline companies took approximately 18 percent of the natural gas produced in the Texas portion of the Hugoton Embayment, and more than 50 percent was vented into the air. This excess of supply over demand depressed the prices paid for natural gas to very low levels. Some prices paid by Panhandle Eastern Pipe Line Company in the Hugoton Embayment ranged from 2y2 cents per Mcf to a high of 4 cents, all on a 16.4 p.s.i.a pressure base. Most contracts entered into during this period provided for a flat price for the life of commercial production. In general, the purchaser got the liquefiable hydrocarbons in the raw gas. A B.t.u. value of 1,000 was the minimum acceptable heat value of the gas. Many low-price contracts executed during this period are still in effect.

58. The excess of supply of natural gas in the Hugoton Embayment over the demand prevailed until the end of World War II. At that time, there began to be an increase in the demand for natural gas. Utility companies had long waiting lists of customers who wanted gas service for house heating. In addition, the intrastate use of natural gas, particularly by the chemical industry, increased. The pipeline companies expanded their lines. By 1948-1949, some 90 percent of the Kansas portion of the Hugoton Field was covered by gas purchase contracts. Over the past 10 years, the increase in the use of natural gas has been roughly one-half trillion cubic feet each year. By 1955, the interstate and intrastate pipeline companies in the Hugoton Embayment were taking approximately 90 percent of the total gas produced.

59. This change in demand for natural gas caused the pipeline companies to contract for additional supplies of gas. This, in turn, set up competitive forces in the Hugo-ton Embayment, with its consequent effect on prices. Purchasers of gas became willing to contract for smaller volumes or to pay substantially higher prices for greater volumes. The sellers, in order to protect themselves against future increases in prices, inserted in their contracts fixed periodic price escalation clauses, “favored nation” clauses, and clauses providing for price renegotiations at fixed intervals. The sellers also commenced to reserve the right to process their gas for removal of the liquefiable hydrocarbons. The acceptable heat value of gas to the purchasers became gradually lower. Adequate supplies of natural gas in the Hugo-ton Embayment became harder to obtain, and in 1950 and 1951 .at least one pipeline company in the area had to go to the Texas Gulf Coast for additional supplies. During the years involved in the present litigation, the competition among purchasers steadily increased.

,60. Natural gas is ordinarily transported through pipelines. These may be high-pressure or low-pressure lines. Since pipelines are expensive to construct, pipeline companies have been required to insure for themselves long-term supplies of natural gas in order to amortize their investment and to deliver the gas in competition with other fuels. This, in turn, has dictated the terms of gas purchase contracts between pipeline companies and sellers of natural gas. Invariably, such contracts are for long terms. This has been true since the first long-distance pipelines were constructed. Over the years, the term of gas purchase contracts has gradually shortened from the commercial life of the producing leases to a 20-year term. During the years 1951 through 1957, the term or depletion rate of these contracts decreased from about 27 years to 21.9 years. Natural gas, unlike oil, is normally not sold on a day-to-day basis, except principally for drilling operations. Occasionally, a pipeline company in immediate need of gas will purchase spot gas or short-term gas to meet its demands. There is no posted field price for natural gas, as in the case of crude oil.

61. During the years 1951 through 1957, the following factors influenced the price that a seller of natural gas could command for his product in the Hugoton Embayment :

(a) The volume available for sale. Generally, the greater the volume or reserves, the greater the price the seller could command.

(b) The location of the leases or acreage involved, whether in a solid block or scattered, and their proximity to prospective buyers’ pipelines.

(c) Quality of the gas as to freedom from hydrogen sulphide in excess of 1 grain per 100 cubic feet.

(d) Delivery point.

(e) Heating value of the gas.

(f) Deliverability of the wells. The lai’ger the volume that could be delivered from a reserve, the greater the price the seller could command.

(g) Delivery or rock pressure. The higher the pressure, the less compression for transportation is required.

62. (a) During the years 1951 through 1957, the plaintiff’s natural gas from the Hugoton Lease Block rated as follows under the criteria mentioned in finding 61:

(1) Its reserves were far above the average available for sale.

(2) The leased acreage was well-blocked and compactly situated.

(3) Its gas was average as to quality.

(4) The delivery point was better than average from the standpoint of costs of connection.

(5) The heating value of plaintiff’s gas was average.

(6) The plaintiff’s gas wells had a deliverability above average, because the producing formation had greater thickness and higher permeability.

(7) The delivery or rock pressure was average.

(b) In addition to the factors mentioned in paragraph (a) of this finding, the Hugoton Lease Block was closer than the average productive acreage of the Hugoton Embayment to the northern markets, where natural gas is consumed.

63. At all times during the years 1952 through 1957, there existed a market for natural gas in the Hugoton Embayment, in the sense that there were both buyers and sellers dealing at arms’ length, who bought and sold gas. There was a great deal of competition. In general, the sellers were seeking the best price they could get for their gas, while the buyers sought to buy at the lowest possible prices. Contracts of sale made during the period provided for initial prices per Mcf (on a 14.65 p.s.i.a. pressure base) in 1952 of 8.5 cents (one contract) and 13.273 cents (one contract), in 1953 of 11.5 cents (one contract), 12 cents (one contract), and 15 cents (four contracts), in 1954 of 15 cents (two contracts) and 16 cents (one contract), in 1955 of 12 cents (one contract), 15.5 cents (two contracts), and 16 cents (three contracts), in 1956 of 16 cents (four contracts), and in 1957 of 16 cents (two contracts) and 17 cents (one contract).

64. The plaintiff is the owner of the claims herein asserted. No assignment or transfer of the same, or any part thereof, has heretofore been made.

CONCLUSION OE LAW

Upon the foregoing findings of fact and opinion, the court concludes that this case should be, and it hereby is, remanded to the trial commissioner for further proceedings consistent herewith. 
      
       53 Stat. 14, 45, as amended, 26 U.S.C. §§ 23(m), 114(b) (3) (1.952 ed.).
     
      
       68A Stat. 207-08, as amended, 26 U.S.C. §§ 611, 613 (1958 ed.).
     
      
       “Sec. 613. Percentage Depletion.
      “(a) General Buie. — In the case of the mines, wells, and other natural deposits listed in subsection (b), the allowance for depletion under section 611 shall be the percentage, specified in subsection (b) of the gross income from the property excluding from such gross income an amount equal to any rents or royalties paid or incurred by the taxpayer in respect of the property. Such allowance shall not exceed 50 percent of the taxpayer’s taxable income from the property (computed without allowance for depletion). In no case shall the allowance for depletion under section 611 be less than it would be if computed without reference to this section.
      “(b) Percentage Depletion Bates. — The mines, wells, and other natural deposits, and the percentages, referred to in subsection (a) are as follows:
      (1) 27% percent — oil and gas wells.”
     
      
       Rev. Act of 1926, § 204(c), 44 Stat. 16.
     
      
       See Hearings Before Sen. Com. on Finance on H.R. 1, 69th Cong., 1st Sess. 177 (1926) ; S. Rep. No. 52, 69th Cong., 1st Sess. 17-18 (1926) ; H.R. Rep. No. 356, 69th Cong., 1st Sess. 31-32 (1926) ; 67 Cong. Rec. 3761-78 (1926) ; Austin, Percentage Depletion: Its Background and Legislative History, 21 Kans. City L. Rev. 22, 26-27 (1952) ; Comment, 3 DePaul L. Rev. 233, 241-43 (1954).
     
      
      
        Brea Cannon Oil Co. v. Commissioner, 77 F. 2d 67 (C.A. 9, 1935), aff’g 29 B.T.A. 1134 (1934) ; Signal Gasoline Corp. v. Commissioner, 77 F. 2d 728 (C.A. 9, 1935), aff’g 30 B.T.A. 568 (1934) ; Greensboro Gas Co. v. Commissioner, 79 F. 2d 701 (C.A. 3, 1935), aff’g 30 B.T.A. 1362 (1934), Consumers Natural Gas Co. v. Commissioner, 78 F. 2d 161 (C.A. 2, 1935), aff’g 30 B.T.A. 1263 (1934). Cf. United States V. Cannelton Sewer Pipe Co., 364 U.S. 76, 80 S. Ct. 1581, 4 L. Ed. 2d 1581 (1960) ; Riddell v. Monolith Portland Cement Co., 371 U.S. 537, 83 S. Ct. 378, 9 L. Ed. 2d 492 (1963).
     
      
       Treas. Reg. 74, Art. 221(i), which provided as follows:
      “If the oil and gas are not sold on the property but are manufactured or converted into a refined product or are transported from the property prior to sale, then the gross income shall be assumed to be equivalent to the market or field price of the oil and gas before conversion or transportation.” Compare Treas. Reg. 69, Art. 221.
     
      
       Treas. Reg. 77, Art. 221(g) ; see also Treas. Reg. 86, Art. 23 (m) (1) (g).
     
      
       Treas. Reg. 94, Art. 23(m)-1(3) (g) ; see also Treas. Reg. 101, Art. 23(m)—1(3) (g).
     
      
       Treas. Reg. 111, § 29.23(m)—1(f), as amended Oct. 31, 1944. See also Treas. Reg. 118, § 39.23(m)-1(e) (1).
     
      
       Treas. Reg. § 1.613-3(a).
     
      
       In its tax returns, plaintiff computed gross income for purposes of the depletion allowance on the basis of an unacceptable method described in Finding 46(a). After an audit of plaintiff’s returns by the Commissioner of Internal Revenue, additional income taxes were determined to be due (except for 1953 and 1953, for which years refunds were allowed), and the additional taxes were paid by plaintiff. Thereafter, plaintiff filed claims for refunds in which it computed gross income on the basis of a formula method adopted by the Kansas courts in royalty litigation in which the plaintiff was involved and similar in principle to the method urged by the Government. See Findings 40-45, 47. After these claims for refunds had been disallowed, plaintiff instituted the present proceedings for its refunds, urging use of the market comparison method described above.
     
      
       For a fuller description of the Government’s method, see Finding 49.
     
      
       The regulations, authorized under the 1954 Code by sections 611(a) and 7805(a), 68A Stat. 207, 917, 26 U.S.C. §§ 611(a), 7805(a) (1958 ed.), have, as our previous discussion indicates, remained substantially unchanged through a series of statutory reenactments. “Treasury regulations and interpretations long continued without substantial change, applying to unamended or substantially reenacted statutes, are deemed to have received congressional approval and have the effect of law.” Helvering v. Winmill, 305 U.S. 79, 83, 59 S. Ct. 45, 83 L. Ed. 52 (1938) ; Crane v. Commissioner, 331 U.S. 1, 7-8, 67 S. Ct. 1047, 90 L. Ed. 78 (1947) ; J. &. Boswell Co. v. Commissioner, 302 F. 2d 682, 685 (C.A. 9), cert. denied, 371 U.S. 860, 83 S. Ct. 118, 9 L. Ed. 2d 99 (1962). The regulations are binding upon the Commissioner as well as upon the taxpayer. McCord v. Granger, 201 F. 2d 103, 106-07 (C.A. 3, 1952) ; Pacific Nat. Bank v. Commissioner, 91 F. 2d 103 (C.A. 9, 1937).
     
      
       Treas. Reg. 118, § 39.23(m)-1(e) (3), as amended. Comparable, though different, regulations were proposed for the 1954 Code, § 1—613-3 (b), 21 Fed. Reg. 8450—51 (1956), but have not yet been adopted.
     
      
      
        Alabama By-Products Corp. v. Patterson, 258 F. 2d 892 (C.A. 5, 1958), cert. denied, 358 U.S. 930, 79 S. Ct. 318, 3 L. Ed. 2d 303 (1959) ; United States Pipe & Foundry Co. v. Patterson, 203 F. Supp. 335 (N.D. Ala. 1962) ; Woodward Iron Co. v. Patterson, 173 F. Supp. 251 (N.D. Ala. 1959).
     
      
       See Finding 61.
     
      
       Based on this considerable evidence, our Commissioner was able to mate a finding as to the minimum initial price that the plaintiff could have obtained under a long-term contract, entered in each of the years 1952 through 1957, for the sale of its raw natural gas at or near the wellhead. We have not adopted this finding as our own because of our decision, discussed in the latter half of this opinion, that this price is not the equivalent of the representative market or field price referred to in the regulations.
     
      
       See note 15, supra, and text at that point. Cf. Randolph, Problems of the Oil & Gas Industry, N.Y.U., 9th Inst. on Fed. Tax. 491, 494-96 (1951).
     
      
       The positions of the parties were reversed in the Shamrock Oil & Gas case.
     
      
      
        Wall v. United Gas Public Service, 178 La. 908, 914, 152 So. 561 (1934) ; Douglas v. Merceles, 25 N.J. Eq. 144, 147 (1874),
     
      
       These eases are well compiled in 3A Summers, Oil & Gas § 589 (1958 ed.).
     
      
       Federal Power Commission, Natural Gas Investigation 222 (Docket No. G-580, 1948) (Report of Commrs. Smith & Wimberly) [hereinafter referred to as “Natural Gas Investigation”].
     
      
      
        Shamrock Oil & Gas Corp. v. Coffee, 140 F. 2d 409, 410-11 (C.A. 5), cert. denied, 323 U.S. 737, 65 S. Ct. 42, 89 L. Ed. 591 (1944) ; Columbian Fuel Corp. v. United Fuel Gas Co., 72 F. Supp. 843, 847 (W.D. Va. 1947), aff’d 165 F. 2d 746 (C.A. 4, 1948).
     
      
       Natural Gas Investigation 175 — 235. The Commission adopted this method in In re Panhandle Eastern Pipeline Co., 13 F.P.C. 53, 59-77 (1954) ; however, the Commission was immediately reversed sub nom City of Detroit, Mich. v. F.P.C. 97 U.S. App. D.C. 260, 230 F. 2d 810 (1955), cert denied, 352 U.S. 829, 77 S. Ct. 34, 1 L. Ed. 2d 48 (1956), where the court held that the field price could not be used as an element in the composition of rates of the pipeline’s own produced gas without a showing that the resulting increased rate was no more than necessary for the purpose of encouraging exploration and development. See In re Union Oil Co., 16 F.P.C. 100, 110 (1956), aff’d in part sub nom Bel Oil Corp. v. F.P.C., 255 F. 2d 548 (C.A. 5), cert. denied, 358 U.S. 804, 79 S. Ct. 47, 3 L. Ed. 2d 76 (1958) ; In re Sun Oil Co., 17 F.P.C. 174, 191-94 (1957), aff’d in part, 255 F. 2d 557 (C.A. 5), cert. denied, 358 U.S. 804, 79 S. Ct. 41, 3 L. Ed. 2d 76 (1958). In re Forest Oil Corp., 17 F.P.C. 586, 617-19 (1957), aff’d in part 263 F. 2d 622 (C.A. 5, 1959).
     
      
       Natural Gas Investigation 219-20. It is of no significance that the Commission was referring primarily to the field price for processed gas, rather than gas at the wellhead; the important similarity is that virtually all gas sold by the independents was under long-term contract.
     
      
      
        Brea Cannon Oil Co. v. Commissioner, 77 F. 2d 67, 69 (C.A. 9, 1935).
     
      
       Hence It might be suggested that the representative market price he computed solely on the basis of the price which petitioner could have obtained under a long-term contract entered in a single past year in which it would be reasonable to assume he would have entered such a contract. This suggestion has not been offered by either of the parties and, for several reasons, it does not appear a satisfactory alternative.
     
      
       Our conclusion adopting- the market comparison method was reached on tiie basis of the record complied on the assumption that only contracts entered in the tax year in question were relevant to the representative price. We recognize the possibility that practical difficulties may prevent the computation of the representative price as we have now defined it. We do not suggest that we think this likely — indeed, we find many indications to the contrary — nor do we wish to render inconclusive our determination that this method must be employed. However, should problems of a different nature from any considered in these proceedings arise, the commissioner and the court of course will be compelled to consider the consequence which they may have upon our decision here.
     
      
       The court has adopted the recommended findings of the commissioner, except that amendments have been made to findings 27, 41, 45, and 47; the commissioner’s finding 64 has been deleted and his finding 65 has been renumbered.
     
      
       Although the findings on this point will relate specifically to the years that are involved in the present litigation, the evidence indicates that the same system of processing the plaintiff's gas is still being used.
     
      
       The excess in Mcf treated this year over the amount produced for 1952, as shown in finding 6, was due to line gain or overage attributable to variations in temperature when the gas was metered.
     
      
       The plaintiff’s assertion in the liftigation with the Matzens that there was no market price for the gas at the wellhead apparently reflected the factual situation that none of the gas was actually sold at the wellhead.
     
      
       Of the years involved in the present litigation, 1957 was the only one for which a deficiency notice conld still be issued.
     
      
       See footnote 33.
     
      
       A so-called “favored nation” clause obligated the buyer to increase the contract price to the level of any higher price paid by the buyer to any other producer in the area, or to increase the contract price to the level of any higher price paid by any other purchaser in the area.
     
      
       Two contracts made in 1952 provided for initial prices of 10 cents and 11 cents, respectively, per Mcf on a pressure base of 16.4 p.s.i.a.
     
      
       On March 31, 1961, the defendant filed a counterclaim against the plaintiff in the total amount of $20,729.86. This amount consisted of $10,191.28 and $1,921.01 which the Internal Revenue Service allegedly had refunded to the plaintiff for the years 1952 and 1953, respectively, through error, and of $8,617.57 representing the tax deficiency and interest mentioned in finding 53. The sum of $8,617.57 was subsequently paid by the plaintiff (see finding 55). The alleged refunds for 1953 and 1953 were not specifically covered by the evidence that was introduced by the parties, and no findings expressly referring to them were requested by the parties. The implication in the record is that the counterclaim respecting such refunds involves the same legal issue as is raised by the plaintiff’s claims, and, therefore, that the counterclaim can be disposed of in the light of the court’s decision on the plaintiff’s claims.
     