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The Shamrock Oil and Gas Corporation, Petitioner, v. Commissioner of Internal Revenue, RespondentShamrock Oil & Gas Corp. v. CommissionerDocket Nos. 49145, 61315, 68580, 77791March 24, 1961, Filed
United States Tax Court *198Decisions will be entered under Rule 50 .1. Petitioner produced and processed natural gas in which it had an economic interest in its gasoline extraction plants. Based upon the evidence of record,
held , for the purpose of determining "gross income from the property" for percentage depletion, the petitioner did not sell gas in the immediate vicinity of the well so that, under the respondent's regulations, the "gross income from the property" is the equivalent of the representative market or field price.Held, further , the respondent erred in his determination of representative market or field price; proper method established.2. Petitioner paid cash bonuses to lessors or assignors, who retained an economic interest in the property, for the acquisition of leases.
Held , respondent's regulations requiring the petitioner's "gross income from the property" for the purposes of percentage depletion to be reduced by a proportionate amount of the bonuses paid sustained.Held, further , respondent's regulations which provide that such cash bonuses are capital investments recoverable only through depletion sustained and no part of the bonuses is deductible or excludiblefrom gross income.Wright *199 Matthews, Esq., W. M. Sutton, Esq., H. A. Berry, Esq ., andEd H. Selecman, Esq ., for the petitioner.Roy E. Graham, Esq ., andAllen T. Akin, Esq ., for the respondent.Train,Judge .TRAIN*979 Respondent determined deficiencies in the petitioner's income and excess profits taxes for the years and in the amounts as follows:
Deficiency (or Deficiency in Fiscal year ended Nov. 30 -- Docket No. overassessment) excess profits in income tax tax 1943 49145 $ 8,275.66 $ 242,520.76 1944 49145 1,625.87 61,139.20 1945 49145 (9,205.72) 80,655.08 1946 49145 15,434.98 5,112.82 1947 49145 28,010.94 1948 61315 207,474.99 1949 61315 236,827.51 1950 61315 275,399.99 1951 68580 268,247.74 1952 68580 277,543.20 1953 77791 348,770.37 1954 77791 479,017.43 *980
Docket No. 49145 .The parties have settled the excess profits tax issue and all standard issues other than depletion contained in this docket.
No deficiencies with respect to depletion were found by respondent for the fiscal years ending November 30, 1943, through November 30, 1947.
The respondent, as to each of these years, either agreed to the depletion allowance claimed by Shamrock in its returns or he allowed an additional depletion allowance. The amounts claimed in the returns, and the amounts *200 finally allowed, for 1943 through 1947, are set forth below:
Claimed on Finally allowed return 1943 $ 398,550.58 $ 402,258.98 1944 334,916.17 351,466.08 1945 369,307.99 377,784.80 1946 633,938.45 633,938.45 1947 727,438.54 727,438.54 From 1943 until October 1, 1945, inclusive, Shamrock, for income tax purposes, reported the value of its raw gas at the wellhead in accordance with its payments to the royalty owners. From October 1, 1945, to November 30, 1954, inclusive, Shamrock reported the value of its raw gas at the wellhead for income tax purposes upon a computed basis.
In the original petition filed by Shamrock in this docket, Shamrock put in issuethe amount of the depletion allowance to which it was entitled for each of the fiscal years 1943 through 1947. By a first amended petition, Shamrock contends that the "gross income from the property" at the wellhead, for depletion purposes, in terms of price per thousand cubic feet of gas (MCF) was as follows:
1943 $ 0.028497 1944 .029895 1945 .031314 1946 .036468 1947 .051986 This amount of gross income from the property, in terms of price per MCF, is proposed by Shamrock as the amount for which it sold the gas in the immediate vicinity of the well and as the representative *201 market or field price of the gas. Alternative amounts of gross income from the property for each of the fiscal years in issue are proposed by Shamrock as the representative market or field price if the same is to be determined by other sales. These amounts are set forth to be not less than 3 cents for the fiscal year 1943; 4 cents for the fiscal year 1944; 5 cents for the fiscal year 1945; 5 cents for the fiscal year 1946; and 6 cents for the fiscal year 1947.
*981 Based on the amounts of 3 to 6 cents stated above, Shamrock has computed its gross income from the property, allowable percentage depletion, and amount of income tax overpaid in the following amounts for each of the years involved in this docket:
Gross income Percentage Overpayment from the depletion property 1943 $ 1,140,878.52 $ 313,741.59 $ 158,018.98 1944 1,663,055.48 457,340.26 255,116.49 1945 2,555,600.60 702,790.16 207,671.43 1946 2,928,683.45 805,387.95 125,105.37 1947 3,662,165.94 1,007,095.63 181,520.19 Shamrock makes the further allegation in its first amended petition filed in this docket that in the event it is mistaken in its allegations as to the proper method of determining the gross income from the property, then according to the peculiar *202 conditions applicable to Shamrock, the gross income from the property during each of the taxable years involved, attributable to the leasehold or other estates in the gas of Shamrock, with respect to which it is entitled to statutory percentage depletion, is "all the proceeds of the sale of the residue gas * * * plus a sum equal to an amount which is not less than 58.8% of the proceeds of all natural gasoline of not less than 14 nor more than 26 pounds vapor pressure, calculated on the basis of 26-70 natural gasoline, extracted from the raw natural gas and raw casinghead gas in the gasoline extraction plants operated by petitioner" during the years in question. Gross income from the property so calculated by Shamrock for each of the years in issue in this docket is as follows:
1943 $ 1,198,171.65 1944 1,336,266.35 1945 1,797,581.40 1946 2,588,789.75 1947 3,766,485.54 Docket Nos. 61315, 68580, and 77791 .I.
Depletion Issue .The respondent determined deficiencies with respect to depletion and other issues for the fiscal years ending November 30, 1948, through November 30, 1954. All issues raised by the respondent, other than the depletion issue, have been settled by the parties and the settlement *203 thereof is to be given effect under Rule 50.
As regards the depletion allowance, the amounts claimed by Shamrock in its returns are as follows:
1948 $ 1,438,862.76 1949 1,784,807.95 1950 1,739,701.77 1951 1,776,849.81 1952 1,725,296.81 1953 1,986,442.36 1954 2,687,770.27 *982 Shamrock claimed depletion on its interest in natural gas processed in its own natural gasoline extraction plants for these years on the basis that the proceeds from the sale of all the residuegas and the proceeds from the sale of 40 percent of the liquid hydrocarbons extracted from the gas constituted the gross income from the property.
In the respective statutory notices of deficiency respondent disallowed deductions for depletion in the following amounts:
1948 $ 427,905.15 1949 481,257.89 1950 397,392.97 1951 303,757.97 1952 229,111.41 1953 303,286.93 1954 507,592.57 The basis of respondent's action was that the gross income of the gas leases, in his opinion, was the equivalent of the market or field price before the conversion or transportation of the gas produced. This market or field price (per MCF) has been finally determined by the respondent to be the following:
Gas 1948 1949 1950 1951 Sweet $ 0.043602 $ 0.044427 $ 0.043898 $ 0.049699 Sour .041425 .041323 .041861 .048224 Casinghead .039497 .031852 .031187 .039618 Weighted average .041876 .041106 .040681 .047353 Gas 1952 1953 1954 Sweet $ 0.054298 $ 0.062649 $ 0.072486 Sour .055060 .054893 .061690 Casinghead .050746 .051306 .048840 Weighted Average .054181 .055800 .061317 Shamrock, *204 in its first amended petition in these dockets, allegesthat the amount of depletion claimed on its returns was less than the amount of depletion to which it was entitled. Claim is accordingly made by Shamrock that its income tax for the fiscal years 1948 through 1954 was overpaid. The amounts of overpayment are alleged to be not less than the following amounts:
1948 $ 23,065.45 1949 33,473.60 1950 73,972.51 1951 131,877.66 1952 153,224.35 1953 132,994.75 1954 113,831.99 Shamrock contends that the gross income from the property at the wellhead, for depletion purposes, in terms of price per MCF, was as follows:
1948 $ 0.081003 1949 .067785 1950 .062656 1951 .070763 1952 .072186 1953 .079313 1954 .087243 This amount of gross income from the property, in terms of price per MCF, is proposed by Shamrock as the amount for which it sold the gas in the immediate vicinity of the well and as the representative market or field price of the gas. Alternative amounts of gross income for each of the fiscal years in issue are proposed by Shamrock as the representative market or field price if the same is to be determined by *983 other sales. These amounts are set forth to be not less than 6 1/2 cents per MCF foreach of the years *205 1948, 1949, and 1950, 7 1/2 cents per MCF for 1951, 8 cents per MCF for 1952, 8 1/2 cents per MCF for 1953, and 9 1/2 cents per MCF for 1954.
Based on these amounts per MCF stated above, Shamrock computes its gross income from the property, allowable percentage depletion, and amount of income tax overpaid in the following amounts:
Gross income Percentage Overpayment depletion 1948 $ 4,431,021.85 $ 1,218,531.01 $ 23,065.45 1949 5,341,355.76 1,468,872.83 33,473.60 1950 5,494,012.74 1,510,853.50 73,972.51 1951 5,973,652.20 1,642,754.35 131,877.66 1952 5,874,591.44 1,615,512.65 153,224.35 1953 6,348,503.20 1,745,838.00 132,994.75 1954 7,132,385.49 1,961,406.01 113,831.99 In these dockets, Shamrock makes the same further allegation as it made in Docket No. 49145, that is, that in the event it is mistaken in its allegations as to the proper method of determining the gross income from the property, the gross income should be the proceeds from the sale of the residue gas plus a sum equal to an amount not less than 58.8 percent of the proceeds of all natural gasoline. Gross income so calculated by Shamrock is the following:
1948 $ 6,112,670.52 1949 7,367,760.86 1950 7,235,829.79 1951 7,625,687.71 1952 7,569,782.93 1953 7,505,966.84 1954 8,987,914.26 II. *206
Bonus Issue .In Docket Nos. 61315, 68580, and 77791, Shamrock raises an additional issue, concerning the treatment of bonuses, upon which it predicates a claim for additional overpayment of tax. Shamrock first contends that the total amount of bonuses or initial payments, paid or incurred by it with respect to mineral leases acquired from lessors who retained an economic interest in the property, should be deducted in full from gross income in the year in which paid or incurred. A second and alternative contention is that if such bonuses paid or incurred are held to be advance or prepaid royalties not deductible in full in the year paid, then a proportionate amount based on the anticipated productive life of the leases should be deducted from gross income. A third contention is that if neither the full amount nor a proportionate amount of the bonuses may be deducted from gross income, and the bonuses are considered or treated as capital expenditures, then the respondent erred in deducting from "gross income from the property" before computing percentage depletion a proportionate amount of the bonuses so paid.
*984 The amounts in issue in respect of the bonuses paidand the alleged overpayments *207 of income tax are as follows:
Entire amount First Contention: deductible Overpayment 1948 $ 276,441.11 $ 105,047.62 1949 177,630.31 67,499.51 1950 287,024.73 117,479.22 1951 30,266.20 15,201.20 1952 168,728.19 87,738.66 1953 302,237.68 157,163.59 1954 408,387.75 212,361.63 Proportionate amount Second Contention: deductible Overpayment 1948 $ 17,006.30 $ 6,462.43 1949 18,331.85 6,966.10 1950 19,920.90 8,153.62 1951 21,713.41 10,905.56 1952 24,532.01 12,756.95 1953 28,829.12 14,991.14 1954 33,756.15 17,553.20 Amount deducted from "gross income from the property" Third Contention: Capital investment (allocate part) 1948 $ 276,441.11 $ 17,006.39 1949 177,630.31 18,331.85 1950 287,024.73 19,920.90 1951 30,266.20 21,713.41 1952 168,728.19 24,532.01 1953 302,237.68 28,829.12 1954 408,387.75 33,756.15 Loss in percentage Third Contention: depletion allowance Overpayment 1948 $ 4,676.76 $ 1,777.17 1949 5,041.26 1,915.68 1950 5,478.25 2,242.25 1951 5,971.18 2,999.03 1952 6,746.30 3,508.07 1953 6,003.01 2,375.13 1954 9,282.94 4,827.13 Theissues for decision are:
(1) What is the "gross income from the property" for the taxable years ending November 30, 1943, through November 30, 1954, with respect to natural gas in which petitioner owned an economic interest that was produced by petitioner *208 and processed by petitioner in its gasoline extraction plants?
(2) May petitioner's expenditures for oil and gas lease bonuses be deducted from gross income, either in the year in which paid or over the estimated life of the leases for which paid, or if the expenditures for bonuses are to be treated as capital expenditures, for computing percentage depletion, must petitioner's "gross income from the property" be reduced by the amount of such bonuses over the estimated life of the leases?
FINDINGS OF FACT.
Some of the facts have been stipulated and are hereby found as stipulated.
The Shamrock Oil and Gas Corporation, hereinafter referred to as Shamrock, was incorporated in 1929 and during all of the period here involved, i.e., from December 1, 1942, through November 30, 1954, *985 kept its books on a fiscal year basis and on an accrual basis of accounting. The taxable years involved are the fiscal years ending November 30 of1943, 1944, 1945, 1946, 1947, 1948, 1949, 1950, 1951, 1952, 1953, and 1954.
Shamrock filed corporation income and declared value excess-profits tax returns and corporate excess profits tax returns for the fiscal years 1943 to 1946, inclusive, and corporate income tax returns *209 for the fiscal years 1947 to 1954, inclusive, with the district director of internal revenue or his predecessor at Dallas, Texas.
Shamrock is an independent oil company with integrated operations for the production and processing of oil and gas and for the distribution and sale of oil and gas products to pipelines, industrial users, carbon black companies, and to Shamrock's dealers in eight States.
All of the natural gas, with respect to which there is any controversy regarding what was the "gross income from the property" for the purpose of computing percentage depletion, was produced by Shamrock and was processed in Shamrock's gasoline extraction plants.
Shamrock's principal operations for the production of natural gas have been in the West Panhandle gasfield of Texas and in the Texas Hugoton gasfield.
The Panhandle and Hugoton Gasfields .The Panhandle gasfield starts in the eastern part of Wheeler Countyand extends northwestward across portions of Collingsworth, Gray, Hutchinson, Potter, Carson, and Moore Counties, Texas, into Dallam County, Texas, where it connects with the Texas portion of the Hugoton field. There is no physical separation between the fields designated as the East *210 Panhandle field, the West Panhandle field, the TexasHugoton, Oklahoma Hugoton, or Kansas Hugoton fileds. The "East Panhandle" and the "West Panhandle" fields and the area designated "Texas Hugoton field" are all located in the State of Texas.
The East Panhandle and West Panhandle fields are both a part of the same common reservoir and are separated by the Railroad Commission of Texas for administration purposes rather than because of physical differences.
Gas was first discovered in the Panhandle of Texas in a well started in 1918 and completed in 1919 at a point approximately 20 miles north of Amarillo, Texas. Gas was first discovered in the Kansas portion of the Hugoton field in 1922 at about the same time it was discovered in what is now the Oklahoma Hugoton field. Exploration began to find production in the Texas Hugoton field as early as 1940, but it was not thought that the fields were connecteduntil about 1946 when sufficient wells had been drilled to definitely establish the connection between them.
*986 The Oklahoma Hugoton and Kansas Hugoton fields are located in those respective States.
The Panhandle field, consisting of both the East and West Panhandle fields, contains approximately *211 1,500,000 acres and is approximately 120 miles in length in an eastward and westward direction, and varies in width from 10 to approximately 50 miles. The Hugoton field extending from point of connection with Panhandle field to the northern limits of the Kansas Hugoton field, is approximately 160 miles. The total distance from the top of the Kansas Hugoton field down through the Panhandle field to its eastern tip is approximately 280 miles. Before it was known that the Panhandle field and the Hugoton field were connected, the Panhandle gasfield was known as the largest gas-producing area in the world. The Hugoton field covers approximately 900,000 acres in Oklahoma, 2,400,000 acres in Kansas, and about 640,000 acres in Texas. This, with approximately 1,500,000 to 1,600,000 acres in the Panhandle field, brings the entire reservoir, i.e., Panhandle and Hugoton fields, to approximately5,500,000 acres.
The East Panhandle field, the West Panhandle field, and the Texas portion of the Hugoton field, as well as Kansas, Oklahoma, and Texas portion of the Hugoton field are all in one reservoir which is uninterrupted and connected all the way.
The reservoir pressure in the Panhandle gasfield *212 at the beginning was approximately 430 pounds per square inch. As gas has been produced through the years there have been declines in reservoir pressure from the original reservoir or rock pressure. The virgin pressure of 430 pounds per square inch was not the average pressure during the taxable years here involved. At the beginning of the taxable period the weighted average pressure in the sour gas area was approximately 350 pounds. The normal decline or withdrawals in the sour gas area has been from 10 to 12 pounds a year.
At the beginning of the taxable period the pressure in the Texas Hugoton field was very close to the virgin pressure of 430 pounds per square inch. At that time the average pressure in the sour gas portion of the field was approximately 100 pounds less than that of 430 pounds per square inch. As gas has been produced since that time pressure has become lowerin proportion to the withdrawals.
Petitioner first made an investment in compression equipment in fiscal year 1948. The purpose of the compression equipment was to maintain pressures in the lines and plants at about a 200-pound level. In later years, further investment was made by petitioner for the construction *213 of additional compression plants.
Little development occurred in the Panhandle field at first because the initial well had about one-third of the normal rock pressure for *987 the depth from which gas was produced, and it was thought to be a freak well. Additionally, the area was not heavily populated. The rapid development of the field did not start until the Borger, Texas, boom in about 1925 with the development of an oilfield which is along the north portion or rim of the Panhandle field.
The Texas Hugoton field, in general, produces what is known as sweet gas while the Panhandle field produces both sweet and sour gas. Sour and sweet gas are both produced from the same reservoir in the Panhandle field.
In the West Panhandle field, the sour gas supply is higher in heating value than the sweet gas. This is not a result of the gas containing sulphur. The richergas is normally found closer to the oil production and the sour gas adjoins the oil-producing area of the Texas Panhandle.
A royalty interest is a right to oil and gas in place that entitles its owner to a specified fraction, in kind or in value, of the total production from the property, free of expense of development and operation. *214 In Texas, customarily, a royalty owner receives one-eighth of the value of the gas.
The working interest is an interest in oil and gas in place that is burdened with the cost of development and operation of the property.
An overriding royalty is similar to a royalty in that each is a right to oil and gas in place that entitles its owner to a specified fraction of production, in kind or in value, and neither is burdened with the costs of development or operation. They differ in that an overriding royalty is created from the working interest, and its term is coextensive with that of the working interest from which it was created.
Raw gas is the gas as it comes from the well. Raw gas as it emerges from the wellhead is in a gaseous state. It is a colorless gas and essentially is a mixture of gases in equilibrium. The mixture of gas consists principallyof hydrocarbons in a gaseous form.
Residue gas is that portion of the raw gas which remains after the extraction of the liquefiable hydrocarbons which are present in the raw gas. The residue is that portion which is marketed as a gas after the liquefiable hydrocarbons are extracted. Raw natural gas in the Panhandle is composed of the residue *215 elements and the liquefiable hydrocarbons.
All raw natural gas contains some liquefiable hydrocarbons in suspension. The liquefiable hydrocarbons that are generally extracted in the Panhandle field are propane, isobutane, normal butane, isopentane, normal pentane, and the remaining heaviest portion, generally called hexane-plus.
*988 Natural gasoline includes all of these hydrocarbons in their liquid state. In the industry it is customary to apply the term natural gasoline to that portion of these liquids used by refineries in blending motor fuels. Isopentane, normal pentane, and hexanes are the same as natural gasoline. Motor fuel is motor gasoline, a finished gasoline.
In the Panhandle field, methane is the principal constituent of the natural gas and constitutes approximately 80 percent of the total volume of the raw gas. If allof the liquefiable hydrocarbons from propane or heavier hydrocarbons were removed from the Panhandle gas, approximately 95 percent of the volume of the original raw gas would remain.
Residue gas is made up principally of methane, but it also includes ethane and some inert elements such as carbon dioxide, nitrogen, and helium.
Gas, raw or residue, may be either *216 sour gas or sweet gas. Sour gas is natural gas having more than 1 1/2 grains of hydrogen sulphide per 100 cubic feet, or more than 30 grains of total sulphur per 100 cubic feet. Sweet gas is all natural gas except sour and casinghead gas. Casinghead gas is any gas and/or vapor indigenous to any oil stratum and produced from such stratum with oil. Casinghead gas is gas produced with oil and comes out of solution with the oil.
Natural gas includes sweet gas, sour gas, and casinghead gas taken from the earth through gas wells, oil wells, or distillate wells.
Sour gas, before removal of the hydrogen sulphide, is not desirable for light and fuel purposes because, in burning, it produces a poisonous gas, is corrosive, and has a bad rotten-egg odor.
The heating value of sweet and sour gas is comparable. The raw sweet gas in theWest Panhandle field has a B.t.u. content of approximately 1,060 B.t.u.'s per cubic foot. Raw sour gas has a B.t.u. content of approximately 1,070 B.t.u.'s per cubic foot. The raw sweet gas in the Hugoton field portion of the Texas Panhandle has a lower heating value and ranges a little below 1,000 B.t.u.'s per cubic foot because of a higher nitrogen content.
B.t.u., *217 or British thermal unit, is a standard of measurement for determining the heating value of gas.
The terms "dry gas" and "wet gas" are relative terms. Dry gas generally means gas produced from a well which does not produce oil. Cashinghead gas, sometimes called wet gas, is produced from a well which does produce oil. Wet gas contains a higher percentage of liquefiable hydrocarbons. In the oil and gas industry, the term "wet gas" is applied generally to gas having a high content of liquefiable hydrocarbons.
"LPG," or liquefied petroleum gas, consists usually of a mixture of propane and butane and is used as a gas for domestic and some industrial purposes where natural gas is not available.
*989 Drip gasoline is a term applied to the liquefiable hydrocarbons which take on a liquid form in the gathering lines asa result of the lowering of temperature and pressure. The amount of drip gasoline which forms in the gathering line depends on the temperature and pressure in the lines, but is usually of a small quantity.
A wellhead sale of gas is a sale where the purchaser lays a line to receive the gas at the wellhead on the lease. The wellhead on a gas well is the valve at the top of the ground that *218 closes the well after production is found and is the valve on the top of the pipe that extends down into the hole in the ground.
A so-called "NGAA contract" was a form of contract which was at one time proposed by the Natural Gas Association of America. A "modified NGAA contract" is a form of contract for the purchase of gas which provides for the determination of the price by the addition of a portion of the sales price for residue gas and a portion of the sales price or value of the liquids recovered.
The term "rolled in price" as used by petitioner means a combination of lower prices and higher prices resulting in an average price. Such an average price might occur in the renegotiation of a contract for the sale of gas where a new provision is added to the contract, such as increased volume to be delivered. The price set forth in the renegotiated contract for all the gas to be delivered might be an average price taking into account the price originally specified in the old contract for the volume to be delivered under that contract and a new price for the added volume to be delivered under the renegotiated contract.
Gathering lines are the lines that extend from the individual wells *219 to the plant where the gas is processed for the extraction of natural gas liquids. The lines that extend beyond the extraction plant are referred to as residue or delivery lines. A transmission line is a line that carries the gas to market after it has been received in that pipeline in order to make it available to transport to the market at some distance.
During all of the period in question (i.e., from December 1, 1942, through November 30, 1954) Shamrock owned in whole or in part economic interests in the gas produced from certain properties (various producing gaswells and leases) in Moore, Hartley, and Hutchinson Counties, Texas, in the West Panhandle gasfield in the Panhandle of Texas, and during a portion of such period Shamrock additionally owned, in whole or in part, economic interestsin the gas produced from certain properties (various producing gaswells and leases) in Moore, Sherman, Dallam, and Hansford Counties, Texas, in the Texas portion of the Hugoton gasfield in the Panhandle of Texas.
*990 Leases were obtained by Shamrock on the properties from which gas was produced and in respect of which gas Shamrock had an economic interest. The number of leases obtained in the years *220 from 1926 to 1954, broken down into the different type gas properties, is set forth in the schedule below:
Sour gas Sweet gas Casinghead property property gas property leases leases leases 1926 30 1 1927 7 1 1928 1 1929 1 1930 5 3 1931 2 1932 1933 1 1934 1 3 1935 2 5 1936 40 15 3 1937 21 11 1 1938 7 16 1939 11 1 1940 15 1 1 1941 8 5 1 1942 5 5 1 1943 4 16 1944 25 123 1 1945 37 12 2 1946 12 15 1 1947 16 12 9 1948 9 5 10 1949 36 1 1950 3 1951 1 1952 1 1 1953 2 3 1954 1 1 During all of the period from 1943 through 1954, it was Shamrock's practice to expand its acreage holding, both producing and nonproducing, to the extent it was economically able to do so. The reason for increasing both producingand nonproducing acreage was to replace the depletion of supply and to put together additional gas supplies that could be marketed to an advantage. Shamrock's lease acreage, both producing and nonproducing, during the taxable years, in the counties designated, is shown by the following table:
*221Shamrock's Producing and Nonproducing Gas Lease Acreage in Moore, Hutchinson, Sherman, Dallam, Hansford, and Hartley Counties at End of Fiscal Years 1944 Through 1954. County 1944 1945 1946 1947 1948 1949 Moore: Producing 24,725.16 43,328.59 51,194.12 54,303.37 53,030.52 56,687.19 Nonproducing 35,578.64 20,567.57 23,983.91 26,750.14 33,425.58 29,665.85 Hutchinson: Producing 2,195.36 2,195.36 2,195.36 2,845.60 4,118.10 4,627.36 Nonproducing 805.51 805.51 805.51 3,835.27 4,831.51 5,522.25 Sherman: Producing 9,960.33 23,133.09 28,713.92 Nonproducing 63,956.89 70,267.21 71,193.21 63,153.27 46,133.33 41,687.76 Dallam: Producing 213.00 213.00 Nonproducing 21,843.33 20,296.33 24,719.20 52,750.62 71,961.41 71,996.63 Hansford: Producing Nonproducing 1,028.00 1,028.00 1,319.82 Hartley: Producing Nonproducing 2,150.38 2,154.01 Shamrock's Producing and Nonproducing Gas Lease Acreage in Moore, Hutchinson, Sherman, Dallam, Hansford, and Hartley Counties at End of Fiscal Years 1944 Through 1954. County 1950 1951 1952 1953 1954 Moore: Producing 59,575.26 65,422.85 72,821.33 77,828.61 84,005.75 Nonproducing 26,910.49 21,132.91 14,457.09 10,141.43 4,861.42 Hutchinson: Producing 4,950.87 4,950.87 5,110.87 7,980.87 8,160.87 Nonproducing 5,548.85 5,548.85 5,548.85 5,568.85 5,388.85 Sherman: Producing 32,560.72 49,015.44 58,409.74 65,818.11 69,156.56 Nonproducing 36,792.11 17,568.89 8,616.83 4,535.74 7,445.34 Dallam: Producing 213.00 213.00 415.48 415.48 415.48 Nonproducing 73,521.31 69,158.81 65,072.45 64,272.45 63,572.16 Hansford: Producing 291.82 291.82 291.82 Nonproducing 1,560.76 1,560.76 1,268.94 1,268.94 5,508.94 Hartley: Producing 437.50 Nonproducing 8,348.45 8,348.45 22,707.48 22,707.48 22,266.35 *991 After November 30, 1942, Shamrock continued to expand its exploration to obtain raw gas and attempted to obtain more sour gas at that time as well as sweet gas. Shamrock attempted to obtainmore production of all kinds.
Many of the individual leases obtained by Shamrock were for fractional interests in gas properties. The usual drilling unit for spacing gaswells is a section or a tract of 640 *222 acres. Following is a schedule of property units, grouped in terms of acreage, on which Shamrock had leasehold interests and from which gas was produced and processed in Shamrock's McKee or Sunray gasoline extraction plants:
Leasehold Interests Acres 0-200 201-400 401-600 601-800 Sour 23 23 11 74 Sweet 4 9 7 108 Casinghead 9 7 1 4 Number of Property Units, in Terms of Acreage, on Which Shamrock Had Leasehold Interests Acres 801-1,000 1,001-1,200 1,200-1,400 1,401-1,600 Sour 1 1 1 Sweet 2 Casinghead Number of Property Units, in Terms of Acreage, on Which Shamrock Had Leasehold Interests Acres 1,601-1,800 1,801-2,000 2,001-2,500 2,501-3,000 Sour 2 2 1 Sweet Casinghead 1 Production was commenced on these several propertiesat different times during the years. Production starts, or wells which commenced to produce, are shown by year and type of gas produced: *992
Sour gas Sweet gas Casinghead gas 1930 3 1931 1 1932 1933 2 1934 5 1935 4 1936 14 1937 7 3 1938 3 1 1939 3 1 1940 3 1941 5 1 1942 5 1 1943 2 1944 3 3 1945 25 9 1946 5 12 1947 8 19 3 1948 3 16 3 1949 11 5 4 1950 4 9 2 1951 9 28 1 1952 14 14 1953 12 5 1954 6 8 1 1955 1 The number of properties from which gas was produced *223 in the years in issue was as follows:
Sour gas Sweet gas Casinghead Total properties properties gas properties properties 1943 47 3 50 1944 47 5 52 1945 69 7 76 1946 78 14 92 1947 87 25 6 118 1948 90 38 10 138 1949 100 42 13 155 1950 103 47 14 164 1951 107 59 14 180 1952 120 66 15 201 1953 123 68 22 213 1954 126 76 23 225 The following table shows the number of Shamrock wholly or partially owned wells in the West Panhandle and Hugoton gasfields which were connected to the McKee and Sunray plants at the end of the fiscal years 1943 through 1954 and the distances of suchwells from those plants: *993
*224Number of Shamrock Wholly or Partially Owned Wells in West Panhandle and Hugoton Gas Fields Connected to McKee and Sunray Plants at End of Fiscal Years 1943 Through 1954 and Distances of Such Wells From Said Plants Number of Number of wells connected well connected to McKee to Sunray (M) Plant (S) Plant 1943 West Panhandle gasfield 58 Hugoton gasfield 1944 West Panhandle gasfield 61 Hugoton gasfield 1945 West Panhandle gasfield 91 Hugoton gasfield 1946 West Panhandle gasfield 108 Hugoton gasfield 1947 West Panhandle gasfield 105 16 Hugoton gasfield 17 1948 West Panhandle gasfield 106 18 Hugoton gasfield 45 1949 West Panhandle gasfield 112 19 Hugoton gasfield 54 1950 West Panhandle gasfield 114 19 Hugoton gasfield 63 1951 West Panhandle gasfield 117 19 Hugoton gasfield 102 1952 West Panhandle gasfield 121 22 Hugoton gasfield 123 1953 West Panhandle gasfield 132 29 Hugoton gasfield 126 1954 West Panhandle gasfield 136 29 Hugoton gasfield 134 Number of Shamrock Wholly or Partially Owned Wells in West Panhandle and Hugoton Gas Fields Connected to McKee and Sunray Plants at End of Fiscal Years 1943 Through 1954 and Distances of Such Wells From Said Plants Location of wells in relation to plants -- miles from respective plants 0-5 5-10 10-15 15-20 20-25 25-30 M S M S M S M S M S M S 1943 West Panhandle gasfield 39 14 3 2 Hugoton gasfield 1944 West Panhandle gasfield 39 15 5 2 Hugoton gasfield 1945 West Panhandle gasfield 43 23 18 7 Hugoton gasfield 1946 West Panhandle gasfield 46 25 26 10 1 Hugoton gasfield 1947 West Panhandle gasfield 54 7 18 3 25 6 7 1 Hugoton gasfield 4 2 7 4 1948 West Panhandle gasfield 54 7 17 4 27 6 7 1 1 Hugoton gasfield 7 3 20 14 1 1949 West Panhandle gasfield 58 7 18 4 28 6 7 2 1 Hugoton gasfield 1 9 3 20 19 2 1950 West Panhandle gasfield 60 7 18 4 28 5 7 3 1 Hugoton gasfield 2 11 3 20 21 6 1951 West Panhandle gasfield 63 7 18 4 28 7 3 1 Hugoton gasfield 3 28 7 34 24 6 1952 West Panhandle gasfield 64 7 21 5 28 6 7 4 1 Hugoton gasfield 3 34 8 48 24 6 1953 West Panhandle gasfield 67 10 26 5 30 10 7 4 1 1 Hugoton gasfield 3 35 9 49 24 6 1954 West Panhandle gasfield 67 10 29 6 31 10 7 3 1 1 Hugoton gasfield 3 37 12 51 24 7 *994 Shamrock did not have an economic interest in all the gas which it produced. The following schedule sets forth production statistics for Shamrock's producing properties *225 on which Shamrock had a leasehold interest and shows the total production from those properties and the volume interest of that production in which Shamrock had an economic or depletable interest:
Production Statistics for Producing Properties on Which Shamrock Had a Leasehold Interest Number of Total Shamrock's Fiscal year and type of property producing production volume properties interest 1943 Sour 47 42,797,846 33,152,426 Sweet 3 5,573,552 4,876,858 Casinghead 1944 Sour 47 46,713,866 36,185,839 Sweet 5 6,160,625 5,390,548 Casinghead 1945 Sour 69 57,716,236 45,690,510 Sweet 7 6,362,110 5,421,502 Casinghead 1946 Sour 78 63,472,389 51,416,735 Sweet 14 8,693,018 7,156,934 Casinghead 1947 Sour 87 59,947,042 48,518,539 Sweet 25 14,949,759 12,435,818 Casinghead 6 94,010 81,742 1948 Sour 90 63,172,931 49,934,823 Sweet 38 22,515,171 17,631,858 Casinghead 10 701,449 602,886 1949 Sour 100 80,943,210 64,106,207 Sweet 42 21,982,241 17,000,100 Casinghead 13 1,242,670 1,068,397 1950 Sour 103 81,087,868 63,917,913 Sweet 47 24,788,533 19,395,429 Casinghead 14 1,408,323 1,209,931 1951 Sour 107 74,032,637 56,825,870 Sweet 59 27,285,421 21,438,800 Casinghead 14 1,608,720 1,384,026 1952 Sour 120 64,116,724 49,666,349 Sweet 66 27,987,223 21,967,801 Casinghead 15 2,080,205 1,798,243 1953 Sour 123 64,347,817 49,508,315 Sweet 68 27,623,268 21,704,621 Casinghead 22 6,866,051 3,475,337 1954 Sour 126 60,441,142 46,712,381 Sweet 76 28,129,495 22,134,537 Casinghead 23 11,227,775 6,230,824 *226 *995 From 1943 to 1954, inclusive, the major portion of Shamrock's natural gas production consisted of sour gas.
The volume of gas set forth in the last column of the schedule immediately above, as Shamrock's volume interest in gas produced, entered Shamrock's gas-gathering system connected to Shamrock's McKee and Sunray gasoline extraction plants and this volume constituted part of the volume of gas which was available for processing in those plants.
Shamrock owned an economic interest in a total of 591 leaseholds on gas properties connected to Shamrock's extraction plants for the period covered by the fiscal years ended November 30, 1943, through November 30, 1954, not all of such leasehold estates being connected to the plants during such period, however. The leases between Shamrock and the royalty owners/lessors contained provisions whereby Shamrock was to pay the royalty to the royalty owners for their proportionate part of the gas production. There were 72 different gas royalty provisions in the total of 591 leases. The one provision which appeared in the most leases, 223 of the 591, provided as follows:
on gas, including casinghead gas, or other gaseous substance, produced from *227 said land and sold or used off the premises or in the manufacture of gasoline or other products therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale.
Following is a schedule of the proportionate part of the gas production acquired from the royalty owners by Shamrock:
Schedule of Gas Acquired by Shamrock From Royalty Owners for Years Ended Nov. 30, 1943 Through 1954 Sour Sweet Casinghead Overriding Total royalty 1943 5,274,576 696,695 720,371 6,691,642 1944 5,758,630 410,295 759,719 6,928,644 1945 7,043,161 514,306 756,439 8,313,906 1946 7,513,079 701,681 476,904 8,691,664 1947 7,367,159 1,654,173 12,300 597,292 9,630,924 1948 7,784,403 2,512,723 89,119 849,938 11,236,183 1949 10,519,809 2,470,371 158,604 822,957 13,971,741 1950 10,491,601 2,791,679 176,039 765,746 14,225,065 1951 9,148,112 3,073,141 200,691 869,055 13,090,999 1952 7,932,037 3,144,324 260,019 830,973 12,167,353 1953 7,826,502 3,124,939 1,021,555 1,237,999 13,210,995 1954 7,384,625 3,192,832 1,796,734 1,584,513 13,958,704 Subsequent to October 1, 1945, Shamrock endeavored to simplify its accounting to royalty owners and in place of the many different royalty *228 provisions contained in the separate leases Shamrock attempted to substitute a royalty computed on a flat basis. Most of the royalty payments subsequent to that date were made on this flat royalty basis. However, in instances where Shamrock had special *996 contracts or royalties fixed by contract different than the NGAA or flat royalty or unit rate the contract price prevailed.
Payment of gas royalties in the following amounts was made in the taxable years by Shamrock to the royalty owners for the production (by type of gas) acquired:
Schedule of Gas Royalties Paid by Shamrock to Royalty Owners for Fiscal Years 1943 to 1954 Inclusive Sour Gas MCF Amount Price per MCF 1943 5,274,576 $ 57,880.20 $ 0.010973 1944 5,758,630 66,778.67 .0115963 1945 7,043,161 108,427.12 .015395 1946 7,513,079 226,111.98 .030096 1947 7,367,159 231,683.26 .031448 1948 7,784,403 306,557.16 .039381 1949 10,519,809 422,757.35 .040187 1950 10,491,601 464,238.53 .044249 1951 9,148,112 453,864.36 .049613 1952 7,932,037 477,216.71 .056381 1953 7,826,502 447,982.81 .061072 1954 7,384,625 488,689.86 .066177 Sweet Gas 1943 696,695 9,736.28 .013975 1944 410,295 12,299.87 .029978 1945 514,306 17,643.08 .034305 1946 701,681 24,624.77 .035094 1947 1,654,173 60,646.72 .036869 1948 2,512,723 110,391.37 .043933 1949 2,470,371 109,662.33 .044391 1950 2,791,679 138,838.43 .049733 1951 3,073,141 171,911.65 .055940 1952 3,144,324 194,605.56 .061891 1953 3,124,939 207,755.09 .066483 1954 3,192,832 228,882.40 .071686 Casinghead Gas 1947 12,300 369.05 .030004 1948 89,119 3,243.95 .036400 1949 158,604 5,092.92 .032111 1950 176,039 5,335.43 .030308 1951 200,691 6,377.08 .031776 1952 260,019 8,986.77 .034562 1953 1,021,555 48,477.06 .047454 1954 1,796,734 82,795.45 .046081 *229 The following table sets forth the same data with respect to overriding royalties: *997
Schedule of Gas Royalties Paid by Shamrock to Royalty Owners for Fiscal Years 1943 to 1954 Inclusive Overriding Royalties Sour Sweet MCF Amount Price per MCF Amount Price per MCF MCF 1943 720,371 $ 7,936.40 $ 0.011017 1944 759,719 8,822.11 .011612 1945 756,439 9,383.18 .012404 1946 469,776 8,520.39 .018137 7,128 $ 254.72 $ 0.03574 1947 433,269 13,358.12 .030831 163,505 5,842.31 .035732 1948 554,704 21,185.85 .038193 284,351 11,246.67 .039552 1949 564,720 18,296.85 .032400 234,264 8,677.27 .037041 1950 482,856 16,705.67 .034598 260,541 11,932.37 .045798 1951 525,984 22,427.93 .042640 322,487 17,693.55 .054866 1952 484,394 22,611.87 .046681 324,639 19,442.61 .059890 1953 675,280 35,180.08 .052097 307,109 19,967.72 .065018 1954 766,215 47,401.81 .061865 316,780 22,250.81 .070241 Schedule of Gas Royalties Paid by Shamrock to Royalty Owners for Fiscal Years 1943 to 1954 Inclusive Overriding Royalties Casinghead MCF Amount Price per MCF 1943 1944 1945 1946 1947 518 $ 15.54 $ 0.030000 1948 10,883 501.32 .046065 1949 23,973 792.34 .033051 1950 22,349 675.84 .030240 1951 20,584 666.42 .032376 1952 21,940 759.94 .034637 1953 255,610 12,250.47 .047926 1954 501,518 23,231.18 .046322 In all, or practically all, of the cases where Shamrock had *230 a partnership or joint interest with others, Shamrock purchased the gas of its partner or joint owner. Following is a schedule of gas purchased by Shamrock from the working interest of others in Shamrock leases, for the fiscal years indicated:
Shamrock Schedule of Gas Purchases From Working Interest of Others in Shamrock Leases for Years Ended No. 30, 1943 Through 1954, Inclusive Number of Volume -- contracts MCF 14.65 PSIA 1943 5 3,575,339 1944 5 3,930,223 1945 7 4,156,429 1946 10 4,128,787 1947 8 2,919,362 1948 15 4,233,092 1949 20 6,481,573 1950 21 7,598,320 1951 21 7,200,089 1952 21 5,907,040 1953 21 5,571,277 1954 20 4,994,952 The following table shows a detailed breakdown of gas purchased from the working interest of others in Shamrock leases (1943-1954) in terms of MCF and price per MCF: *998
*231Schedule of Gas Purchased From Working Interest of Others in Shamrock Leases 1943-1954 in Terms of MCF and Price per MCF 1943 1944 Purchased from -- Type of gas Volume Price Volume Price H. C. Fownes II Sour 400,058 $ 0.010957 445,880 $ 0.011726 Warren Oil Corp., Dye, do 1,749,668 .011095 1,869,367 .011857 Solow, Cornell & King. E. B. Clark do 350,047 .010917 443,852 .011620 Phillips Petroleum Co do 423,304 .011072 442,334 .011662 Magnolia Petroleum Co do Magnolia Petroleum Co Sweet Shell Oil Co do Sinclair Oil & Gas Sour Magnolia Petroleum Co do E. W. Means Sweet E. W. Means do Dave Rubin Sour Sinclair Oil & Gas Co Sweet Smith & Fowlston do Continental Oil Co Sour 652,262 .010738 728,790 .011205 Shell-Sinclair do Texas Company do Schedule of Gas Purchased From Working Interest of Others in Shamrock Leases 1943-1954 in Terms of MCF and Price per MCF 1945 1946 Purchased from -- Volume Price Volume Price H. C. Fownes II 480,986 $ 0.012433 361,171 $ 0.029343 Warren Oil Corp., Dye, 1,851,008 .012476 1,553,084 .029427 Solow, Cornell & King. E. B. Clark 441,769 .012479 340,761 .029947 Phillips Petroleum Co 483,220 .012458 333,248 .029561 Magnolia Petroleum Co 13,302 .012467 253,671 .029588 Magnolia Petroleum Co 145,345 .031265 392,429 .031265 Shell Oil Co 57,029 .031265 Sinclair Oil & Gas 82,422 .031265 Magnolia Petroleum Co E. W. Means E. W. Means Dave Rubin Sinclair Oil & Gas Co Smith & Fowlston Continental Oil Co 740,799 .012260 534,927 .029552 Shell-Sinclair 220,045 .029784 Texas Company
*232Schedule of Gas Purchased From Working Interest of Others in Shamrock Leases 1943-1954 in Terms of MCF and Price per MCF 1947 1948 Purchased from -- Volume Price Volume Price H. C. Fownes II 274,253 $ 0.031265 242,657 $ 0.035512 Warren Oil Corp., Dye, 1,196,134 .031265 1,028,898 .037121 Solow, Cornell & King. E. B. Clark 287,721 .031265 275,122 .036743 Phillips Petroleum Co 299,961 .031265 298,008 .036900 Magnolia Petroleum Co 225,122 .031265 198,931 .034541 Magnolia Petroleum Co 338,689 .031265 266,815 .039440 Shell Oil Co 72,182 .031265 130,954 .038755 Sinclair Oil & Gas 225,300 .031265 243,180 .034012 Magnolia Petroleum Co 686,499 .035223 E. W. Means 1,858 .038546 E. W. Means 294,898 .040087 Dave Rubin 17,251 .046360 Sinclair Oil & Gas Co 197,134 .037883 Smith & Fowlston 313,963 .040198 Continental Oil Co Shell-Sinclair Texas Company 36,924 .044049
*233Schedule of Gas Purchased From Working Interest of Others in Shamrock Leases 1943-1954 in Terms of MCF and Price per MCF 1949 1950 Purchased from Type of gas Volume Price Volume Price H. C. Fownes II Sour 69,613 $ 0.032417 63,391 $ 0.039786 Warren Oil Corp., Dye, do 1433,963 .043242 1,047,118 .041498 Solow, Cornell & King. E. B. Clark do 198,355 .031095 192,826 .034279 Phillips Petroleum Co do 317,668 .032199 252,424 .028264 Magnolia Petroleum Co do 189,672 .029298 159,548 .028337 Magnolia Petroleum Co Sweet 206,719 .040198 203,110 .040198 Shell Oil Co do 166,293 .040198 167,447 .040198 Sinclair Oil & Gas Sour 242,577 .030317 213,415 .028527 Magnolia Petroleum Co do 1,267,031 .029823 1,172,603 .028528 E. W. Means Sweet 21,784 .038864 28,858 .039457 E. W. Means do 259,350 .039642 331,660 .039651 Dave Rubin Sour 26,073 .048642 7,207 .047201 Sinclair Oil & Gas Co Sweet 203,217 .040198 200,541 .040198 Smith & Fowlston do 572,915 .039969 641,447 .039814 Magnolia Petroleum Co Sour 520,215 .035322 1,387,282 .035407 Magnolia Petroleum Co do 16,371 .047375 32,012 .047091 Fowlston & Price Sweet 40,857 .039913 56,344 .040074 J. W. Huff Sour 428,556 .044665 1,137,554 .044665 Sinclair Oil & Gas and do 257,234 .028571 246,638 .028029 Magnolia Petroleum Co. Magnolia Petroleum Co do 18,067 .047881 Texas Company do 43,110 .041837 38,828 .040459 Schedule of Gas Purchased From Working Interest of Others in Shamrock Leases 1943-1954 in Terms of MCF and Price per MCF 1951 1952 Purchased from Volume Price Volume Price H. C. Fownes II 54,228 $ 0.049122 49,406 $ 0.050000 Warren Oil Corp., Dye, 1,060,116 .045797 927,585 .047201 Solow, Cornell & King. E. B. Clark 186,490 .045000 166,206 .045000 Phillips Petroleum Co 292,843 .033207 221,153 .035593 Magnolia Petroleum Co 133,086 .031802 110,664 .034631 Magnolia Petroleum Co 211,504 .053176 182,313 .056478 Shell Oil Co 156,707 .053425 160,100 .056404 Sinclair Oil & Gas 201,219 .032528 176,113 .045434 Magnolia Petroleum Co 1,391,536 .032330 1,122,107 .034758 E. W. Means 23,833 .039477 47,233 .039199 E. W. Means 293,622 .039581 235,639 .039536 Dave Rubin 4,324 .049796 2,624 .051955 Sinclair Oil & Gas Co 178,923 .049260 171,440 .054788 Smith & Fowlston 600,136 .039962 487,744 .039979 Magnolia Petroleum Co 1,262,574 .035414 1,005,250 .044647 Magnolia Petroleum Co 23,170 .049907 22,427 .051783 Fowlston & Price 57,556 .040078 43,233 .040036 J. W. Huff 711,969 .044665 501,500 .044665 Sinclair Oil & Gas and 283,558 .031805 206,941 .044032 Magnolia Petroleum Co. Magnolia Petroleum Co 28,465 .049675 21,978 .051535 Texas Company 44,230 .043868 45,384 .045224 Schedule of Gas Purchased From Working Interest of Others in Shamrock Leases 1943-1954 in Terms of MCF and Price per MCF 1953 1954 Purchased from Volume Price Volume Price H. C. Fownes II 47,823 $ 0.050000 32,793 $ 0.050000 Warren Oil Corp., Dye, 856,767 .051557 759,747 .056994 Solow, Cornell & King. E. B. Clark 151,384 .045000 129,804 .045000 Phillips Petroleum Co 257,049 .058662 226,468 .065000 Magnolia Petroleum Co 115,259 .036372 87,082 .039949 Magnolia Petroleum Co 166,812 .061692 144,509 .073504 Shell Oil Co 135,145 .062255 110,135 .074168 Sinclair Oil & Gas 167,705 .055000 142,186 .055000 Magnolia Petroleum Co 994,009 .036276 870,197 .039945 E. W. Means 74,588 .041820 79,166 .071794 E. W. Means 253,796 .057617 259,826 .072423 Dave Rubin 1,722 .056310 Sinclair Oil & Gas Co 154,301 .060000 124,200 .060000 Smith & Fowlston 452,336 .054985 438,478 .073751 Magnolia Petroleum Co 976,332 .056914 937,145 .068963 Magnolia Petroleum Co 20,939 .057561 21,392 .069576 Fowlston & Price 42,725 .039659 42,203 .067523 J. W. Huff 430,964 .044665 360,206 .059036 Sinclair Oil & Gas and 210,201 .055000 176,116 .055000 Magnolia Petroleum Co. Magnolia Petroleum Co 21,354 .057365 21,410 .068490 Texas Company 40,066 .050363 31,889 .056166 *234 *1000 The following schedule shows the weighted average paid for gas purchased from the working interest of others in Shamrock leases:
Schedule of Weighted Average Price Paid for Gas Purchased From Working Interest of Others in Shamrock Leases Weighted average price Year per MCF 1943 $ 0.010994 1944 .011673 1945 .013089 1946 .029775 1947 .031265 1948 .037117 1949 .036854 1950 .036844 1951 .039236 1952 .043073 1953 .050466 1954 .059552 In addition to purchasing gas from the working interests of others in its leases, Shamrock purchased casinghead gas during some of the years in issue. These purchases, by year, are set forth below:
Summary Schedule of Shamrock Casinghead Gas Purchases for Years Ended Nov. 30, 1947 Through 1954 Year Number of Volume-MCF contracts 14.65 PSIA 1947 2 29,914 1948 13 2,040,858 1949 19 4,109,306 1950 20 6,941,093 1951 20 6,491,648 1952 19 8,601,611 1953 23 6,949,313 1954 28 6,049,833 These casinghead gas purchases by Shamrock (1947 through 1954) in terms of MCF and price per MCF are set forth in detail in the following table:
*235Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954 in Terms of MCF and Price per MCF 1947 1948 Purchased from -- Volume Price Volume Price Shell Oil Co 22,817 $ 0.030000 135,142 $ 0.057794 Phillips Petroleum Co 7,097 .030000 304,359 .039161 Dave Rubin-Kerr- McGee 643,152 .036352 Gayden & Cree 34,590 .051847 Champlin Refining Co 21,461 .030092 Magnolia Petroleum Co 47,420 .062247 American Liberty Oil Co Holt Brothers 385 .086779 Kerr-McGee-Dave Rubin Power Petroleum Co 134,724 .032887 Rosenblum & Rubin Gold-Rubin Continental Oil Co 535,414 .037312 E. M. Solow Herman Brothers-Dollie Adams 114,831 .046376 Holt, Sparks & Plummer Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954 in Terms of MCF and Price per MCF 1949 1950 Purchased from -- Volume Price Volume Price Shell Oil Co 125,325 $ 0.039130 124,860 $ 0.032436 Phillips Petroleum Co 460,733 .031447 255,339 .030052 Dave Rubin-Kerr- McGee 231,123 .031076 1,784,121 .030300 Gayden & Cree 35,191 .041714 52,802 .036306 Champlin Refining Co 46,404 .030516 45,952 .03000 Magnolia Petroleum Co 83,803 .032272 122,914 .030394 American Liberty Oil Co 703,001 .031131 326,938 .030499 Holt Brothers 1,222 .053838 27,223 .031063 Kerr-McGee-Dave Rubin 101,001 .030268 138,618 .031507 Power Petroleum Co 193,593 .030551 70,627 .030692 Rosenblum & Rubin 63,562 .03000 Gold-Rubin 376,388 .030258 1,912,305 .030279 Continental Oil Co 596,123 .032906 860,778 .032072 E. M. Solow 36,636 .03000 Herman Brothers-Dollie Adams 117,946 .040100 93,787 .047551 Holt, Sparks & Plummer 11,026 .049838 40,125 .03000
*236Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954 in Terms of MCF and Price per MCF 1948 1949 Purchased from -- Volume Price Volume Price Service Drilling Co 50,111 $ 0.032898 869,462 $ 0.030307 Service Drilling Co Skelly Oil Co 14,616 .032521 35,095 .030936 The Texas Co 4,653 .051298 39,410 .038401 Stewart, Smith & Phillips 18,898 .031375 Nabob Production Co Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954 in Terms of MCF and Price per MCF 1950 1951 Purchased from -- Volume Price Volume Price Service Drilling Co 712,576 $ 0.032479 44,382 $ 0.046038 Service Drilling Co 6,575 .055265 20,727 .052795 Skelly Oil Co 28,813 .030638 28,950 .034252 The Texas Co 65,203 .034599 61,208 .046088 Stewart, Smith & Phillips Nabob Production Co 234,901 .032189 274,610 .036969
*237Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954 in Terms of MCF and Price per MCF 1951 1952 Purchased from -- Volume Price Volume Price Phillips Petroleum Co 146,247 $ 0.039026 172,091 $ 0.040749 Phillips Petroleum Co 203,706 .031368 215,572 .033172 Dave Rubin-Kerr-McGee 1,524,727 .038182 4,408,620 .051181 Gayden & Cree 51,900 .047145 55,920 .057341 Champlin Refining Co 45,666 .030618 42,377 .031353 Magnolia Petroleum Co 96,138 .031983 91,780 .035269 American Liberty Oil Co 130,500 .033711 241,633 .056698 Holt Brothers 21,052 .043419 9,795 .041454 Kerr-McGee-Dave Rubin 300,261 .036988 Power Petroleum Co 179,914 .041514 84,923 .043463 Riedell, Bollig & Skelly Oil Co Gold-Rubin 1,600,214 .035929 227,074 .05000 Continental Oil Co 844,005 .054052 1,353,219 .061350 E. M. Solow 370,330 .031556 860,575 .045432 Herman Brothers -- Dollie Adams 112,899 .056081 78,859 .064239 Holt, Sparks & Plummer 34,212 .03000 32,962 .030036 Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954 in Terms of MCF and Price per MCF 1953 1954 Purchased from -- Volume Price Volume Price Phillips Petroleum Co 107,221 $ 0.049197 115,698 $ 0.05000 Phillips Petroleum Co 143,253 .035214 114,221 .035776 Dave Rubin-Kerr-McGee 2,660,251 .051890 Gayden & Cree 37,902 .061379 46,297 .050348 Champlin Refining Co Magnolia Petroleum Co 83,286 .045140 228,615 .049309 American Liberty Oil Co 141,912 .058326 62,953 .052342 Holt Brothers 72,068 .03353 421,406 .042175 Kerr-McGee-Dave Rubin Power Petroleum Co Riedell, Bollig & Skelly Oil Co 14,310 .049096 93,513 .037374 Gold-Rubin Continental Oil Co 1,006,652 .064660 808,635 .056062 E. M. Solow 1,444,995 .050227 956,114 .05000 Herman Brothers -- Dollie Adams 45,654 .065367 19,414 .080931 Holt, Sparks & Plummer 30,073 .030844 22,322 .040978
*238Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954 in Terms of MCF and Price per MCF 1952 1953 Purchased from -- Volume Price Volume Price Service Drilling Co 425,627 $ 0.053877 284,418 $ 0.056100 Service Drilling Co 12,572 .048878 20,180 .051304 Skelly Oil Company 8,732 .046844 5,821 .059189 The Texas Company 29,549 .057479 13,335 .076725 Nabob Production Co 249,731 .042088 223,132 .050839 Mayfield, Sigfried, Rooney, et al 78,773 .05000 Casey, Liversay & Phillips Petroleum Co 291,281 .03900 General American Oil Co 212,385 .05000 Casey, Liversay & Phillips Petroleum Co 299,792 .039145 Skelly Oil Co 31,907 .05000 Major & Beach J. M. Huber Corp 712 .05000 Riedell & Skelly Oil Co Holifield, Major & Beach McDaniel & McDaniel Power Petroleum Co Van Norman Oil Co M & D Oil Company A. C. Sorelle & A. C. Sorelle, Jr Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954 in Terms of MCF and Price per MCF 1954 Purchased from -- Volume Price Service Drilling Co 237,749 $ 0.050736 Service Drilling Co 38,670 .05000 Skelly Oil Company 5,417 .063306 The Texas Company 6,973 .069762 Nabob Production Co 54,181 .056437 Mayfield, Sigfried, Rooney, et al 86,589 .05000 Casey, Liversay & Phillips Petroleum Co General American Oil Co 334,853 .05000 Casey, Liversay & Phillips Petroleum Co 1,406,498 .049287 Skelly Oil Co Major & Beach 11,000 .05000 J. M. Huber Corp 782,278 .05000 Riedell & Skelly Oil Co 70,386 .05000 Holifield, Major & Beach 38,614 .049984 McDaniel & McDaniel 2,698 .05000 Power Petroleum Co 76,527 .05000 Van Norman Oil Co 3,046 .05000 M & D Oil Company 4,803 .047847 A. C. Sorelle & A. C. Sorelle, Jr 373 .05000 *1002 Following is a schedule of the weighted average price paid for casinghead gas purchased by Shamrock in terms of MCF:
Weighted average Year price per MCF 1947 $ 0.03000 1948 .039597 1949 .031835 1950 .031212 1951 .039883 1952 .051277 1953 .051997 1954 .049868 A final source of supply of natural gas for Shamrock was purchases of gas under miscellaneous contracts. A summary of the total quantity of gas obtained in each of the years in issue, *239 first under miscellaneous contracts excepting the Continental Oil contract, and second under the Continental Oil contract, follows:
Shamrock Schedule of Gas Purchases Under Miscellaneous Contracts for Years Ended Nov. 30, 1943 Through 1954 Number of Volume-MCF suppliers 14.65 PSIA 1943 4 1,421,177 1944 4 1,425,705 1945 4 1,554,827 1946 4 1,001,454 1947 6 2,647,204 1948 5 6,347,943 1949 11 8,351,981 1950 10 8,662,025 1951 12 11,741,400 1952 11 15,808,642 1953 14 8,120,022 1954 14 6,782,300 Shamrock's sour gas purchases from the Continental Oil Company for the years ended November 30, 1943 through 1954 were as follows:
Volume-MCF Year 14.65 PSIA 1943 9,768,880 1944 10,631,082 1945 10,634,027 1946 9,475,581 1947 9,263,163 1948 9,965,399 1949 11,258,727 1950 9,672,189 1951 9,790,795 1952 8,962,657 1953 8,340,980 1954 7,132,210 Following is a schedule of sour gas and sweet gas purchased under miscellaneous contracts by Shamrockfor the years 1943 through 1954 in terms of MCF and price per MCF:
Schedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock 1943-1954 in Terms of MCF and Price per MCF 1943 1944 Purchased from -- Volume Price Volume Price Cities Service Oil Co 241,652 $ 0.010883 248,657 $ 0.0113996 Phillips Petroleum Co 375,007 .010660 378,653 .011097 Magnolia Petroleum Co 282,228 .011338 248,980 .011943 Sunset Oil Co 522,290 .010957 549,415 .011618 Continental Oil Co 9,768,880 .011771 10,631,082 .015081 Liveoak Corporation Joe Worsham Herman Brothers, Inc
*240Schedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock 1943-1954 in Terms of MCF and Price per MCF 1945 1946 Purchased from -- Volume Price Volume Price Cities Service Oil Co 255,834 $ 0.012223 195,597 $ 0.014990 Phillips Petroleum Co 476,031 .011881 318,083 .014564 Magnolia Petroleum Co 268,983 .013443 173,501 .015763 Sunset Oil Co 553,979 .012437 314,273 .015261 Continental Oil Co 10,634,027 .0123095 9,475,581 .020512 Liveoak Corporation Joe Worsham Herman Brothers, Inc Schedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock 1943-1954 in Terms of MCF and Price per MCF 1947 1948 Purchased from -- Volume Price Volume Price Cities Service Oil Co 170,166 $ 0.023484 171,425 $ 0.036395 Phillips Petroleum Co 182,468 .021686 Magnolia Petroleum Co 89,789 .022729 Sunset Oil Co 321,261 .023542 Continental Oil Co 9,263,163 .030796 9,965,399 .044438 Liveoak Corporation 684,688 .035349 829,691 .04624 Joe Worsham 173,960 .031265 398,250 .043841 Herman Brothers, Inc 46,753 .030000 Schedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock 1943-1954 in Terms of MCF and Price per MCF 1949 1950 Purchased from -- Volume Price Volume Price Cities Service Oil Co 175,448 $ 0.033856 126,409 $ 0.040198 Phillips Petroleum Co 1,023,510 .066996 Continental Oil Co 11,258,727 .042494 9,672,189 .040832 Liveoak Corporation 741,160 .048451 746,375 .047621 Joe Worsham 328,128 .048805 301,529 .047653 Herman Brothers, Inc 90,562 .030420 60,674 .030000 Fowlston & Schroeter 164,193 .035732 315,718 .035732 Stewart & Smith & Phillips Phillips Petroleum Co Dave Rubin Dollie Adams Oil Co Texas Co Walter Caldwell Witco Chemical Corp Stanolind Oil & Gas and J. J. Zofness J. M. Huber Schedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock 1943-1954 in Terms of MCF and Price per MCF 1951 1952 Purchased from -- Volume Price Volume Price Cities Service Oil Co 139,834 $ 0.040198 139,561 $ 0.042355 Phillips Petroleum Co Continental Oil Co 9,790,795 .044057 8,962,657 .046095 Liveoak Corporation 707,559 .049894 619,488 .052083 Joe Worsham 341,328 .050018 317,118 .052026 Herman Brothers, Inc Fowlston & Schroeter 285,200 .040000 262,719 .035732 Stewart & Smith & Phillips 244,070 .050000 180,902 .054577 Phillips Petroleum Co 3,826,062 .070000 8,708,136 .070000 Dave Rubin 562,037 .065000 1,288,534 .065000 Dollie Adams Oil Co 43,683 .030149 16,805 .030029 Texas Co Walter Caldwell Witco Chemical Corp Stanolind Oil & Gas and J. J. Zofness J. M. Huber
*241 *1004Schedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock 1943-1954 in Terms of MCF and Price per MCF 1953 1954 Purchased from -- Volume Price Volume Price Cities Service Oil Co 121,228 $ 0.057242 99,765 $ 0.069254 Phillips Petroleum Co Continental Oil Co 8,340,980 .050347 7,132,210 .056631 Liveoak Corporation 557,994 .057129 487,191 .069323 Joe Worsham 292,774 .057234 270,238 .069586 Herman Brothers, Inc Fowlston & Schroeter 280,343 .035732 267,592 .057907 Stewart & Smith & Phillips 163,453 .060000 114,300 .065000 Phillips Petroleum Co 490,367 .070000 520,999 .10 Dave Rubin 539,059 .065000 Dollie Adams Oil Co 29,010 .031934 15,554 .037869 Texas Co 86,696 .060000 102,291 .059752 Walter Caldwell 89,789 .060000 Witco Chemical Corp 1,439,783 .060000 723,893 .060000 Stanolind Oil & Gas and J. J. Zofness 67,053 .065000 J. M. Huber 230,238 .065000 Schedule of Sweet Gas Purchased Under Miscellaneous Contracts by Shamrock 1947-1954 in Terms of MCF and Price per MCF 1947 1948 Purchased from -- Volume Price Volume Price Liveoak Corporation 879,760 $ 0.035732 2,409,493 $ 0.049448 Texas Co 145,112 .039918 2,492,331 .040081 Shell Oil Co Magnolia Oil Co United Producing Co., Inc Stanolind Oil & Gas Schedule of Sweet Gas Purchased Under Miscellaneous Contracts by Shamrock 1947-1954 in Terms of MCF and Price per MCF 1949 1950 Purchased from -- Volume Price Volume Price Liveoak Corporation 2,580,431 $ 0.052820 2,418,099 $ 0.051995 Texas Co 2,034,686 .040005 2,110,323 .039975 Shell Oil Co 50,144 .039879 121,291 .039760 Magnolia Oil Co 11,610 .039712 141,768 .039669 United Producing Co., Inc 87,601 .050655 413,834 .052084 Stanolind Oil & Gas 1,064,508 .040140 1,906,005 .040181 Schedule of Sweet Gas Purchased Under Miscellaneous Contracts by Shamrock 1947-1954 in Terms of MCF and Price per MCF 1951 1952 Purchased from -- Volume Price Volume Price Liveoak Corporation 2,476,052 $ 0.054409 2,173,583 $ 0.056518 Texas Co 2,050,672 .039894 1,703,478 .043252 Shell Oil Co 109,918 .039744 93,941 .039874 Magnolia Oil Co United Producing Co., Inc 446,209 .054239 304,377 .056358 Stanolind Oil & Gas 508,776 .040198 Schedule of Sweet Gas Purchased Under Miscellaneous Contracts by Shamrock 1947-1954 in Terms of MCF and Price per MCF 1953 1954 Purchased from -- Volume Price Volume Price Liveoak Corporation 1,984,309 $ 0.061655 1,715,524 $ 0.073914 Texas Co 1,626,978 .061689 1,711,098 .073418 Shell Oil Co 80,611 .049108 90,644 .073254 Magnolia Oil Co United Producing Co., Inc 337,628 .062116 365,920 .073748 Stanolind Oil & Gas The *242 schedule of weighted average price paid for gas purchased under miscellaneous contracts and price paid for gas purchased from Continental Oil Company (in terms of MCF) is as follows:
Schedule of Weighted Average Price Paid for Gas Purchased Under Miscellaneous Contracts and Price Paid for Gas Purchased from Continental Oil Company (in Term of MCF) Weighted average Price per price per MCF paid for MCF paid for gas purchased gas purchased from Continental under miscellaneous Oil Co. contracts 1943 $ 0.010942 $ 0.011771 1944 .011498 .015081 1945 .012406 .012310 1946 .015074 .020512 1947 .031893 .030796 1948 .044504 .044438 1949 .048178 .042494 1950 .044715 .040832 1951 .055497 .044057 1952 .062320 .046095 1953 .060382 .050347 1954 .072249 .056631 The gas produced together with the gas purchased or otherwise acquired constituted the total amount of Shamrock owned gas available for processing in Shamrock's extraction plants.
Disposition of Gas .Prior to 1933, the owner of a sour gas well had no outlet for his gas because dry gas was not permitted to be used for any purpose other than light and fuel purposes and sourgas was not suitable for pipeline purposes. At that time, sour gas wells were shut in as a general *1005 rule. Casinghead gas, however, *243 could be burned to make carbon black.
Prior to 1941, interstate pipeline operators did not consider sour gas as a source of supply to them. They objected to sour gas because the hydrogen sulphide in the gas had a corrosive effect on the steel pipelines and on burners and its burning produced dangerous, incomplete combustion with an objectionable rotten-egg odor.
The act of the Texas legislature commonly called "the stripping law" was passed in 1933 and under this legislation it became legal to process gas to extract the liquefiable hydrocarbons and to waste the residue gas by simply venting it into the air. The volume of vented gas reached the point where it exceeded a billion cubic feet of gas per day in the Panhandle of Texas.
The conservation statutes of Texas were revised in 1935 and, in addition to other modifications, the stripping law was repealed and the "popping" of gas into the air was prohibited.
In May 1935 a new law known as House Bill No. 266 was adopted. Under this law, sour residue gas could be burned in the manufacture ofcarbon black, provided the liquefiable hydrocarbons were first extracted, and provided that the carbon black plant averaged a production yield of at *244 least one pound of carbon black per thousand cubic feet of gas consumed. The statute also limited the amount that could be burned for this purpose to a total of 750 million feet of gas per day and limited the privilege of burning it to gas from common reservoirs in the State of Texas, containing both sweet and sour gas, and 200,000 acres or more in extent. The effect of these limitations was to make the law applicable only to the Panhandle field. Sweet gas could only be burned, under the statute, for carbon black manufacture if the sweet gas was casinghead gas that was produced with oil. It was not permissible to use sweet gas for any purpose other than light and fuel under House Bill No. 266 unless the sweet gas might be produced in the form of casinghead gas with oil.
In approximately 1947, an amendment was adopted which permitted the burning of sweet gas in furnace-type carbon plants, as differentiated from channel-type plants, provided the purchaser of the gas paid a price equal to the average price, which was to be determinedby the Railroad Commission of Texas, being paid for sweet gas in the field during the month in which the gas was taken.
From 1943 through 1954, approximately *245 75 or 80 percent of the raw natural gas in the West Panhandle and Texas-Hugoton gasfields was owned by producers who processed their own gas. This left only 20 or 25 percent of the gross production of raw natural gas in the West Panhandle and Texas-Hugoton gasfields available for sale.
During the years 1943 through 1954, most of the gas was owned by the producer and was processed by the producer so that he either sold *1006 or used residue gas and liquefied hydrocarbons. The interstate pipelines in most instances processed gas produced by them.
In making contracts for the sale of raw gas or residue gas the length of the contract is a factor bearing on the contract and the price to be paid for the gas. As a general rule, purchasers are desirous of obtaining a long-term supply.
It is customary to negotiate sales of gas on relatively long-term bases. Where raw gas is sold, the investment involved in connecting the gas is great. Purchasers of raw gas must build expensive facilities to collect and process the raw gas and, therefore, such purchasers require long-term contracts. Where residue gas is sold to an interstate pipeline, a long-term contract is required for regulatory purposes. An *246 interstate pipeline is often in the market for residue gas so that it can increase its market outlet. To do so it has to file application for such expansion program with the Federal Power Commission and adequate reserves is one of the factors considered by that Commission in passing on the application.
Interstate pipelines cannot get permission under the interstate pipeline regulations to construct pipelines and other facilities unless they can show a sufficient supply of gas to justify the investment. Shamrock entered into long-term contracts for the sale of residue gas because that was the only way it could sell gas to the purchaser who, in turn, had to build his facility and pipelines. Thus, Shamrock sold gas on long-term bases because that was the only way that it could sell it.
In the West Panhandle and Texas-Hugoton gasfields from 1943 through 1954, all sales of raw gas were under long-term contracts. Most of these long-term contracts had escalator clauses increasing the price on gas periodically accordingto the terms of the contract.
At all times here material and during the period from December 1, 1942, through November 30, 1954, Shamrock owned and operated a gasoline extraction *247 plant known as its McKee Gasoline Plant located on Section 399, Block 44 H&TC Ry. Co. Survey, Moore County, Texas, and from July 15, 1947, through November 30, 1954, Shamrock owned and operated a gasoline extraction plant, known as its Sunray Gasoline Plant, located on Section 170, Block 3-T, T&NO Ry. Co. Survey, Moore County, Texas, approximately 3 miles east of the McKee Plant. In each of these gasoline extraction plants, various liquefiable hydrocarbons were extracted (through an absorption process) from gas in which an economic interest was owned by Shamrock and which gas was produced from properties owned in whole or in part by Shamrock. Shamrock additionally processed in such plants during such periods additional volumes of gas in which it did not own an economic interest. The gas with respect to which a controversy *1007 as to depletion exists is only that volume of gas in which Shamrock owned an economic interest and which gas was processed in one of the above-named Shamrock Plants (i.e., McKee or Sunray).
Shamrock constructed its first gasoline extraction plant in 1933. The Sunray plant was originally constructed by the Magnolia Petroleum Company which gathered its own gas, processed *248 it, and sold the residue gas to a carbon black plant in the area of the processing plant. Shamrock purchased the Sunray Plant from the Magnolia Petroleum Company in 1947.
An extraction plant is designed to extract the liquefiable hydrocarbons from natural gas. It is a usual matter that raw gas is brought by a gathering system to a central point in the Panhandle area and in the Texas portion of the Hugoton area for processing. This is true because of the economics of handling and delivering gas. It is not feasible or practical to construct an extraction plant for each well.
Shamrock's gas-gathering system connects the individual wells and leases and brings the gas to a central point where it is processed for the extraction of the natural gas liquids and after the gas has been brought to the extraction plant and the liquids extracted, the residue gas is then delivered into the lines of the purchaser of that residue gas.
The terrain in Moore and Sherman Counties where Shamrock gas productionis carried on is generally level, smooth terrain, with practically no trees. There is no subsoil rock that would interfere with the laying of gathering lines for the production of gas. It is an ideal *249 country for laying pipelines.
In Shamrock's collection lines or gathering lines sweet gas and sour gas are mixed. It is more economical to put the entire stream through the Girbitol plant than it would be to gather and process the gas separately.
After the gas is brought to the McKee and Sunray Plants, the liquefiable hydrocarbons are extracted from the gas. The residue gas remaining is sold to the pipeline companies or to other customers or utilized by Shamrock as plant fuel, etc. The liquefiable hydrocarbons, now in a liquid form, are either sold to customers or utilized by Shamrock in its refinery.
Shamrock has not made sizable sales of raw gas. Since it has had its processing plants and gathering system, it has sold only residue gas with slight exception. With respect to sales of raw gas, Shamrock made no sales during the period 1943 through 1954 at the wellhead as such as distinguished from out of its gathering system. If there were any wellhead sales they were of no consequence.
In the beginning of the taxable years in question, Shamrock sold most of its sweet gas as raw gas but processed its sour gas. However, *1008 in 1944 Shamrock sold most of its sweet gas producing wells *250 and leases to Phillips Petroleum Company. After 1944 Shamrock made no similar sales of raw sweet gas. When Shamrock sold sour gas residue under its first residue gas pipeline contract to Panhandle Eastern Pipeline Company in 1945, it included the sale of residue gas from the sweet gas leases that were dedicated under that contract.
When the gas enters the gasoline extraction plant for processing, it goes first to the absorber which is a vessel in which the gas flows against the absorption oil. This absorber or tower at the McKee Plant is about 20 to 30 feet tall and from 5 to 7 feet in diameter. The gas goes in at the bottom of the tower and out at the top. Only line pressure is used for running the gas through the tower either without compression or after compression, as the case may be. No heat is applied at this stage. As the gas moves up the tower oil is pumped against the flow of the stream of gas, and the oil absorbs liquefiable hydrocarbons out of the raw gas stream. The natural gas not absorbed in the oil is called residue gas.
All of the liquefiable hydrocarbons are extracted at one time in the absorber, and they are then contained in the absorption oil. From the absorber, *251 the oil goes to the still where heat coming from steam is applied and the temperature of the liquid is raised and the pressure controlled so that the hydrocarbons will take the form of a liquid, be boiled off, and leave the oil for recirculation. The still or heat exchangers that raise the temperature are a series of horizontal tubes where steam is used to heat the outside surface.
The boiling-off of liquids by heat and pressure is called fractionation. A further fractionation process also separates the propane, butane, isobutane, pentane, isopentane, and the hexanes-plus.
After the liquid extracted by absorption in the first tower has gone through the still, the first product that is separated or taken out of the liquid is propane. This separation is accomplished in what is called a depropanizer where the temperature is regulated so that the propane comes off the top as a gas and the remaining portion of the liquid remains in the liquid state. The propane is then cooledand becomes a liquid again. Pressure and temperature is maintained to keep it in the liquid state as it goes to the storage facility.
Each liquid extracted has its own characteristics with respect to vapor pressure. *252 Propane has the highest vapor pressure. In order to retain it as a liquid, it has to be kept under a certain pressure, and that is true of the other liquids. It is easier to keep the heavier blending stock that is usually used in motor fuel in a liquid form than any of the other liquids in the higher ranks of vapor pressure.
After the propane has been taken out of the liquid, the remainder of the liquids are taken to another tower and then the butanes are taken off. There again the separation is made by boiling off the *1009 lighter fractions that come off the towers as a gas and leaving the balance as liquid at the bottom and the efficiency of the operation is dependent upon temperature levels, top and bottom, on the tower. These temperatures are done by steam and they are all below 200 o F.
After the butanes are taken out, the remainder is commonly referred to as butane-free material. One further step in Shamrock's operations is to take out the isopentane. Isopentane is a blending stock used principally in the industry as the material to give the volatility to aviation gasoline.
Pentanes and isopentanes are both pentanes. Pentanes and isopentanes are separated in the same manner as *253 the other separations, that is, in towers with controlled heat and pressure. Butane consists of butane and isobutane. The normal butane and isobutane are separated by the same method of control of the temperature and pressure.
After the butanes have been taken out, the remainder is called pentanes-plus from which Shamrock removes the pentanes and then separates the isopentanes from the pentanes. After the pentanes have been removed from the liquid, the liquid that is left is called hexanes-plus.
Hexanes-plus and the normal pentanes are used as direct blending material in the refinery. These products are transferred to the refinery for blending into motor fuel or motor gasoline. All of these liquids are frequently called natural gasoline. Isopentane, normal pentane, and hexane are the same as natural gasoline. Natural gasoline, as ordinarily referred to in the industry, is thought of as 26-pound natural gasoline, although lower vapor pressures maybe utilized. The vapor pressure of the remaining liquids after the pentanes have been removed is approximately 10 pounds. A 12-pound natural gasoline is a butane-free material. It is the part of the total natural gasoline with everything, *254 including butane and above, eliminated. The 26-pound product is a product that contains all the heavier materials with some variation, but approximately 35 to 38 percent butane in combination to give a 26-pound material which can be and has been used to a large extent in the blending of motor fuel. The difference is that lesser quantities of 26-pound gasoline can be put into a gallon of motor fuel because of its vapor pressure than the 12-pound butane-free material.
The residue gas comes off the absorber in the initial stage. It is largely methane (approximately 80 percent of the volume of the residue) and it includes some ethane, propane, and occasionally some butane, and certain inert materials such as helium, carbon dioxide, and nitrogen. After the liquefiable hydrocarbons are removed from the raw gas, there remains approximately 95 percent of the volume of the original raw gas.
*1010 Residue gas may be either sweet or sour gas. Whereraw sweet and raw sour gas are mixed in the collection or gathering lines, as is done by Shamrock, the residue gas produced most likely will be sour residue gas.
Prior to 1941, there was considerable research done for the purpose of obtaining a process *255 for removing hydrogen sulphide from sour gas. By 1941, a pilot plant to remove hydrogen sulphide had been constructed and found to be dependable and by it sour gas could be sweetened for use by interstate pipelines. The plant process is known as the Girbitol process. Shamrock owns such a plant. After the residue gas leaves Shamrock's absorber in the initial stage, it immediately goes to the Girbitol plant for the removal of hydrogen sulphide which is still in the residue at that stage.
Generally speaking, the Girbitol plant is simply another absorber or group of absorbers. The inside of an absorber contains trays (or bubble caps) and the absorbent material filters down through these trays which are placed to slow up the movement of the absorbent in order to provide maximum contact with the gas for the absorption process. An amine solution is used as an absorbent to absorb the liquid hydrogen sulphide. The process is very similarto that of the first absorber. The hydrogen sulphide is next removed by fractionation from the liquid that absorbed it as the processes already described separate the liquefiable hydrocarbons from the absorbent.
Shamrock first started taking hydrogen sulphide *256 out of the residue gas in 1947 with the commencement of the sale of residue gas to Panhandle Eastern Pipeline Company. This contract, Shamrock's first contract for the sale of sweetened gas, was entered into in 1945.
The following tables show the disposition by years by Shamrock of available raw gas in terms of MCF:
Disposition by Years of Total Available Raw Gas -- in Terms of MCF Total Gathering available Raw gas and raw gas sales extraction losses 1943 69,300,388 148,855 1,883,780 1944 76,888,480 377,391 1,476,699 1945 91,096,177 369,559 1,859,025 1946 96,994,242 149,541 1,024,375 1947 109,374,858 2,757,918 2,205,527 1948 130,836,192 1,818,291 2,378,961 1949 160,244,539 336,540 2,896,818 1950 159,770,389 994,328 3,251,493 1951 150,687,588 1,080,574 1,748,727 1952 144,770,286 1,384,558 3,043,031 1953 137,836,683 1,145,306 3,840,911 1954 133,690,073 1,159,771 4,333,917 Disposition by Years of Total Available Raw Gas -- in Terms of MCF Residue gas Residue gas Total residue consumed returned under gas available as plant processing for sale by fuel, etc. contracts Shamrock 1943 4,088,877 9,230,221 53,948,655 1944 4,228,760 11,537,070 59,268,560 1945 3,565,898 14,213,667 71,088,028 1946 3,620,990 13,912,993 78,286,343 1947 4,123,985 20,733,369 79,554,059 1948 5,094,452 22,457,301 99,087,187 1949 5,798,655 25,535,698 125,676,828 1950 5,389,448 25,251,366 124,883,754 1951 7,699,430 22,558,881 117,599,976 1952 8,124,656 19,943,432 112,274,609 1953 9,276,824 18,764,486 104,809,156 1954 9,534,629 16,309,574 102,352,182 The *257 following table shows a percentage analysis of the disposition by years by Shamrock of total available raw gas: *1011
Percentage Analysis of Disposition by Years of Total Available Raw Gas Total Raw gas Gathering available sales and extraction raw gas losses Percent 1943 100 0.21 2.72 1944 100 0.49 1.92 1945 100 0.41 2.04 1946 100 0.15 1.06 1947 100 2.52 2.02 1948 100 1.39 1.82 1949 100 0.21 1.81 1950 100 0.62 2.04 1951 100 0.72 1.16 1952 100 0.96 2.10 1953 100 0.83 2.79 1954 100 0.87 3.24 Percentage Analysis of Disposition by Years of Total Available Raw Gas Residue gas Residue gas Total residue consumed as returned gas available plant fuel, under processing for sale by etc. contracts Shamrock Percent 1943 5.90 13.32 77.85 1944 5.50 15.01 77.08 1945 3.91 15.61 78.03 1946 3.73 14.35 80.71 1947 3.77 18.95 72.74 1948 3.89 17.16 75.73 1949 3.62 15.93 78.43 1950 3.37 15.80 78.17 1951 5.11 14.97 78.04 1952 5.61 13.78 77.55 1953 6.73 13.61 76.04 1954 7.13 12.20 76.56 From 1943 to 1954, inclusive, Shamrock either sold the liquefied hydrocarbons which were extracted from the raw gas to others or transferred them to Shamrock's refinery. These transfers to the refinery were treated as intercompany sales and a price was set by Shamrock for these sales.
A major portion of the natural gasoline extracted by Shamrock from*258 raw gas was used in Shamrock's refinery for blending gasoline and a substantial part of the gross receipts listed for such natural gasoline represents intercompany sales from Shamrock's gasoline extraction plants to Shamrock's oil refinery.
Normally Shamrock's outside sales of products consistof the higher vapor pressure materials. Shamrock sells butane, propane, and a combination of butane and propane, known in the industry as LPG, which is liquefied petroleum gas. Shamrock has at times additionally sold isobutane and isopentane.
Shamrock disposed of the total volume of residue gas it had available for sale to the various classes of purchasers and in the amounts shown on the following schedule:
Disposition by Years of Total Residue Gas Available for Sale by Shamrock Residue Percentage Total residue gas sold to of residue gas available carbon gas sold to for sale black manufacturers carbon black manufacturers Percent 1943 53,948,655 50,480,415 93.5 1944 59,268,560 56,266,369 94.93 1945 71,088,028 68,894,814 96.91 1946 78,286,343 75,283,206 96.16 1947 79,554,059 65,012,653 81.72 1948 99,087,187 67,754,536 68.38 1949 125,676,828 57,664,656 45.88 1950 124,883,754 54,376,858 43.54 1951 117,599,976 43,590,413 37.07 1952 112,274,609 35,031,649 31.20 1953 104,809,156 13,181,028 12.58 1954 102,352,182 2,827,917 2.76 Disposition by Years of Total Residue Gas Available for Sale by Shamrock Residue Percentage Residue Percentage gas sold to of residue gas sold to of residue interstate gas sold to other gas sold to pipelines interstate industrial other pipelines users industrial users Percent Percent 1943 3,468,240 6.43 1944 3,002,191 5.07 1945 2,193,214 3.09 1946 3,003,137 3.84 1947 10,803,728 13.58 3,737,678 4.70 1948 27,062,848 27.31 4,269,803 4.31 1949 63,110,874 50.22 4,901,298 3.90 1950 65,251,426 52.25 5,255,470 4.21 1951 68,021,715 57.84 5,987,848 5.09 1952 70,024,618 62.37 7,218,342 6.43 1953 84,174,597 80.31 7,453,531 7.11 1954 91,874,684 89.76 7,649,581 7.48 *259 *1012 The following table shows a summary of amounts received from the sale by Shamrock of residue gas and percentages of the amounts received from the respective sales to the total amount received therefor:
Summary of Amounts Received From Sale of Residue Gas and Percentages of the Amounts Received From the Respective Sales to the Total Amount Received Therefor
Carbon black manufacturers Interstate pipelines Percent Percent of total of total Amount amount Amount amount of residue of residue sales sales 1943 $ 437,513.44 79.93 1944 481,606.34 83.31 1945 902,290.52 92.69 1946 1,768,634.12 93.34 1947 2,225,207.40 76.40 $ 521,266.59 17.90 1948 3,269,308.63 66.60 1,420,918.59 28.94 1949 2,648,533.17 39.26 3,845,576.87 57.00 1950 2,512,008.07 37.97 3,815,239.25 57.67 1951 2,097,711.67 31.50 4,154,679.87 62.39 1952 1,684,288.58 25.25 4,518,819.66 67.74 1953 623,752.09 9.23 5,733,715.92 84.85 1954 153,263.00 1.85 7,598,590.66 91.43 Other industrial users Total amount received Percent from of total sale of Amount amount residue gas of residue sales 1943 $ 109,880.26 20.07 $ 547,393.70 1944 96,515.61 16.69 578,121.95 1945 71,139.02 7.31 973,429.54 1946 126,208.18 6.66 1,894,842.30 1947 166,075.72 5.70 2,912,549.71 1948 219,009.09 4.46 4,909,236.31 1949 252,435.74 3.74 6,746,545.78 1950 288,016.92 4.36 6,615,264.24 1951 407,082.61 6.11 6,659,474.15 1952 468,101.09 7.01 6,671,209.33 1953 400,328.53 5.92 6,757,796.54 1954 558,673.08 6.72 8,310,526.74 *260 From 1943 to 1954, inclusive, Shamrock made sales of residue gas to carbon black companies. From 1933 to 1943, most of the sour gas residue was sold to carbon black companies.
A channel-type carbon black plant operates on the basis of insufficient combustion of gas with the flame impinging upon a metal surface or channels to cause the accumulation of soot or carbon which is removed by periodically scraping that carbon black off the metal surface and collecting it. The carbon produced by the channel-type plant is in the form of fine carbon particles and is suitable for combination with natural rubber to make commercial rubber products. The carbon produced by the furnace-type method produced larger particles and this gray-type black is more effective for combination with synthetic rubber to make rubber products.
Under the sour gas law passed in 1935, the extraction of gasoline was required before the sour gas residue could be used for the manufacture of carbon black. With the passage of this sour gas law in 1935, it was necessary that Shamrock find an outlet for its residue gas. It found an outlet through the carbon black industry by inducing carbon black companies either to constructor *261 move plants to an area adjacent to Shamrock's natural gasoline extraction plant.
Shamrock joined with Continental Oil Company in forming Continental Carbon Company in which Shamrock owned a 30 percent interest. Continental Oil Company likewise furnished a part of the capital for Continental Carbon Company.
*1013 Shamrock on October 15, 1936, agreed to purchase all of the raw gas from approximately 10,000 to 12,000 acres of leases from Continental Oil Company. The purchase of the Continental Oil Company gas was a special arrangement in connection with the formation and construction of the Continental Carbon Black Plant in partnership with the Continental Oil Company.
In addition to the Continental Carbon Company, Shamrock assisted Reliance Carbon Company financially in establishing its plant near Shamrock's McKee Plant. This assistance took the form of permitting a deduction in the price paid to Shamrock for gas sold to the carbon company until the accumulated deductions equaled the cost of moving the plant from Louisiana and reconstructing it in the Panhandle of Texas.
There were five carbon black plants constructed in the vicinity of Shamrock's McKee Plant. Shamrock committedto each of these *262 carbon black companies the furnishing of a definite volume of gas for the life of the field. This was necessary in order for Shamrock to induce these carbon black companies to provide the market for Shamrock's residue gas. The companies that built plants in the area and with whom Shamrock had contracts were Continental Carbon Company, Crown Carbon Company, Reliance Carbon Company, later known as United Carbon Company, and Columbian Carbon Company. To induce these carbon black companies to provide a market for the residue sour gas by locating near the McKee gasoline extraction plant, Shamrock dedicated residue gas from certain acreages for the life of the leases to the carbon black companies. All contracts made with these companies had such long-term dedications.
In September 1937, the Crown Carbon Company built a plant 0.2 of a mile from the McKee Plant and Crown purchased residue gas from Shamrock from 1943 to March 1954.
In June 1936, the Columbian Carbon Company built a plant 1.28 miles from the McKee Plant and Columbian purchased residue gas from Shamrock from 1943 to August 1953, inclusive.
In January 1937, Continental Carbon Company built a plant 2.46 milesfrom the McKee Plant *263 and Continental Carbon purchased residue gas from Shamrock from 1943 to 1954, inclusive.
In June 1936, Reliance Carbon Company built a plant 0.014 of a mile from the McKee Plant and Reliance purchased residue gas from Shamrock from 1943 to January 1953.
In September 1937, Shell-Columbian Carbon Company built a plant 0.091 of a mile from the McKee Plant and Shell-Columbian purchased residue gas from Shamrock from 1943 to December 1951.
The price basis on which Shamrock sold the residue gas to the carbon black companies for supplying their requirements was 30 *1014 percent of the carbon black yield, less certain deductions such as sales and packaging and warehouse expenses, etc., to give a net price to Shamrock in the neighborhood of 25 percent to 26 percent of the value of the carbon black produced from the gas.
Each of the contracts with these carbon black companies provided that, in the event the purchaser elected to discontinue the manufacture of carbon black, then it had the right of resale and the contract set forth the percentage basis upon which the revenue from such resale would be divided between the carbon company and Shamrock even though the carboncompany should elect to move its *264 plant from the area.
The economics of the gas industry early in the taxable period changed to where all of the gas that had been sold to the carbon black companies was resold to pipeline companies. Shamrock participated in the resale of that gas and in the revenue received. Additionally, Shamrock handled, with the consent or permission of the carbon black companies, the negotiations of the contracts which were made disposing of the gas to the various pipeline companies. The first contract for the resale of this gas was made in 1947. Shamrock continued to make these contracts of resale of gas until all of the gas was sold.
At the time of the resale of this gas the value of the gas for light and fuel purposes exceeded the value of the gas for carbon black manufacture.
The delivery of gas to Continental Carbon Company started with the completion of the Continental Carbon Company's channel-type carbon black plant in 1937 and continued until the residue gas was sold to pipeline companies in increments beginning with the sale to Texoma Natural Gas Company. The date of the first sale to Texoma Natural Gas Company was July 1, 1947.
Shamrock continued to produce gas, extract gasoline, and *265 sell the majority of residue gas for carbon black manufacture up to the beginning of the period here involved in 1943.
Shamrock negotiated new contracts with the carbon black companies prior to a resale of the gas to pipeline companies. In the renegotiations the prices for the gas were put on a flat basis of a certain sum per MCF and the amount that was being paid for carbon black was substantially increased. In these contract negotiations, the minimum price to be paid to Shamrock in the event of a resale was likewise increased. In the original contracts, it was provided that in the event a carbon black company ceased using gas and made a resale of the gas Shamrock would receive the first 2 cents per thousand cubic feet and the balance would be divided on a 50-50 basis between the two companies. In these renegotiated contracts *1015 for sale of gas to carbon black companies, it was provided that the first 3 cents would be received by Shamrock and the balance would be divided 50-50.
At the time of making these renegotiated contracts for the sale of gas to the carbon black companies, the price of residue gas in substantial quantities hadincreased from what it was in 1936.
During the period *266 prior to 1943, Shamrock made two industrial sales to other users. These sales were a fuel sale to the plant of the American Zinc Company of Illinois and a fuel sale to what was then a small generating plant of the Southwestern Public Service Company, originally Panhandle Power & Light Company. Both of these plants are in the proximity of Shamrock's extraction plants.
In September 1936, the American Zinc Company built a plant 2.8 miles from the McKee Plant and American Zinc purchased residue gas from Shamrock from 1943 to 1954, inclusive.
In January 1938, Southwestern Public Service Company built a plant 0.774 of a mile from the McKee plant and Southwestern purchased residue gas from Shamrock from 1943 to 1954, inclusive.
The first pipeline from the Panhandle field was constructed in 1926. Thereafter, the major long distance pipelines in the order of their construction were:
(1) Cities Service Pipe Line which was constructed into the Kansas City, Missouri, area in 1928;
(2) CanadianRiver Pipe Line (now known as Colorado Interstate Pipeline) which began transporting gas to Denver, Colorado, and intermediate points in 1928;
(3) Panhandle Eastern Pipeline Company, which began making deliveries *267 out of its initial pipeline to Indiana in June 1931;
(4) Texoma Natural Gas (now Natural Gas Pipeline of America) which began taking gas out of the West Panhandle field to the vicinity of Chicago in October 1931; and
(5) Northern Natural Pipe Line Company, which began taking gas through its pipeline into the Omaha, Nebraska, area in 1932; later to the Minneapolis, St. Paul, Iowa, and Nebraska area.
The principal other pipelines built out of the Panhandle field was the Michigan-Wisconsin Pipeline, which originates in the Texas-Hugoton field, and the El PasoNatural Gas Pipeline, which obtains substantially all its supply from the sweetened sour gas in the West Panhandle field. This latter pipeline extends to the California market. Since original construction, the early pipelines have been expanded, paralleled, duplicated, and additional facilities have been built.
All of the pipeline companies had to have long-term supplies of natural gas in order to finance the pipeline projects. In order to obtain *1016 such long-term supplies, the pipeline companies acquired leases on large blocks of acreage in the Panhandlefield and produced gas from their own acreage.
With one exception, that is, the *268 Northern Natural Gas Company, no gas was purchased by any of the pipeline companies until 1936. In 1936, Panhandle Eastern Pipeline Company purchased gas from wells owned by what was then the King Oil Company (later sold to Phillips Petroleum Company). Likewise, in the same year, Panhandle Eastern entered into a contract with Shamrock involving the purchase of gas from two wells, which two wells were located in the sweet portion of the field in Moore County.
In the early 1930's, the majority of the sweet gas producing acreage in the Panhandle field was owned by interstate pipeline companies, but the same percentage did not apply to the total known producing acreage in the Panhandle, whether sweet or sour. The interstate pipeline companies did not own a substantial portion of the sour gas acreage.
The removal of the liquefiable hydrocarbons from natural gas is desirable from the standpoint of the pipeline company and the ordinary processing of natural gas is carried on by all major long-distance pipeline companies.
Until about 1941, sour gas was not considered as a source of supply for pipelines. Thepipeline companies would not purchase sour gas because of the corrosive effects of the *269 hydrogen sulphide on the steel of which the pipelines were constructed, the danger of incomplete combustion because of the corrosion of the burner tip, and the fact that the gas would leave an objectionable odor in the house when the gas was burned.
Considerable research had been undertaken with respect to the removal of hydrogen sulphide from the sour natural gas and in 1941 a pilot plant for this purpose had been constructed and found to be dependable.
With the development of the Girbitol process and the increase in the national population, the sour gas reserve became a highly desirable source of supply for interstate pipeline companies. The pipelines in general extended their facilities greatly to take care of the new increase in population and new communities.
During the period from 1943 to 1954, there was an evolution with respect to the use of sour gas. With the development of the Girbitol process for the removal of hydrogen sulphide from gas and with the increasing market outlet for natural gas, the sour gas reserve became a desirable source of supply because in the West Panhandle Fieldit was located close to existing pipeline facilities. Panhandle Eastern Pipeline *1017 Company *270 was the first company to make a contract and become competitive for the purchase of sour gas residue.
Negotiations were started in 1943 between Panhandle Eastern Pipeline Company and Shamrock for the purchase of gas. These negotiations started in 1943 when Panhandle Eastern became convinced it was necessary to find additional sources of supply in the Panhandle and Hugoton fields. This contract was later executed on December 28, 1945.
Shamrock had many opportunities to make sales of residue gas to the gas pipelines with deliveries beginning in the year 1947. This residue gas was the residue sour gas from which the hydrogen sulphide had been removed. Shamrock made actual sales of such gas to Texoma Natural Gas Company, Natural Gas Pipeline Company of America, and Northern Natural Gas Company.
There was an increasing demand for residue gas in the Panhandle field and in the Texas portion of the Hugoton field for interstate and intrastate pipelines over the period from 1943 through 1954, and there was a change in the uses to which residue gas has been disposed of in the Panhandle field. The principal change in the use of residue gas was from the carbon black market to the natural gas *271 pipelines for light and fuel.
The change in the use of the residue gas brought about a change in the price for which the gas could be sold in the Panhandle field both at the wellhead and for residue gas. The price for which it could be sold moved upward.
From 1943 to 1954, inclusive, Shamrock used considerable quantities of its residue gas as plant fuel for the gasoline extraction plants and the oil refinery. Transfers of residue gas were treated as intercompany sales and billed at prices set by Shamrock.
The maximum length of all of Shamrock's delivery or residue lines at all times was 7.68 miles. A portion of the delivery lines equaling 1.598 miles was abandoned when the carbon black plants were abandoned. There are no delivery lines from the Sunray Plant because the residue gas is brought to the McKee Plant, a distance of 3 miles, where the hydrogen sulphide is removed.
The following purchases of raw gas in the field were reported by interstate pipeline companies to the Federal Power Commissioner during the years in issue. All of these purchases, where the point of receipt ofthe raw gas was at the well mouth, except two purchase contracts stipulated by the parties as not to be *272 considered by the Court, have been considered by the Court and the basic provisions of the original contracts considered are set out following the schedules of purchases. *1018
*273Raw Gas Purchased by Interstate Pipeline Companies During Calendar Year 1943 Date of Purchaser Seller contract 1943 None None 2/27/37 Northern Natural Independent Natural 2/1/37 Panhandle Eastern Shamrock 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips 9/27/35 do Northern Natural 9/27/35 do do 8/4/30 do Navajo Natural 2/1/29 West Texas Gas Co Red River Gas 1944 2/27/37 Northern Natural Independent Natural 2/1/37 Panhandle Eastern Phillips Petroleum 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips Petroleum 9/27/35 do Northern Natural 9/27/35 do do 8/4/30 do Navajo Natural 2/1/29 West Texas Gas Red River Gas 1945 8/18/45 Panhandle Eastern Shell Oil 2/27/37 Northern Natural Independent Natural 2/1/37 Panhandle Eastern Phillips Petroleum 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips Petroleum 9/27/35 do Northern Natural 9/27/35 do do 8/4/30 do Navajo Natural 2/1/29 West Texas Gas Red River Gas 1946 5/10/46 Panhandle Eastern Burnett-Cornelius 6/16/46 do do 6/16/46 do do 6/16/46 do Navajo Natural 8/18/45 do Shell Oil 2/27/37 Northern Natural Independent Natural 2/1/37 Panhandle Eastern Phillips Petroleum 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips Petroleum 11/27/36 do do 6/27/35 do Northern Natural 9/27/35 do do 8/4/30 do Navajo Natural 2/1/29 West Texas Gas Red River Gas 1947 9/1/47 Northern Natural Hagy-Harrington-Marsh 5/10/46 Panhandle Eastern Burnett-Cornelius 6/16/46 do do 6/16/46 do do 6/16/46 do Navajo Natural 8/18/45 do Shell Oil 12/27/37 Northern Natural J. M. Huber 2/27/37 do Independent Natural 2/1/37 Panhandle Eastern Phillips Petroleum 10/30/36 do do 7/12/36 do do 11/27/36 do do 9/27/35 do Northern Natural 9/27/35 do do 8/4/30 do Navajo Natural 2/1/29 West Texas Gas Red River Gas 1948 8/1/48 Northern Natural Williams-Phillips 1/12/48 Panhandle Eastern Shamrock 9/1/47 Northern Natural Harrington-Marsh 5/10/46 Panhandle Eastern Burnett-Cornelius 6/16/46 do do 6/16/46 do do 6/16/46 do Navajo Natural 8/18/45 do Shell Oil 2/27/37 Northern Natural Independent Natural 2/1/37 Panhandle Eastern Phillips Petroleum 2/1/37 do do 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips Petroleum 7/12/36 do do 11/27/36 do do 9/27/35 do Northern Natural 9/27/35 do do 8/4/30 do Navajo Natural 2/1/29 West Texas Gas Red River Gas 1949 11/26/48 Cities Service Gas Burnett Cornelius 8/1/48 Northern Natural Phillips Petroleum 1/12/48 Panhandle Eastern Shamrock 9/1/47 Northern Natural Panoma 5/10/46 Panhandle Eastern Burnett-Cornelius 6/16/46 do do 6/16/46 do do 6/16/46 do Navajo Natural 6/16/46 do do 8/18/45 do Shell Oil 2/27/37 Northern Natural Independent Natural 2/1/37 Panhandle Eastern Phillips Petroleum 2/1/37 do do 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips Petroleum 7/12/36 do do 11/27/36 do do 9/27/35 do Northern Natural 9/27/35 do do 8/4/30 do Navajo Natural 2/1/29 West Texas Gas Red River Gas 2/1/29 do do 1950 9/25/50 Panhandle Eastern Britain 4/5/50 do Burnett-Cornelius 12/1/49 do Dunn-Kimberlin 10/14/49 do Skelly Oil 11/26/48 Cities Service Gas Burnett-Cornelius 8/1/48 Northern Natural Phillips Texas 1/12/48 Panhandle Eastern Shamrock 9/1/47 Northern Natural Panoma Corp 5/10/46 Panhandle Eastern Burnett-Cornelius 6/16/46 do do 6/16/46 do Navajo Natural 6/16/46 do do 8/18/45 do Shell Oil 2/1/37 do Phillips Petroleum 2/1/37 Panhandle Eastern Phillips Petroleum 4/21/36 Northern Natural J. M. Huber 2/27/36 do Indenpendent Natural 10/30/36 Panhandle Eastern Phillips Petroleum 7/12/36 do do 11/27/36 do do 9/27/35 do Northern Natural 9/27/35 do do 8/4/30 do Navajo Natural 2/1/29 West Texas Gas Red River Gas 1951 9/5/51 Panhandle Eastern Burnett-Cornelius 2/11/50 Natural Gas Pipeline do 6/8/50 do Red River Gas 9/25/50 Panhandle Eastern Britain 4/5/50 do Burnett-Cornelius 1/7/49 Natural Gas Pipeline Cities Service Gas 9/29/49 do Earl Nutter 12/1/49 Panhandle Eastern Dunn-Kimberlin 10/14/49 do Skelly 11/26/48 Cities Service Gas Burnett-Cornelius 8/1/48 Northern Natural Phillips-Texas 1/12/48 Panhandle Eastern Shamrock 9/1/47 Northern Natural Panoma 5/10/46 Panhandle Eastern Burnett-Cornelius 5/10/46 do do 6/16/46 do do 6/16/46 do Navajo Natural 6/16/46 do do 8/18/45 do Shell Oil 2/27/37 Northern Natural Independent Natural 2/1/37 Panhandle Eastern Phillips Petroleum 2/1/37 do do 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips Petroleum 7/12/36 do do 11/27/36 do do 8/4/30 do Navajo Natural 2/1/29 West Texas Gas Red River Gas 1952 2/8/52 Natural Gas Pipeline Panhandle Eastern 7/1/52 Northern Natural Panoma 11/1/52 Northern Natural Northern Natural Gas Co. Gas Producing Co. 4/17/51 Northern Natural Shamrock 4/12/51 do do 8/30/51 Panhandle Eastern Shell-Sinclair 2/11/50 Natural Gas Pipeline Burnett-Cornelius 6/8/50 do Red River Gas 9/25/50 Panhandle Eastern Britain 4/5/50 do Burnett-Cornelius 9/5/50 do do 1/7/49 Natural Gas Pipeline Cities Service Gas 9/29/49 do Earl Nutter 12/1/49 Panhandle Eastern Dunn-Kimberlin 10/31/49 Southwestern Public Shamrock 11/26/48 Cities Service Gas Burnett-Cornelius 8/1/48 Northern Natural Phillips-Texas 6/16/48 Panhandle Eastern Navajo Natural 1/12/48 do Shamrock 5/10/46 do Burnett-Cornelius 5/10/46 do do 6/16/46 do do 6/16/46 do Navajo Natural 8/18/45 do Shell Oil 2/27/37 Northern Natural Independent Natural 2/1/37 Panhandle Eastern Phillips Petroleum 2/1/37 do do 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips Petroleum 7/12/36 do do 11/27/36 do do 9/21/35 do J. M. Huber 6/29/35 Southwestern Public do 6/29/35 do do 8/4/30 Panhandle Eastern Navajo Natural 2/1/29 West Texas Gas Red River Gas 6/16/27 Southwestern Public Phillips Petroleum 7/10/26 do do 1953 4/30/53 Cities Service Gas Cities Service Gas 3/30/53 Natural Gas Pipeline Kimberlin-Howse 8/20/53 do Panhandle Eastern 6/8/53 do Phillips Petroleum 8/28/53 Northern Natural Independent 6/1/53 do Cities Service Oil 6/13/53 do Huval-Dunigan 5/22/53 do Texas Co 12/15/53 do Phillips-Texas 10/1/53 Southwestern Public J. M. Huber 10/1/53 do do 11/2/53 do Phillips Petroleum 11/19/52 Colorado Interstate A. E. Herrmann 12/16/52 do H. F. Sears 7/1/52 Northern Natural Panoma 11/1/52 do Northern Natural 11/9/52 Southwestern Public H. B. Dunn 9/5/51 Panhandle Eastern Burnett-Cornelius 2/11/50 Natural Gas Pipeline do 6/8/50 do Red River Gas 9/25/50 Panhandle Eastern Britain 4/5/50 do Burnett-Cornelius 9/29/49 Natural Gas Pipeline Earl Nutter 1/7/49 do Cities Service Gas 12/1/49 Panhandle Eastern Dunn-Kimberlin 10/14/49 do Skelly Oil 12/31/49 Southwestern Public Shamrock 11/26/48 Cities Service Gas Burnett-Cornelius 1/12/48 Panhandle Eastern Shamrock 3/4/48 do Skelly-Cabot 5/10/46 do do 5/10/46 do do 6/16/46 do do 6/16/46 Panhandle Eastern Navajo Natural 6/16/46 do do 8/18/45 do Shell Oil 2/1/37 do Phillips Petroleum 2/1/37 do do 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips Petroleum 7/12/36 do do 11/27/36 do do 9/21/35 do J. M. Huber 8/4/30 do Navajo Natural 7/10/26 Southwestern Public Phillips Petroleum 1954 5/11/54 Colorado Interstate Witco Chemical 2/2/54 Natural Gas Pipeline Phillips Petroleum 4/30/53 Cities Service Gas Cities Service 4/30/53 do do 3/30/53 Natural Gas Pipeline Kimberlin-Howse 6/1/53 Northern Natural Cities Service Oil 6/13/53 do Huval-Dunigan 8/28/53 do Independent Natural 5/22/53 do Texas Company 12/15/53 do Phillips Petroleum 10/1/53 Southwestern Public J. M. Huber 10/1/53 do do 11/2/53 do Phillips Petroleum 11/2/53 do do 11/19/52 Colorado Interstate A. E. Herrmann 12/16/52 do H. F. Sears 7/1/52 Northern Natural Dorchester 11/1/52 do Northern Natural 11/9/52 Southwestern Public H. B. Dunn 9/5/51 Panhandle Eastern Burnett-Cornelius 2/11/50 Natural Gas Pipeline do 9/25/50 Panhandle Eastern B. M. Britain 4/5/50 do Burnett-Cornelius 1/7/49 Natural Gas Pipeline Cities Service 9/29/49 do Earl Nutter 12/1/49 Panhandle Eastern Dunn-Kimberlin 10/31/49 Southwestern Public Shamrock 11/26/48 Cities Service Gas Burnett-Cornelius 5/10/46 Panhandle Eastern do 5/10/46 do do 6/16/46 do do 6/16/46 do Navajo Natural 6/16/46 do do 8/18/45 do Shell Oil 2/1/37 do Phillips Petroleum 2/1/37 do do 4/21/36 Northern Natural J. M. Huber 10/30/36 Panhandle Eastern Phillips Petroleum 7/12/36 do do 11/27/36 do do 9/21/35 do J. M. Huber 8/4/30 do Navajo Natural
*274 Not available. *1024Raw Gas Purchased by Interstate Pipeline Companies During Calendar Year 1943 Approximate B.t.u. MFC Delivery Cents/ Date of Point of per cu. at MCF at Contract receipt ft. 14.65 PSIA 14.65 PSIA 1943 2/27/37 Skellytown 1,068 12,628,374 $ 0.050970 2/1/37 Moore Co 1,012 14,674,343 .031757 4/21/36 Skellytown (1) 2,149,237 .031265 10/30/36 Moore Co 1,012 652,945 .022332 9/27/35 do 1,012 287,753 .031265 9/27/35 Carson Co 1,012 230,155 .031265 8/4/30 Well mouth 1,012 898,783 .031265 2/1/29 do 1,004 10,480,640 .037110 1944 2/27/37 Skellytown 1,068 12,683,733 .050909 2/1/37 Moore Co 1,010 14,330,621 .031737 4/21/36 Skellytown (1) 2,509,163 .031265 10/30/36 Moore Co 1,010 411,245 .022332 9/27/35 do 1,010 255,236 .031265 9/27/35 Carson Co 1,010 175,030 .031265 8/4/30 Well mouth 1,010 1,764,416 .031265 2/1/29 do 1,040 12,082,846 .036915 1945 8/18/45 Moore Co 1,003 1,076 .035725 2/27/37 Skellytown 1,060 12,674,584 .050838 2/1/37 Moore Co 1,003 13,139,136 .031747 4/21/36 Skellytown (1) 3,375,689 .031326 10/30/36 Moore Co 1,003 484,710 .022332 9/27/35 do 1,003 200,331 .031265 9/27/35 Carson Co 1,003 178,267 .031265 8/4/30 Well mouth 1,003 1,434,683 .031265 2/1/29 do 1,040 12,518,420 .036907 1946 5/10/46 Carson Co 1,016 276,690 .037965 6/16/46 do 1,016 96,583 .037965 6/16/46 Carson & 1,016 161,926 .037965 Hutch. 6/16/46 do 1,016 170,788 .037965 8/18/45 Moore Co 1,016 310,416 .035732 2/27/37 Skellytown 1,047 12,850,449 .050722 2/1/37 Moore Co 1,016 11,470,984 .031824 4/21/36 Skellytown (1) 3,404,250 .035732 10/30/36 Moore Co 1,016 553,972 .022332 11/27/36 do 1,016 1,767,959 .031265 6/27/35 do 1,016 181,269 .031265 9/27/35 Carson Co 1,016 215,696 .031265 8/4/30 Well mouth 1,016 1,551,185 .031265 2/1/29 do 1,040 12,011,675 .036946 1947 9/1/47 Well mouth (1) 8,215,730 .046898 5/10/46 Carson Co 1,015 635,516 .037965 6/16/46 do 1,015 276,764 .037965 6/16/46 Carson & Hutch. 1,015 282,376 .037965 6/16/46 do 1,015 473,972 .037965 8/18/45 Moore Co 1,015 278,665 .035732 12/27/37 Skellytown (1) 3,457,335 .035732 2/27/37 do 1,049 12,598,472 .050918 2/1/37 Moore Co 1,015 9,565,221 .031824 10/30/36 do 1,015 432,643 .022332 7/12/36 do 1,015 460,845 .031265 11/27/36 do 1,015 1,464,171 .031422 9/27/35 do 1,015 158,795 .031265 9/27/35 Carson Co 1,015 152,998 .031265 8/4/30 Well mouth 1,015 2,203,278 .031265 2/1/29 do 1,040 13,845,606 .036787 1948 8/1/48 Well mouth (1) 33,754 .044664 1/12/48 Moore Co 1,015 140,249 .044664 9/1/47 Well mouth (1) 23,324,303 .046898 5/10/46 Carson Co 1,015 734,882 .037965 6/16/46 do 1,015 280,672 .037965 6/16/46 Carson & Hutch. 1,015 270,337 .037965 6/16/46 do 1,015 449,906 .037965 8/18/45 Moore Co 1,015 210,827 .035629 2/27/37 Skellytown 1,056 12,920,229 .051024 2/1/37 Moore Co 1,015 478,329 .032242 2/1/37 do 1,015 9,809,937 .031824 4/21/36 Skellytown (1) 2,191,911 .035732 10/30/36 Moore Co 1,015 484,240 .022332 7/12/36 do 1,015 539,122 .031265 11/27/36 do 1,015 1,076,375 .031342 9/27/35 do 1,015 179,389 .031265 9/27/35 Carson Co 1,015 171,497 .031265 8/4/30 Well mouth 1,015 1,407,669 .045015 2/1/29 do 1,040 14,117,493 .036780 1949 11/26/48 Production line. 1,081 1,916,297 .049131 8/1/48 Well mouth (1) 355,792 .044665 1/12/48 do 1,015 227,864 .044664 9/1/47 do (1) 25,538,167 .046898 5/10/46 Carson Co 1,015 1,067,626 .038196 6/16/46 do 1,015 144,027 .038802 6/16/46 Carson & Hutch. 1,015 393,256 .037933 6/16/46 Well mouth 1,015 477,079 .037999 6/16/46 do 1,015 148,789 .038881 8/18/45 Moore Co 1,015 248,024 .035740 2/27/37 Skellytown 1,055 12,578,884 .051148 2/1/37 Moore Co 1,015 567,268 .031803 2/1/37 do 1,015 11,808,203 .031811 4/21/36 Skellytown (1) 3,172,139 .035732 10/30/36 Moore Co 1,015 477,360 .022313 7/12/36 do 1,015 641,607 .031276 11/27/36 do 1,015 1,229,193 .031244 9/27/35 do 1,015 170,556 .031337 9/27/35 Carson Co 1,015 208,129 .031217 8/4/30 Well mouth 1,015 2,087,371 .040188 2/1/29 do 1,040 7,538,739 .043137 2/1/29 do 1,040 3,354,464 .043618 1950 9/25/50 Well mouth 1,015 63,856 .054999 4/5/50 Carson & Potter. 1,015 2,200,970 .050000 12/1/49 Well mouth 1,015 190,492 .053709 10/14/49 Hutch. & Moore. 1,015 1,963,395 .053744 11/26/48 Production line. 1,081 1,509,687 .049131 8/1/48 Well mouth 1,073 310,709 .044665 1/12/48 do 1,015 229,415 .044678 9/1/47 do (1) 27,343,903 .046898 5/10/46 Carson Co 1,015 965,200 .038033 6/16/46 do 1,015 433,529 .037751 6/16/46 Well mouth 1,015 545,231 .038116 6/16/46 do 1,015 286,870 .038970 8/18/45 Moore Co 1,015 257,885 .035912 2/1/37 do 1,015 561,542 .031762 2/1/37 Moore Co 1,015 10,891,484 .031793 4/21/36 Skellytown (1) 3,247,883 .035732 2/27/36 do 1,050 12,620,252 .051052 10/30/36 Moore Co 1,015 432,311 .022200 7/12/36 do 1,015 652,084 .031364 11/27/36 do 1,015 1,100,664 .031210 9/27/35 do 1,015 137,721 .031590 9/27/35 Carson Co 1,015 187,797 .031054 8/4/30 Well mouth 1,015 1,981,671 .040140 2/1/29 Fritch. Texas. 1,040 8,360,407 .043759 1951 9/5/51 Well mouth 1,015 127,819 .055000 2/11/50 Skellytown (1) 211,205 .058360 6/8/50 Fritch, Texas. (1) 3,385,646 .053597 9/25/50 Well mouth 1,015 1,102,443 .055000 4/5/50 Carson & Potter. 1,015 1,757,088 .050000 1/7/49 Fritch, Texas. (1) 6,421,031 .071463 9/29/49 Skellytown (1) 445,203 .058158 12/1/49 Well mouth 1,015 232,747 .053721 10/14/49 Hutch. & Moore. 1,015 2,647,499 .053773 11/26/48 Carson Co 1,079 1,760,357 .049131 8/1/48 Well mouth 1,061 288,360 .044664 1/12/48 do 1,015 171,688 .044744 9/1/47 do (1) 26,069,862 .046898 5/10/46 Carson Co 1,015 498,802 .038154 5/10/46 do 1,015 604,148 .038136 6/16/46 do 1,015 422,531 .037928 6/16/46 Well mouth 1,015 620,846 .038134 6/16/46 do 1,015 331,570 .038988 8/18/45 Moore Co 1,015 228,981 .040298 2/27/37 Skellytown 1,050 12,570,392 .50894 2/1/37 Moore Co 1,015 556,779 .031870 2/1/37 do 1,015 10,236,103 .031913 4/21/36 Skellytown 1,110 3,458,588 .035732 10/30/36 Moore Co 1,015 415,535 .022200 7/12/36 do 1,015 630,717 .031440 11/27/36 do 1,015 913,163 .031310 8/4/30 Well mouth 1,015 1,922,452 .040189 2/1/29 Fritch, Texas. 1,040 10,404,454 .043818 1952 2/8/52 Moore Co 1,082 7,366,342 .093800 7/1/52 Well mouth (1) 25,216,364 .063463 11/1/52 do 1,084 1,443,235 .081164 4/14/51 Sunray, Texas. 954 12,850,537 .096373 4/12/51 do 954 10,454,488 .055796 8/30/51 Moore Co 1,015 11,580,777 .086637 2/11/50 Skellytown 1,090 200,450 .062694 6/8/50 Fritch, Texas. 1,081 3,997,675 .053597 9/25/50 Well mouth 1,015 1,088,790 .054998 4/5/50 Carson & Potter. 1,015 1,700,591 .049999 9/5/50 Potter Co 1,015 364,175 .054998 1/7/49 Fritch, Texas. 1,090 10,743,014 .086053 9/29/49 Skellytown 1,090 407,940 .062693 12/1/49 Well mouth 1,015 193,671 .053725 10/31/49 Sherman Co 1,000 250,564 .095351 11/26/48 Carson Co 1,079 1,560,237 .049131 8/1/48 Well mouth 1,079 269,712 .054816 6/16/48 do 1,015 314,267 .039053 1/12/48 do 1,015 126,165 .044822 5/10/46 Carson Co 1,015 487,768 .038326 5/10/46 do 1,015 565,287 .038290 6/16/46 do 1,015 419,218 .038080 6/16/46 Well mouth 1,015 585,048 .038199 8/18/45 Moore Co 1,015 211,567 .040351 2/27/37 Skellytown 1,025 12,620,612 .050393 2/1/37 Moore Co 1,015 512,418 .031872 2/1/37 do 1,015 10,414,633 .031939 4/21/36 Skellytown 1,117 3,562,265 .035732 10/30/36 Moore Co 1,015 508,574 .022195 7/12/36 do 1,015 568,200 .031436 11/27/36 do 1,015 1,129,727 .031310 9/21/35 Carson Co 1,015 3,770,922 .040126 6/29/35 Skellytown 1,000 25,959 .093962 6/29/35 Borger, Texas. 1,000 815,125 .093514 8/4/30 Well mouth 1,015 2,062,395 .041778 2/1/29 do 1,040 10,390,762 .043823 6/16/27 Phillips, Texas. 1,000 36,135 .066632 7/10/26 Riverview 1,000 6,045 .053176 1953 4/30/53 Well mouth 1,103 41,039,490 .067960 3/30/53 Carson Co 1,093 118,605 .080000 8/20/53 Moore Co 1,084 834,053 .100000 6/8/53 do 1,072 7,347,545 .100000 8/28/53 Skellytown 1,025 12,720,414 .051711 6/1/53 Well mouth 1,084 241,277 .081670 6/13/53 do 1,067 49,136 .081867 5/22/53 do 1,078 421,305 .092035 12/15/53 do 1,079 239,864 .064798 10/1/53 Skellytown 1,000 24,397 .0113525 10/1/53 Borger, Texas. 1,000 783,229 .0113494 11/2/53 Phillips, Texas. 1,000 34,459 .089451 11/19/52 Well mouth 1,001 223,972 .080000 12/16/52 do 1,047 664,688 .084700 7/1/52 do 1,000 20,930,896 .081300 11/1/52 do 1,073 7,213,064 .081183 11/9/52 Hansford Co. 1,000 112,551 .084895 9/5/51 Potter Co 1,015 256,464 .055000 2/11/50 Skellytown 1,090 183,958 .062690 6/8/50 Fritch, Texas. 1,085 1,144,327 .062530 9/25/50 Well mouth 1,015 1,373,652 .063150 4/5/50 Carson & Potter. 1,015 1,497,492 .050000 9/29/49 Skellytown 1,091 343,102 .062690 1/7/49 Fritch, Texas. 1,090 12,331,878 .096656 12/1/49 Well mouth 1,015 230,960 .053719 10/14/49 Hutch. & Moore Co. 1,015 2,522,903 .054361 12/31/49 Sherman Co. 1,000 160,279 .091723 11/26/48 Production lines. 1,103 1,385,848 .049131 1/12/48 Well mouth 1,015 86,453 .044972 3/4/48 Hutch. Co 1,015 1,438,339 .054300 5/10/46 Carson Co 1,015 404,810 .038349 5/10/46 do 1,015 508,901 .038324 6/16/46 do 1,015 363,445 .038075 6/16/46 Well mouth 1,015 563,773 .038196 6/16/46 do 1,015 309,828 .039060 8/18/45 Moore Co 1,015 207,717 .040353 2/1/37 do 1,015 484,277 .031876 2/1/37 do 1,015 9,314,409 .031944 4/21/36 Skellytown 1,119 2,995,190 .035732 10/30/36 Moore Co 1,015 445,420 .022190 7/12/36 do 1,015 608,655 .031438 11/27/36 do 1,015 985,859 .031314 9/21/35 Carson Co 1,015 3,136,554 .040147 8/4/30 Well mouth 1,015 1,762,919 .044910 7/10/26 Riverview Plant. 1,000 6,006 .059947 1954 5/11/54 Field Point 1,096 111,050 .0151805 2/2/54 Moore Co 1,081 12,890,127 .0140000 4/30/53 Well mouth 1,013 1,424,646 .077478 4/30/53 do 1,013 47,861,367 .092071 3/30/53 Carson Co 1,093 128,716 .080452 6/1/53 Well mouth 1,084 355,867 .080000 6/13/53 do 1,067 108,900 .080000 8/28/53 Skellytown. 1,025 3,677,406 .052227 5/22/53 Well mouth 1,078 953,238 .080000 12/15/53 do 1,079 214,026 .074083 10/1/53 Skellytown. 1,000 21,921 .0151334 10/1/53 Borger, Texas. 1,000 751,352 .0146025 11/2/53 Phillips, Texas. 1,000 32,659 .0149942 11/2/53 Riverview Plant. 1,000 5,349 .0106755 11/19/52 Well mouth 1,030 226,386 .088296 12/16/52 do 1,075 802,599 .089955 7/1/52 do 1,000 19,230,348 .080000 11/1/52 do 992 6,822,493 .080400 11/9/52 Hansford Co. 1,000 130,919 .090649 9/5/51 Well mouth 1,015 215,947 .055213 2/11/50 Skellytown 1,092 161,479 .063037 9/25/50 Well mouth 1,015 1,295,810 .070403 4/5/50 do 1,015 1,064,245 .080211 1/7/49 Fritch, Texas 1,086 10,229,048 .0105692 9/29/29 Skellytown 1,091 274,137 .063055 12/1/49 Well mouth 1,015 152,794 .054223 10/31/49 Sherman Co. 1,000 123,768 .0106818 11/26/48 Production lines. 1,103 1,100,256 .049131 5/10/46 Well mouth 1,015 334,570 .038345 5/10/46 do 1,015 389,820 .038320 6/16/46 Field Point 1,015 284,205 .038075 6/16/46 do 1,015 493,958 .038198 6/16/46 Well mouth 1,015 269,520 .039062 8/18/45 do 1,015 182,058 .040366 2/1/37 Field Point 1,015 441,548 .078134 2/1/37 do 1,015 7,846,147 .031940 4/21/36 Skellytown 1,116 2,799,292 .036630 10/30/36 Field Point 1,015 364,576 .022196 7/12/36 do 1,015 460,634 .031439 11/27/36 do 1,015 965,298 .0146525 9/21/35 do 1,015 2,865,478 .040147 8/4/30 Well mouth 1,015 1,405,568 .044907
*275Tabulation and Comparison of Basic Provisions of Original Contracts Under Which Pipeline Companies Made Field Purchases of Gas at Well Head in Texas Panhandle Area During Years 1943 Through 1954 as Reported to Federal Power Commission (Price converted to rate at 14.65 PSIA) Purchaser Seller Date of Sweet or sour contract Panhandle Navajo 8-4-30 See remarks Eastern. Natural gas. Do do 9-1-47 Sulphur fee merchantable gas. Natural gas Burnett- 2-11-50 Not more than 1 grain Pipeline. Cornelius. H[2]S or 30 grains sulphur per 100 cu. ft. Northern Phillips 8-1-48 (*280 ) Natural. Petroleum. Natural Gas I. Earl 9-29-49 Not more than 1 grain Pipeline. Nutter. H[2]S or 30 grains sulphur per 100 cu. ft. Panhandle Dunn- 12-1-49 Not more than 1 grain Eastern. Kimberlin. H[2]S or 20 grains sulphur per 100 cu. ft. Do Burnett- 4-5-50 do Cornelius. Do B. M. Britain 9-25-50 do Do Burnett- 9-5-51 do Cornelius. Northern Northern 11-1-52 Not more than 1/2 grain Natural. Natural Gas H[2]S or 20 grains sulphur Producing per 100 cu. ft. Company. Southwestern H. B. Dunn 11-9-52 ( ) Public Service. Colorado A. E. Herrmann 11-19-52 Not more than 1 grain Interstate. Corp., H[2]S or 20 grains sulphur et al. per 100 cu. ft. Do H. F. Sears 12-16-52 do Natural Gas Kimberlin & 3-30-53 Not more than 1 grain Pipeline. Howse. H[2]S or 30 grains sulphur per 100 cu. ft. Cities Service Cities Service 4-30-53 Not more than 1 grain Gas Co. Gas Prod. Co. H[2]S or 20 grains sulphur (Formerly per 100 cu. ft. Empire Gas Co.). Northern Texas 5-22-53 do Natural. Company. Do Cities Service 6-1-53 do Oil Co. Do Huval and 6-13-53 do Dunigan. Do Phillips 12-15-53 do Petroleum.
*276n1Tabulation and Comparison of Basic Provisions of Original Contracts Under Which Pipeline Companies Made Field Purchases of Gas at Well Head in Texas Panhandle Area During Years 1943 Through 1954 as Reported to Federal Power Commission (Price converted to rate at 14.65 PSIA) Contract Required price Purchaser B.t.u. Contract minimum cents/ MCF (14.65 PSIA) Panhandle 950 See remarks 3.1265 Eastern. Do 950 Ratably with gas delivered 4.0198 into buyer's line. Natural Gas ( ) Full allowable 5.35974 Pipeline. Northern ( ) Ratably with wells producing 4.4665 Natural. into buyer's line. Natural Gas ( ) Full allowable, ratably 5.3598 Pipeline. Panhandle ( ) Ratably with gas delivered 5.3600 Eastern. into buyer's line. Do 975 90% of legal allowable 5.0000 Do 975 Ratably with gas delivered 5.5000 into buyer's line. Do 975 Legal allowable 5.5000 Nothern 1,000 Ratably with gas purchased 8.0000 Natural. and produced by buyer. Southwestern ( ) Ratably with wells connected 9.0000 Public Service. to Phillips line. Colorado 1,000 Maximum allowable 8.0000 Interstate. Do 1,000 do 8.5000 Natural Gas ( ) Full allowable 8.0000 Pipeline. Cities Service 900 An annual volume of 6.7961 Gas Co. 80,754,778 MCF. Northern 950 Ratably with gas buyer 8.0000 Natural. is taking in Carson and Gray Counties. Do 950 do 8.0000 Do 950 do 8.0000 Do 950 do 8.0000 n1Tabulation and Comparison of Basic Provisions of Original Contracts Under Which Pipeline Companies Made Field Purchases of Gas at Well Head in Texas Panhandle Area During Years 1943 Through 1954 as Reported to Federal Power Commission (Price converted to rate at 14.65 PSIA) Area Dedicated Purchaser Delivery point acres Field County Panhandle Wellhead of the 1.961 W. Pan Carson Eastern. individual wells. Do do 1.961 do do Natural Gas Wellhead-buyer 164.3 do do Pipeline. to install gathering and metering facilities. Northern do 498.9 do do Natural. Natural Gas do 567 do do Pipeline. Panhandle do 160 do Moore Eastern. Do do 310.8 do Carson, Potter. Do do 600 do Moore, Potter. Do do 124.7 do Potter Northern Wellhead-buyer 15,200 W. Pan Carson, Natural. to install gathering Gray. and metering facilities. Southwestern do 640 T. Hugo Hansford. Public Service. Colorado do 160 W. Pan Moore Interstate. Do do 302.6 do Hutch., Moore, Potter. Natural Gas do 80 do Carson Pipeline. Cities Service do 102,143 T do Carson, Gas Co. 88,686 O Gray. Northern do 2,160 do Gray Natural. Do do 640 do Carson, Gray. Do do 320 do Gray Do do 498.9 do Carson n1Tabulation and Comparison of Basic Provisions of Original Contracts Under Which Pipeline Companies Made Field Purchases of Gas at Well Head in Texas Panhandle Area During Years 1943 Through 1954 as Reported to Federal Power Commission (Price converted to rate at 14.65 PSIA) Purchaser Term Special provisions and remarks Panhandle Life of lease Gas to be purchased on Eastern. a pro rata basis with other wells connected to Buyer's line. Buyer may reject gas if it contains more than 20 grains of sulphur per 100 cu. ft. Do do Second 5 year period, the price shall be 4.4665 cents/MCF; next 5 years, 4.9131 cents/MCF; thereafter for each 5 year period, the weighted average price. This is a modification of the above contract. Natural Gas So long as gas can For 5 year period beginning Pipeline. be delivered in 7-1-51, the price commercial shall be 6.25303 cents/MCF; quantities. thereafter, the price shall be 7.14632 cents/MCF Northern 5 yrs. & thereafter The base price is the Natural. on 60 days' notice price shown or the of termination. weighted average price, whichever is higher. When the weighted average price exceeds the price shown, then such weighted average price shall prevail. Natural Gas So long as gas During 5 year period Pipeline. can be delivered beginning 7-1-51, the in commercial price shall be 6.2530 cents/ quantities. MCF. Beginning 7-1-56 and thereafter the price shall be 7.1463 cents/MCF. City of White Deer has first call on gas produced from this lease. Panhandle So long as gas is For the second 5 year Eastern. produced in period, the price shall paying quantities. be 5.8000 cents/MCF; for the third 5 year period, 6.2500 cents/MCF; for each 5 year period thereafter the price shall be the weighted average field price. Do do If Buyer is required to treat gas for removal of sulphur, the price shall be reduced 0.2500 cents/MCF. From 4-1-55 to 4-1-60, the price shall be 7.0000 cents/ MCF; thereafter, 8.0000 cents/MCF. Do do For the second 5 year period the price shall be 7.0000 cents/MCF; thereafter, 8.0000 cents/ MCF. Do do If Buyer is required to treat gas for the removal of sulphur, the price shall be reduced 0.2500 cents/MCF. For second 5 year period, the price shall be 7.0000 cents/MCF; thereafter, 8.0000 cents/ MCF. Nothern As long as gas For each 5 year Natural. can be delivered period beginning in commercial 1-1-58, the price shall quantities. be determined by negotiation, but shall not be less than 8.0000 cents/MCF. Southwestern To 1-1-63 Beginning 1-1-57 the Public Service. price shall be 10.0000 cents MCF. Purchase under this contract is engaged in distribution of gas for domestic and industrial use in Stratford and other areas in the vicinity of this well, and purchases this gas to supplement its requirements for gas being distributed by it. Southwestern as Buyer of gas delivers the gas through a connecting line to Phillips' line and takes a like volume of gas from Phillips' line near City of Stratford. Colorado 20 yrs. & thereafter If Buyer at any time Interstate. as long as gas pays more than can be delivered. 8.0000 cents/MCF for gas in Moore County, then price paid seller shall be adjusted accordingly. Do do For each 5 year period after the initial 5 year period, the price shall be negotiated, but shall not be less than 9.5000 cents/MCF. If Buyer at any time pays more than the prices stated in the Counties of Moore, Hutchinson and Potter, the price paid Seller shall be adjusted accordingly. Natural Gas So long as gas None. Pipeline. can be delivered in commercial quantities. Cities Service 20 yrs. from Price intended to be Gas Co. 4-1-53 & thereafter prevailing field price as long as and to be adjusted gas can be delivered from time to time to in commercial reflect such prevailing quantities. field price. Contract also covers acreage in Oklahoma Hugoton Field. Northern 20 yrs. from date For each 5 year period Natural. of initial delivery beginning 7-1-58, the or 6-30-53 price is to be determined whichever is by negotiation, earlier. but shall not be less than 8.0000 cents/MCF. Do So long as gas Do. can be delivered in commercial quantities. Do do Do. Do To 12-31-73 Do. *277 *1028 Petitioner, in filing its separate returns for the fiscal years ending November 30, 1948, through November 30, 1954, and the respondent in the notices of deficiency, treated bonuses paid to lessors or assignors, who retained an economic interest in the property, for the acquisition of leases, as having been paid or incurred by petitioner as capital expenditures.
The parties have stipulated the amounts of the bonuses paid, the leases in connection with which they were paid, and the estimated life of each of these leases.
OPINION.
I.
Depletion Issue .This issue, stated broadly, is the determination of the "gross income from the property" for the purposes of computing the depletion allowance for the fiscal years 1943 through 1954 with respect to natural gas produced by the petitioner and in which petitioner owned an economic interest.
It is provided in
section 23 of the Internal Revenue Code of 1939 that:In computing net income there shall be allowed as deductions:
* * * *
(m) Depletion. -- In the case of mines, oil and gas wells, other natural deposits, and timber, a reasonable allowance for depletion and for depreciation of improvements, according to the peculiar conditionsin each case; *278 such reasonable allowance in all cases to be made under rules and regulations to be prescribed by the Commissioner, with the approval of the Secretary. * * *
A further provision,
section 114(b)(3) of the 1939 Code, reads as follows:(3) Percentage depletion for oil and gas wells. -- In the case of oil and gas wells the allowance for depletion under
section 23(m) shall be 27 1/2 per centum of the gross income from the property during the taxable year, 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 per centum of the net income of the taxpayer (computed without allowance for depletion) from the property, except that in no case shall the depletion allowance undersection 23(m) be less than it would be if computed without reference to this paragraph.No issue is raised as to either the use of percentage depletion or to the 50 per centum of net income limitation. The issue before us is simply the determination of the "gross income from the property" to which the percentage of allowable depletion is to be applied.
Regulations prescribed by the Commissioner, applicable *279 to the years 1943 through 1954, *1029 The term "gross income from the property," as used in
sections 114(b)(3) and114(b)(4)(A) * * * means the following: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.The regulations prescribed by the Commissioner since the first provision for percentage depletion in the case of oil and gas wells in the Revenue Act of 1926 have contained substantially the same language as that quoted above.
Early in the history of percentage depletion on oil and gas the question arose as to the point at which the "gross income" was to be measured. It was decided, and not contested here, that this point was the well mouth and that the "gross income from the property" was the gross income from the sale of the mineral at that point.
Brea Canon Oil Co ., 29 B.T.A. 1134 (1934)Brea Canon Oil Co. v.Commissioner , 77 F. 2d 67Signal Gasoline Corporation , 30 B.T.A. 568">30 B.T.A. 56877 F. 2d 728 (C.A. 9, 1935);Greensboro Gas Co ., 30 B.T.A. 1362 (1934)79 F. 2d 701 (C.A. 3, 1935);Consumers Natural Gas Co ., 30 B.T.A. 1263">30 B.T.A. 126378 F. 2d 161 (C.A. 2, 1935).The necessity to "adjust" the actual selling price demonstrates that the gas was not sold at the point where the "gross income" is to be *1030 measured, that is, at the well mouth or "in the immediate vicinity of the well." Petitioner concedes that it did not sell the gas in its raw state at the mouth of the well and we have found that the gas which was sold (residue and not raw gas) was sold from petitioner's gasoline extraction plants only after it had been gathered *282 and processed. This processing has been held to be a manufacturing operation.
Brea Canon Oil Co., supra ; Signal Gasoline Corporation, supra ."Gross income from the property" under the second and ultimate provision of the applicable regulation, is to be assumed to beequivalent to the representative market or field price (as of the date of sale) of the oil and gas before conversion or transportation. The point at which the "gross income" is to be determined is the well mouth for it is expressly provided in the regulation that this measure of "gross income" shall be applied "if the oil and gas are not sold on the property but are manufactured or converted into a refined product prior to sale."
With this directive that the "gross income * * * shall be assumed to be equivalent to the representative *283 market or field price * * * of the oil and gas before conversion or transportation," the regulation falls silent. No definition of the term representative market or field price is given. No direction as to how this representative market or field price is to be determined is offered. Agreed that the "gross income" is to be determined at the well, and that it is to be the equivalent of the representative market or field price, the parties present for our decision the specific issue of their disagreement, that is, the method to be used for the determination of this price.
In a recent opinion,
Cities Service Gas Producing Co. v.Federal Power Commission , 233 F.2d 726">233 F. 2d 726
"Prevailing field price" has a definite and well understood meaning in the oil and gas industry. What is the prevailing field price is a question of fact which can be readily ascertained, and any method which would fairly reflect such price would be a proper yardstick under the contract. It would have been more satisfactory, especially in dealing between affiliates, if the contract had provided methods of calculating field prices more *284 explicit and definite and had also set out dates when such prices were to go into effect. However, there are a great many contracts in oil and gas and other areas of the law in which a price to be paid is designated as dependent upon "market price" or a like term of no more certainty than in this contract; notable among these are royalty interests under *1031 oil and gas leases. Yet these contracts are held to provide a calculable figure sufficiently definite for enforcement. * * *"Prevailing field price" having a definite and well-understood meaning in the oil and gas industry, it would appear to us that it was to this meaning that the Commissioner intended us to look when in article 201(h) of Regulations 69 he first directed that "If the mineral products are not sold as raw material but are manufactured or converted into a refined product, then the gross income shall be assumed to be equivalent to the
market or field price of the raw material before conversion." (Emphasis added.)The enforcement of royalty interests under oil and gas leases has presented a troublesome problem to the courts for many years. In most of the decided cases on this point, an action was brought by the lessor *285 of a gas lease against the lessee for additional sums for gas taken from the lease. Most of the lease agreements involved provided for a payment by the lessee of a royalty to be calculated at the rate of market price. One of the most prolonged suits, that brought by one Sartor against the Arkansas Natural Gas Company, came before the United States Court of Appeals for the Fifth Circuit several times. On one occasion,
Arkansas Natural Gas Co. v.Sartor , 78 F. 2d 924Sartor v.United Gas Public Service Co ., 84 F. 2d 436134 F. 2d 433 (C.A. 5, 1943), the United States Court of Appeals for the Fifth Circuit set forth the history and a summary of the result of the Sartorv. Arkansas Natural Gas Corporation litigation. The court said that the object and purpose of the inquiry in a case of the kind before the court was to determine (1) the market price at the well, or (2) if there was no market price at the well for the gas, what it was actually worth there. Referring to *1032 three other similar cases, the court said that if the market price at the well could be established, resort to pipeline contracts and other such testimony *287 to establish the value of the gas would not be admissible. *288In
Shamrock Oil & Gas Corporation v.Coffee , 140 F. 2d 409
Market price is the price that is actually paid by buyers for the same commodity in the same market. It is not necessarily the same as "market value" or "fair market value" or "reasonable worth". Price can only be proved by actual transactions. Value or worth, which is often resorted to when there is no market price provable, may be a matter of opinion. There may be a wide difference between them. The first inquiry here must be whether there was a market price. All the witnesses say that gas like this was bought at the mouth of the well continually in this field. A market price therefore existed and was admittedly proven by actual sales. Opinions and estimates, and particularly consideration of what the buyers could have paid or should have paid, are entirely irrelevant.Phillips Petroleum Co. v.Bynum , 155 F. 2d 196We say that it is not a matter of geography nor of county lines nor of the area embraced in a particular field, but that it is a matter of business, of economics, of supply and demand, and of the existence and availability of a market.
* * * The question, therefore, is not what happens in Moore County, but whether or not there have been recent, substantial, and comparable sales of like gas to gasoline extracting plants, carbon black plants, and the like, from wells in the area whose availability for marketing is reasonably or substantiallysimilar to that of the gas here involved. * * * In the absence of available evidence as to market price at the well it would seem appropriate and relevant to inquire as to the market price paid at the plants of gasoline extractors, after deducting the cost of transportation. *291 * * *
* * * Certain features of cases like this that cannot be overlooked are: (1) That where the contract requires the payment of market price at the well the Court cannot make a new contract. (2) The Court must undertake to see that the contract is carried out if reasonably possible. (3) Neither the Court nor the litigants can get away from the fact that the contract here calls for the payment of market price at the well and the fact that the ascertainment of market price may be troublesome, or that the contract is improvident, is not a web of the Court's weaving. The Court must hold the parties to market price at the well if it is possible to ascertain market price. Neither of the parties nor the Court has the right to exercise any option in the matter. (4) The only theory upon which the Court can allow a recovery for the reasonable value of the gas would be because of proof that it was impossible toascertain market price and, therefore, impossible to carry out the agreement of the parties to pay and to receive market price. Upon it being made clearly to appear that the measure of compensation provided in the contract cannot be applied, the Court, in order to prevent injustice, *292 will require the lessee to pay the reasonable value of such part of lessor's property as has been taken theretofore.
* * * The Courts must also be realistic in considering the question of market price. Daily sales and daily quotations, as in the case of cotton, wheat, or corn, are not essential to an ascertainment of market price, although this would furnish the answer if there were such daily sales.
Sartor v. United Gas & Pub. Serv. Co., supra. The nature of the commodity involved renders it unnecessary that business connected with it be transacted on the basis of daily market fluctuations, and when seeking market value of gas at the well we cannot require the application of rules of daily sales and daily quotations when there is no showing that such sales and quotations occur.* * * *
* * * Under the evidence in this case the only substantial market for the plaintiffs' gas is that afforded by plantsthat extract gasoline and other products from the gas, and in the absence of proof of an unlawful combination between such producers for suppression of the market price, the test is what do such producers pay for gas similar in quantity, quality, and availability to market? * * * [
155 F. 2d at 198, 199 .]In *293 an addendum to its opinion, denying a petition for rehearing, the court again emphasized that the market price of gas is determined by sales of gas, comparable in time, quantity, quality, and availability to marketing outlets and that the term "market price at the well" *1034 meant the price which similar gas brought at the mouth of wells generally in the field.
We believe the reasons apparent why we cannot adopt petitioner's contention that representative market or field price is to be determined by taking the actual sales prices of its residue gas and liquefied hydrocarbons and deducting therefrom the costs of processing, transporting, and gathering. There are the serious problems raised by the fact that petitioner does not sell all of its residue gas or liquefied hydrocarbons but that much of these salable products is transferred for use in other operating divisions of petitioner, that difficult allocations of costs of transporting and gathering are involved, and that problematical questions such as what constitutes a fair return on the investment in the processing, transporting, and gathering facilities are presented. But more important, we do not believe that this method permits *294 the ascertainment of the representative market or field price as the regulations intended. Rather, it appears more suited for the determination of such a concept as "
net proceeds derived from the sale of gas at mouth of the well ." SeePhillips Petroleum Co. v.Johnson , 155 F. 2d 185Market price being the price that is actually paid by buyers for the same commodity in the same market, provable only by actual transactions, it is necessary to determine whether there are in evidence a sufficient number of actual sales of raw gas at the well from which we can find first, that there was a market for raw gas at the well and second, what the price in that market was for the years in issue.
Much of the material set forth in our Findings of Fact was stipulated by the parties. From an analysis of this material it may be seen that petitioner augmented its own volume interest in the raw gas it produced by the acquisition of the royalty owners' gas, the purchase of gas from its partners in working interests, the purchase of casinghead gas, the purchase of gas under miscellaneous contracts, and the purchase of gas from the Continental Oil Company. All of the purchases were of raw gas and were made at the wellhead.
Respondent has combined the weighted average price *296 paid by petitioner in each of the years in issue for this gas so acquired and has *1035 therefrom determined what he contends to have been the "representative market or field price" of petitioner's volume interest in the gas it produced. For two reasons we disagree with this determination.
First, we believe it improper that the weighted average price paid to royalty owners in each of the years in issue was included in the overall weighted average to determine the representative market or field price. Under the law of the State of Texas, *297 in the courts. See
Arkansas Natural Gas Co. v.Sartor, supra For another reason we believe it improper to include the royalty payments in the weighted average to determine representative market or field price. It is possible for a lessee to increase the royalty payments to an amount above the market price with the hope that, if royalty payments are to determine the representative market or field price, the increased royalty payment will sufficiently increase the depletion base of his seven-eighths interest so that the tax saving from an increased depletion allowance will be in excess of the cost of the additional royalty payment made. *298 Royalty payments then, apart from not representing price, may constitute self-serving evidence for the lessee.
Second, the inclusion of the weighted average price paid to the Continental Oil Company in the formula for the determination of the representative market or field price was in error. Petitioner introduced evidence showing that the original contract made with Continental Oil was made under circumstances where Shamrock and Continental agreed to form the Continental Carbon Company as an outlet for the residue gas. Under the circumstances of the contract for *1036 the sale of the Continental gas, it appears that factors other than the market or field price of the gas partly determined the contract price.
Excluding the royalty payments and the Continental *299 Oil sale, the question is whether sufficient other raw gas sales of comparable quantity took place to permit the ascertainment of a representative market or field price for the petitioner's gas. Petitioner, in fact, does not contend that there was no market for raw gas, merely that no such market existed for the quantities of gas which it owned exclusive of the raw gas which it acquired by purchase. However, the question under the applicable section of the regulation is what is the representative market or field price of the gas before conversion or transportation, presumably the price at the mouth of the well. Petitioner's production was from as many as 225 producing properties which were located in an area of many square miles. Petitioner has introduced no evidence tending to show that the properties from which it produced gas were more productive than other properties in the area. In addition, petitioner has not demonstrated to us that the cost of aggregating his production, by the installation of a gathering system, was any less than the cost of aggregating other comparable production. Admittedly, after petitioner's gas was aggregated in its gasoline extraction plants by *300 transportation from the many properties through petitioner's extensive gathering system, it may have constituted a sufficiently large volume of gas to command a premium price. However, for purposes of determining the gross income from the property to compute the depletion allowance the point at which the gross income is to be measured is the mouth of the well.
Brea Canon Oil Co., supra ; Greensboro Gas Co., supra ; Consumers Natural Gas Co., supra .Certain evidence introduced by the petitioner we believe was wrongfully excluded from consideration by respondent in determining the representative market or field price. Petitioner introduced into evidence reports filed by interstate pipeline companies with the Federal Power Commission showing the volume and price of raw gas purchased by these companies during the years in issue. Respondent objected to the admission of these reports on the ground that under the rules and regulations of the Federal Power Commission *301 the cost of raw gas purchased may include transportation, compression, and other costs not incident to the purchase of the gas. Indeed, cross-examination of the representatives of these companies revealed that they could not say that the prices shown on the reports did not include such additional costs. We have included in our Findings of Fact a summary of only the raw gas purchased in the field by these *1037 companies during the yearsin issue, showing for each individual contract the point of receipt of such gas. Several of the contracts called for the receipt of the purchased gas at the well mouth. We believe that these contracts are relevant evidence of the representative market or field price of raw gas at the well mouth for the reason that respondent's objection that the price shown may include transportation, compression, or other costs cannot, it appears to us, extend to the purchases of raw gas at this point.
The objection to the introduction into evidence of pipeline contracts in the royalty cases, summarized in
Phillips Petroleum Co. v.Bynum, supra Using weighted average prices actuallypaid for gas by buyers in the same market, petitioner contends that if a weighted average price is to be used to determine the "representative market or field price" then it should be a weighted average of prices negotiated in the year in issue. In a rising market where sales have most often been made on a long-term basis, use of an average of prices negotiated in the year can effect a substantially different result than that from use of an average of actual prices paid for gas delivered in that year because some of these presumably would have been negotiated in prior years.
The applicable section of the regulation contains this language:
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 *303 prior to sale, the gross income from the property shall be assumed to be equivalent to the representative market of field price (as of the date of sale) of the oil and gas before conversion or transportation.
Presumably, the representative market or field price is to be ascertained as of a given day and that is the day the refined or transported product is sold, or otherwise disposed of. However, market price "is the price that is actually paid by buyers * * *. It is not necessarily the same as 'market value' or 'fair market value' or 'reasonable worth.'"Shamrock Oil & Gas Corporation v.Coffee, supra .Helvering v.Mountain Producers Corporation , 303 U.S. 376">303 U.S. 376James P. Evans, Sr ., 11 T.C. 726">11 T.C. 726Although in the case of integrated producers who manufacture or convert oil or gas *304 into a finished product prior to sale, or who transport oil or gas from the property prior to sale, the amount of depletion may not vary with their individual situations because their actual gross income from the property shall be assumed to be equivalent to the representativemarket or field price. This is no reason for departing from the general principle that the statute bases the percentage on what the producer actually receives for the oil or gas at the well rather than its market value.
The only consideration we have been able to find of the problem of determining "gross income" at the well of an integrated producer of gas, and then not always in terms of ascertaining the "representative market or field price," has been those early cases where the issue was the point at which to measure the "gross income." Unanimous in their holdings that the well mouth was the appropriate place to determine the gross income, the courts which passed on this question were divided on the method to be employed to arrive at the proper figure. However, the question of method to be used in determining the gross income at the well was not specifically before these courts in any of the cases mentioned. *305 In the
Brea Canon case before the Board of Tax Appeals, the parties stipulated that the fair market value of the raw gas at the well was 40 percent of the receipts from the sale of liquefied hydrocarbons extracted therefrom. The Board, commenting that the "fair marketvalue of the wet gas at the well * * * only * * * can be * * * regarded as an element of the gross income from the petitioner's oil and gas properties," approved the stipulated figure. On appeal, the Ninth Circuit, citing with favor the respondent's regulation that the "gross income shall be assumed to be equivalent to the market or field price," concurred.In the
Greensboro Gas Co . case, the respondent determined the "gross income" by computing separately the gross income from each of the several properties in question and adding together the gross incomes so computed, using as a basis for his computation the market or field price of the gas before transportation from the properties, which market or field price he determined to be 23 cents per MCF. The Board's conclusion was that the price at which petitioner sold its gas to ultimate consumers could not be said to be "gross income from the property" which produced *306 the gas and in respect of which petitioner claimed an allowance for depletion. In the opinion of the Board its conclusion was supported by the fact that during the taxable period petitioner purchased 52,344 MCF of gas (compared with *1039 production of 1,164,328MCF) at a cost of approximately 21 cents per MCF, transported the same through its gas mains, and sold the gas to consumers at a price of approximately 40 cents per MCF. The Board said:The difference between the purchase and sale prices, to the extent that it exceeded cost of transportation, represented income derived by the petitioner from its services and investment in the properties used in transportation, and it would hardly be contended that such income constituted "gross income from the property" (in this instance not owned by the petitioner) which produced the gas. So also, if the petitioner had sold its gas at the wells and the same had been transported and distributed by others the increased price for distribution would not constitute "gross income from the property" of the petitioner, which produced the gas.
* * * *
The respondent has determined the amount of petitioner's "gross income from the property" on the basis of *307 a market or field price of 23 cents per thousand cubic feet before transportation from the properties, and the petitioner does not attack respondent's computation, nor does it offer evidence to show that the market or field price so determined by therespondent is not correct. Respondent's determination of the fair market or field price is further supported by the fact that during the taxable period the petitioner purchased gas at a price, before transportation, only slightly in excess of 21 cents per thousand cubic feet. * * * [
30 B.T.A. at 1368-69 .]The last one of these cases was
Consumers Natural Gas Co., supra .
True, its [the basis for depletion] correction involves some computation; the sales price must be broken *308 down into two component parts, the value contributed by the later services, and the remainder of the gross price. But the contributed value is not inaccessible; the apparatus for transportationis known, its cost, its wear and tear, its coefficient of obsolescence; the calculation is like much that is customary in reckoning other taxes, and there is no reason to suppose that Congress would shrink from it. Indeed, it cannot be avoided in many cases. Article 221(i) of Regulations 74 requires, both when the gas and oil is refined and when it is transported, that the "market or field price * * * before conversion or transportation" shall be the "basis for depletion." The taxpayer concedes, and must concede, that this is the right rule when the product is converted into something else. * * * [78 F. 2d at 161-162 .]Considering the language of the applicable section of the regulations and the authorities cited above, we conclude that "representative market or field price" is to be determined by the computation of a weighted average of actual prices paid in the years in issue by *1040 buyers for raw gas. Includible in this weighted average, under the facts of this case, are the prices paid by *309 petitioner for gas purchased from the working interest of others, the prices paid by petitioner for casinghead gas, the prices paid for gas purchased by petitioner under miscellaneous contracts, excepting the Continental Oil Company contract, and the prices paid by interstate pipeline companies for raw gas delivered at the well mouth.
II.
Bonus Issue .The sole remaining issue involves the tax treatment in the hands of Shamrock of cash bonuses or initial payments paid by it for the original acquisition or assignment of oil and gas leases to lessors or assignors who retained an economic interest in the property involved. This issue relates only to the fiscal years 1948 through 1954.
Broadly defined, a "bonus" is the term applied to money received by the lessor upon the execution of an oil and gas lease. It is part of the consideration for the lease by virtue of which the lessee acquires the privilege of exploiting the land for the production of oil and gas for a prescribed period; he may explore, drill, and produce oil and gas, if found.
Burnet v.Harmel , 287 U.S. 103">287 U.S. 103In the ordinary oil and gas lease, the lessor reserves a royalty interest, commonly one-eighth, in any production *310 from the property which follows its exploitation. The word "royalty" as used in such a lease generally refersto a share of the product or profit reserved by the owner for permitting another to use the property. It is compensation for the privilege of drilling and producing oil and gas and consists of a share in the product.
J. T. Sneed, Jr ., 33 B.T.A. 478 (1935)G.C.M. 22730, 1 C.B. 214">1941-1 C.B. 214 . Such a royalty is gross income taxable in the hands of the lessor upon which he is entitled to a reasonable allowance for depletion. The lessee, on the other hand, does not include the lessor's royalty in his own gross income, nor does he include the royalty in the "gross income from the property" upon which his own statutory depletion allowance is based. It is axiomatic that there can be only a single allowance for depletion on a given barrel of oil.Helvering v.Twin Bell Syndicate , 293 U.S. 312">293 U.S. 312It is within this general framework that the tax treatment of lease bonuses must be considered. The present status of such payments, which will be discussed hereafter in greaterdetail, may be summarized *311 as follows: (1) In the hands of the lessor-payee, the bonus is taxable as ordinary income in the year received or accrued and is subject to a reasonable allowance for depletion; (2) in the hands of the lessee-payor, the bonus must be deducted from the "gross income from the property" upon which percentage depletion is computed, *1041 while, secondly, the bonus is treated as a capital investment not excludible nor deductible from taxable income but recoverable only through the depletion allowance.
The petitioner's contentions with respect to the lease bonuses are set forth in its brief as follows:
While not claimed in the respective returns filed by petitioner for the years ending November 30, 1948, through November 30, 1954, petitioner submits and now claims: (1) that bonuses or initial payments paid or incurred by petitioner with respect to mineral leases and subleases acquired from original lessors and assignors, who retained economic interests in the property or subleases, should have been claimed and treated as exclusions from income or as allowable deductions of the petitioner in the respective years that such bonuses or initial payments were paidor incurred; (2) alternatively, petitioner *312 asserts that if payments of such character are to be treated as, or held to be, advanced royalties, but not deductible in the year paid or incurred, same are excludable from taxable income and should have been excluded from taxable income arising from production from such lease or sublease on a proportionate annual basis, based on the anticipated productive life of the respective leases.
Petitioner additionally asserts if such bonuses or initial payments are to be held to be, or treated as, capital investments (but not as bonuses deductible from gross income in the respective years paid or incurred, or, alternatively, as advance or prepaid royalties, excludable from taxable income on a proportionate annual basis, based on the anticipated productive life of the leases), then an allocate part of such capital expenditures, based upon the anticipated productive life of such property should not be deducted annually from production before computing statutory percentage depletion as required by respondent.
The existing pattern of tax treatment with respect to oil and gas lease bonuses has arisen primarily from decisions of the courts dealing withsuch bonuses in the hands of the lessor-recipient. *313 Thus, while the tax status of the lessor is not directly at issue here, it is there that we must start our consideration of the problem. The Supreme Court early held that a cash bonus paid to a lessor was to be treated as ordinary income.
Burnet v.Harmel, supra .287 U.S. at 111, 112) :The court below thought that the bonus payments, as distinguished from the royalties, should be treated as capital gain, apparently because it assumed that the statuteauthorizes a depletion allowance upon the royalties alone. See
Ferguson v.Commissioner , 45 F. (2d) 573, 577Treasury Regulations 65 , as well as under earlier acts. § 214a(10), Revenue Act of 1921, Art. 215,Treasury Regulations 62 . Cf.Murphy Oil Co. v.Burnet , 55 F. (2d) 17Alexander v.King, supra ; Ferguson v.Commissioner , 59 F. (2d) 891Appeal of Nelson Land & Oil Co ., 3 B.T.A. 315">3 B.T.A. 315Burkett v.Commissioner , 31 F. (2d) 667Board of Tax Appeals, 7 B.T.A. 560">7 B.T.A. 560 ;Berg v.Commissioner , 33 F. (2d) 641Hirschi v.United States, supra . We see no basis for it. Bonus and royalties are both consideration for the lease and are income of the lessor. We cannot say that such paymentsby the lessee to the lessor, to be retained by him regardless of the production of any oil or gas, are any more to be taxed as capital gains than royalties which are measured by the actual production. SeeWork v.Mosier , 261 U.S. 352">261 U.S. 352The above-quoted language *315 contains the only reference in the Supreme Court's opinion to the depletion question which is unfortunate because, despite the almost "in passing" nature of the reference, it became the keystone of the tax treatment of cash bonuses. Thus, in the other leading case in this field decided by the Supreme Court later that same term,
Murphy Oil Co. v.Burnet , 287 U.S. 299">287 U.S. 299We think it no longer open to doubt thatwhen the execution of an oil and gas lease is followed by production of oil, the bonus and royalties paid to the lessor both involve at least some return of his capital investment in oil in the ground, for which a depletion allowance must be made under § 234. See
Burnet v.Harmel, supra .At this juncture, it may be noted that
Burnet v.Harmel arose under the Revenue Act of 1924, and thatMurphy Oil Co. v.Burnet arose under the Revenue Act of 1918, neither of which statute made any provisions forpercentage depletion, an allowance which, in the case of oil and gas wells, was first provided by the Revenue Act of 1926.Palmer v.Bender , 287 U.S. 551 (1933)Anderson v.Helvering , 310 U.S. 404*1043 (1940)Burton-Sutton Oil Co. v.Commissioner , 328 U.S. 25 (1946)Burnet v.Harmel andMurphy Oil Co. v.Burnet , that a cash bonus is depletable in the hands of the lessor. Examination of the opinions in those two cases, particularly the excerpts quoted above, indicate that the Supreme Court attached great weight *317 to the fact that bonus payments to the lessor were "deemed to be subject to depletion allowances" under the regulations promulgated under the Revenue Act of 1924 as well as earlier acts. *320 These various regulations are substantially identical in language. The earliest, that contained inTreasury Regulations 45 promulgated under the 1918 Act provided as follows:Art. 215, Depletion -- Adjustments of accounts based on bonus or advanced royalty. -- (a) Where a lessor receives a bonus or other sum in addition to royalties, such bonus or other sum shall be regarded as a return of capital to the lessor, but only to the extent of the capital remaining to be recovered through depletion by the lessor at the date of lease. If the bonus exceeds the capital remaining to be recovered, the excess and all the royalties thereafter received will be income and not depletable. If the bonus is less than the capital remaining to be recovered by the lessor through depletion, the difference may be recovered through depletion deductions based on the royalties thereafter received. The bonus or other sum paid by the lessee for a lease made on or after March 1, 1913, will be his value for depletion as of *318 date of acquisition.
During the years before the Supreme Court in the
Burnet v.Harmel andMurphy Oil Co. v.Burnet cases, the applicable depletion allowances were cost depletion and discovery value depletion, the latter *1044 being eliminated, in the case of oil and gas wells, by the 1926 Act which, as we have seen, made the first provisions for percentage depletion. *321 otherwise) was less than the bonus received, the excess of the bonus over such capital to be recovered was taxable in full as ordinary income and not depletable. Thus, the fact that a bonus had been received did not operate to increase by a penny the total to be recovered through the depletion allowance. In actual fact, if there is any conclusion or inference to be drawn from the regulation in question as to the status for depletion of lease bonuses, it is to the effect that such bonuses were depletable in the hands of the lessee. In this connection, the last sentence of the regulation, already quoted but repeated here, declares:
The bonus or other sum paid by the lessee for a lease made on or after March 1, 1913, will be his value for depletion as of date of acquisition.
Insofar as can be determined, there was no depletion issue before the Supreme Court inBurnet v.Harmel . Neither the trial court,Burnet v.Harmel, supra In
Murphy Oil Co. v.Burnet, supra pro tanto the depletion allowed on the royaltiesreceived in later taxable years."*1045 The taxpayer-lessor had received a cash bonus, followed by royalties. Having allocated none of its depletion allowance to the bonus, it sought to deduct the whole allowance against the royalties received in the taxable years. The Commissioner insisted that a portion of the allowance should have been recovered from the bonus and only the remainder from the royalties. Under the regulations already quoted, the capital recoverable through depletion would have *323 been recovered dollar for dollar against the bonus as received, only the excess, if any, being recovered by way of deduction from the subsequent royalties. However, that regulation had been amended in 1926 to read as follows:
(a) Where a lessor receives a bonus in addition to royalties, there shall be allowed as a depletion deduction in respect of the bonus an amount equal to that proportion of the cost or value of the property on the basic date which the amount of the bonus bears to the sum of the bonus and the royalties expected to be received. Such allowance shall be deducted from the amount remaining to be recovered by the lessor through depletion, and the remainder is recoverablethrough depletion deductions on the basis of royalties thereafter received. *324 this regulation, the fact of a bonus payment in no way affected the total amount to be recovered by the lessor through depletion. The determination of the Commissioner was sustained by the Court on the ground that the bonus was ordinary income out of which the depletion allowable was properly recoverable and that the method of allocation set up by the Commissioner in his regulations as between bonus and royalties was reasonable.
Murphy Oil Co. v.Burnet, supra .The above represents the state of the tax law with respect to lease bonuses prior to the applicability of percentage depletion. As we have pointed out above, under the various alternative depletion allowances available prior to 1926, the total depletion allowable with respect to any mineral property was a sum certain, fixed on the basis of actual cost or of value determinations, as the case may have been. The total depletion allowable to a lessor with respect to a given property was unaffected by the fact of whether or not a bonus was paid. Receipt of a bonus essentially only affected the timing of the lessor's depletion recovery. It is apparent *325 that the two leading cases in the field,
Burnet v.Harmel andMurphy Oil Co. v.Burnet , did no more than sustain the treatment which had been accorded by the Commissioner *1046 as early as his regulations under the 1918 Act. *326 of allocation and of timing of capital recovery became a matter critically affecting the total dollar amount of depletion available to each of the parties to a lease.However, it was not until 1933 that the Commissioner took a position with respect to applicability of percentage depletion to lease bonuses. In
G.C.M. 11384 Murphy Oil Co. case" was to allow percentage depletion to the lessor on a bonus if production occurred in the taxable year or if "future production [were] practically assured because of near-by wells and geological indications." The ruling reflects an apparent awareness of the problem created by granting a depletion allowance on a bonus which was not followed by subsequent production.Herring v.Commissioner , 293 U.S. 322 (1934)
A bonus is not proceeds from the sale of property, but payment in advance for oil and gas to be extracted, and is therefore taxable income. As such it is a part of the "gross income from the property" as the phrase is used insection 204(c)(2) to designate the base for the application of the percentage deduction. * * * [293 U.S. 322">293 U.S. 322 , 324, 325.]* * * *
* * * To condition the allowance on actual production, however small, or the imminent probability of production, and to deal in refinements as to the degree of probability of future production, is in many cases to deny any deduction where the taxpayer elects to compute it under
section 204(c)(2) , flat percentage of gross income from the property, and permit it where he elects to *1047 compute it undersection 204(c) , on the basis of cost. But the nature and the purpose of the allowance is the same in both cases, and we find neither statutory authority nor logical justification for withholding it in the one and granting it in the other; much less for making the decision turn upon the circumstance that no production is obtained within the year in which the bonus is paid. [293 U.S. 322">293 U.S. 322 , 327, 328.]Thus, even if we were to *328 assumethat the earlier cases dealing with cost and discovery depletion contained inherent limitations with respect to their applicability to percentage depletion, those limitations were abandoned in
Herring v.Commissioner . While a cash bonus in the hands of the lessor had not previously been subject to depletion in the sense that it had actually entered into the base upon which his depletion allowance was computed but had simply been considered a receipt out of which recovery of the allowance (otherwise computed) was permitted, the Supreme Court inHerring refused to draw such a distinction. Construing its own earlier decision as meaning that the bonus itself was part of the depletion base, and concluding that "the nature and purpose" of the depletion allowance was the same with respect to both cost and percentage depletion, the Court decided that a cash bonus was part of the lessor's base for percentage depletion.It was apparent that the Court recognized that under this approach a serious problem existed with respect to the allowance of depletion when no production ensued. However, it closed its opinion by simply declaring:
As to income tax liability in the year of terminationof *329 the lease, on account of bonus paid at the execution of the lease, if no mineral has then been extracted, we express no opinion. [
293 U.S. 322">293 U.S. 322 , 328.]Previously, in 1927, the Commissioner had ruled in this connection that article 216(a) of Regulations 69 had no application to a bonus received by the lessor of an unproven area and was applicable only to a lease of a property in a proven area where the mineral content was capable of being estimated at the time the bonus was received even though the property was nonproducing at that time.
Herring v.Commissioner, supra This rule, known as the "restoration of depletion rule," was embodied in the applicable regulations as follows:
(c) If for any reason any grant of mineral rights expires or terminates or is abandoned before the mineral which has been paid for in advance has been extracted and removed, the grantor shall adjust his capital account by restoring thereto the depletion deductions made in prior years on account of royalties on mineral paid for but not removed, and a corresponding amount must be returned as income for the year in which such expiration, termination, or abandonment occurs.
Douglas v.Commissioner , 322 U.S. 275">322 U.S. 275 (1944)Sneed v.Commissioner , 119 F. 2d 76740 B.T.A. 1136">40 B.T.A. 1136 (1939);Crabb v.Commissioner , 119 F. 2d 77241 B.T.A. 686">41 B.T.A. 686 (1940).The restoration-of-depletion rule serves to highlight the inherently unreal nature of depletion allowed with respect to a bonus, representing recognition of what would seem obvious, namely, that without extraction of minerals there is no depletion in fact.
Crabb v.Commissioner, supra .*1049 We have found it necessary to trace the development of the law with respect to the taxation of cash bonuses in the hands of the
lessor-payee , because it was within that framework that the Commissioner subsequently was obliged to construct a conforming treatment of such payments in the hands of the lessee-payor. InG.C.M. 22730 ,1 C.B. 216">1941-1 C.B. 216 , as part of a general discussion of issues relating to the acquisition and assignment of interests in oil and mineral properties, the Commissioner declared: *333 in place is a reservoir of the capital investments of the parties returnable through the depletion allowance, and as the bonus payment results in a reduction in the lessor's capital investment to the extent of the depletion allowable thereon, it follows that such payment is a contribution by the lessee to such reservoir of capital investments which is substituted for the capital thereby withdrawn by the lessor. Such shifting of capital investment is attended by a corresponding shift in the value of the respective capital interests or share rights of the parties. That is, a bonus payment diminishes the value of the lessor'smineral interest by reducing his royalty share in future production. The depletion allowance on his bonus income is designed to compensate him for such diminution in value of his interest thereby sustained. Correspondingly, the bonus payment enhances the value of the lessee's interest by giving him a larger share of the minerals produced, or the proceeds therefrom, by reason of his bonus investment.While this rationalization may seem more metaphysical than logical, the difficulty of explaining concepts which were largely artificial in nature *334 was understandable. In any event, this reasoning led to the conclusion embodied in the regulation to the effect that, on the part of the lessee-payor, a bonus payment is "a capital investment in the property recoverable only through the depletion allowance."
Helvering v.Twin Bell Syndicate, supra Kirby Petroleum Co. v.Commissioner , 326 U.S. 599">326 U.S. 599less an allocable portion of the bonus, because otherwise depletion would be allowed on more than the total production. This rule was set forth *1050 in the regulations applicable to the taxable years here at issue as follows: *336 31, 1939, the amount excluded from "gross income from the property" for the current taxable year on account of such payments shall be an amount equal to the deduction for such taxable year taken on account of such payments pursuant to § 29.23(m)-10(e).The treatment of bonuses in the hands of the lessee, as embodied in the various applicable regulations set out above, has been sustained by the courts on several occasions.
Sunray Oil Co. v.Commissioner , 147 F. 2d 9623 T.C. 251">3 T.C. 251 (1944);Canadian River Gas Co. v.Higgins , 151 F. 2d 954Quintana Petroleum Co. v.Commissioner , 143 F. 2d 58844 B.T.A. 624">44 B.T.A. 624 (1941). With respect to the depletion issue, these cases hold that, since decisions of the Supreme Court have long established the right of the lessor to a depletion allowance on a cash bonus, the Commissioner's regulation excluding the same bonus from the lessee's *337 "gross income from the property" must be sustained. Thus, for example, inQuintana Petroleum Co. v.Commissioner, supra 143 F.2d 588">143 F. 2d 588 , 591):
UnderHelvering v. Twin Bell Syndicate, 293 U.S. 312">293 U.S. 312 , 55 S. Ct. 174">55 S. Ct. 174, 79 L. Ed. 383">79 L. Ed. 383, percentage depletion is a single allowance and must be apportioned between lessor and lessee as provided in the Revenue Act. It follows that if the percentage depletion is allowable upon the cash bonus (advance royalty) received by the lessor, such bonus must be deducted from the gross income from production received by the lessee in computing depletion; otherwise double percentage depletion deductions would result contrary to the statute.Helvering v. Twin Bell Syndicate, supra. In the
Quintana Petroleum Co . case just quoted, the taxpayer had not properly raised any issue with respect to the exclusion from taxable income of the bonus and the court refused to consider the question. However, that issue was decided in theSunray Oil Co . andCanadian River Gas Co . cases, the court stating in the former case as follows (147 F.2d 962">147 F. 2d 962 , 966, 967):*1051 The lessee of an oil and gas lease may elect between cost and percentage depletion in a particular tax *338 year. Here, the taxpayer elected to take percentage depletion for each of the taxable years involved. Had it elected to take cost depletion, the bonuses or advance royalties would have been included in the base for cost depletion. But the taxpayer may not have the benefit of both cost and percentage depletion. In effect, the taxpayer here is seeking to recover its original investment in the oil and gas leases by amortizing its cost and deducting a portion thereof from gross income annually in addition to a percentage depletion allowance. There is no statutory basis for such a deduction where percentage depletion has been taken. In such a case, the investment can only be recovered through the percentage depletion allowance. To hold otherwise would result in a double depletion allowance. [Footnotes omitted.]
The reasoning of the court in the
Canadian River Gas Co . case was similar.As we have seen, as long ago as 1934, the Supreme Court flatly held a cash bonus to be part of the lessor's "gross income from the property" and, thus, part of his base for percentage depletion.
Herring v.Commissioner, supra .Harmel , the Supreme *340 Court rejected the lessor's attempt to treat cash bonuses as capital gains, efforts have been made by lessees to have the courts reject the respondent's regulations treating such bonuses as capital investments in the hands of the payor. However, the courts have sustained the regulations, refusing to find any fatal inconsistency in the treatment of a bonus as ordinary income to the payee, on the one hand, and as a capital investment to the payor, on the other. *1052 thesale of his product is ordinary income (to the extent it exceeds his cost of goods sold) while to the purchaser it represents a capital investment. Perhaps an even more apposite example would be that of a bonus in the case of the execution of the ordinary real estate lease. While such bonuses are taxable to the lessor when received or accrued, they are not deductible as expenses by the lessee but are considered capital expenditures. *341Of course, the fact that a particular expenditure is classified as capital in nature does not preclude its recovery for tax purposes but generally prevents its deduction in full in the year of payment. For example, in the case of the ordinary real estate lease bonus just referred to, the lessee amortizes his bonus payment over the life of the lease involved. In the instant case, as we have seen, the cash bonus with respect to an oil and gas lease is "a capital investment to be recovered through the depletion allowance."
In the
Sunray Oil Co . andCanadian River Gas Co . cases, the courts rationalized this result on the ground that, since the lessee's basis forcost depletion *342 includes the amount of a bonus, any additional exclusion by way of deduction of a portion of the bonus annually, would be tantamountto a double depletion allowance. Since this reasoning could only be applicable to cost depletion, the courts considered the two allowances, i.e., cost and percentage, as being elective alternatives, so that when a taxpayer exercised his "option" to take percentage depletion he could not then complain when he was denied the benefits of cost depletion. *1053 of the cost basis of the property.United States v.Dakota-Montana Oil Co ., 288 U.S. 459">288 U.S. 459So-called "geological and geophysical exploration expenditures" must be capitalized, with no expensing option available.
Louisiana Land & Exploration Co ., 7 T.C. 507 (1946)161 F. 2d 842 (C.A. 5, 1947);1 C.B. 48">1950-1 C.B. 48 . Here, too, there is no adjustment of the base for percentage depletion.Finally, where the taxpayer exercises his option *344 to expense intangible drilling costs, there again is no reduction of the base for percentage depletion, Sunray Oil Co. and
Canadian River Gas Co . cases, should a deduction by a lessee of an annual portion of a cash bonus be permitted. Perhaps the most that can be deduced from these various rules is that the taxation of oil and gas is a practical matter, not governed entirely by considerations of theoretical *345 logic.More recently, an entirely different approach to the problem (the exclusion of the bonus, or a portion thereof, from income subject to tax) was taken by the Court of Appeals for the Fifth Circuit in
Lambert v.Jefferson Lake Sulphur Company , 236 F. 2d 542Burton-Sutton Oil Co. v.Commissioner, supra It is apparent from a reading of the opinion, including that of the trial court, Lambert v.
Jefferson Lake Sulphur Company case and the case at bar, the principles upon which the former was decided are of considerable significance here and are pressed upon us by petitioner as supporting its contentions.In the
Jefferson Lake Sulphur Company case, the Government contended that the payments in question were bonuses and *347 recoverable only through depletion. Since on this aspect of its decision, the Court of Appeals adopted by reference the grounds' stated by the District Court, it is necessary to refer to the latter's opinion. The District Court stated that the payments in question "were depletable as advanceroyalties by the lessor," citingBankers' Pocahontas Coal Co. v.Burnet , 287 U.S. 308">287 U.S. 308Burnet v.Harmel, Murphy Oil Co. v.Burnet , andPalmer v.Bender , allsupra . From this premise the court concluded that those same payments "should be excludable as such [advance royalties] by the lessee," on the authority ofBurton-Sutton Oil Co. v.Commissioner, supra .Sunray Oil Co., Canadian River Gas Co ., andQuintana Petroleum Co . cases, but considered their authority to have been superseded by the more recent Supreme Court decision inBurton-Sutton .The latter case had involved the tax treatment of a lease payment when that payment took the form of a share of net profits. The Supreme Court declared, in part, as follows:
A decision on the category of expenditures to which these 50% disbursements belong affects *348 both the operators who make them and the owners, lessors, vendors, grantors, however they may be classed, who received them.
If they are capital *1055 investments to one, they are capital sales to the other. If they are rents or royalties paid out to one, they are rents or royalties received by the other . * * * [Emphasis added.]* * * *
* * * We do not agree with the Government that ownership of a royalty or other economic interest in addition to the right to net profits is essential to make the possessor of a right to a share of the net profit the owner of an economic interest in the oil in place. * * *
* * * *
* * * As the oil is extracted and sold that economic interest in the oil in place is reduced and the holder or owner of the interest is entitled to his equitable proportion of the depletion as rent or royalty. The operator, of course, may deduct such payments from the gross receipts. Burton-Sutton is readily distinguishable from
Lambert v.Jefferson Lake Sulphur Company , a fact recognized in the opinion of theDistrict Court in the latter *349 case, and, at the least, equally distinguishable from the case at bar. Nevertheless, in reaching its decision, the District Court placed primary reliance upon the language italicized in the above quotation. Advance royalties, like current royalties, are excluded from the lessee's taxable income. Therefore, reasoned the court, if the payments in question were includible in the lessor's income (and depletable) as advance royalties, it necessarily followed, under the declaration contained inBurton-Sutton , that they were advance royalties to the lessee and as such deductible in their entirety in the year paid. Burton-Sutton, the issue before the Court was whether the possessor of a right to a percentage of net profits was the owner of an economic interest in the oil in place. It is not *350 clear what part, if any, the statement in question played in the resolution of that issue. At best, it would seem declaratory of the Court's insistence that it was the substance of the interests involved, and not the mere labels attached to them, that determine the nature of the respective rights.As we have mentioned, the District Court in
Jefferson Lake Sulphur Company citedBurnet v.Harmel, Bankers' Pocahontas Coal Co. v.Burnet, Murphy Oil Co. v.Burnet , andPalmer v.Bender , allsupra , as authority for the proposition that a bonus is an advance royalty in the hands of the lessor. It must be conceded that bonuses frequently have been described in such terms by the courts and by writers in general. *1056 that the labeling of bonuses as "advance royalties" has been more fortuitous than otherwise. For example, the opinion inBurnet v.Harmel contains no reference, either direct or indirect, to advance royalties.Bankers' Pocahontas Coal Co. v.Burnet uses the phrase "advanced payments of royalties" only in reference to evidence which the trial court had refused to consider. InMurphy Oil Co. v.Burnet the words "advance *351 royalties" do not appear and the only phrase which might be so interpreted is a reference to "payments in advance of royalties," an entirely different matter. The significance of that phrase lies in the fact, as pointed out above, that the Court was concerned in the pre-1926 cases with thetiming of depletion recovery, and considered postponement of depletion deductions a hardship when there were payments in advance of royalties available for the recovery of the allowance. The fourth case cited,Palmer v.Bender , contains no reference to advance royalties, either directly or indirectly.In
Herring v.Commissioner, supra Anderson v.Helvering, supra
Cash bonus payments, when included in a royalty lease, are regarded as advance royalties, and are given the same tax consequences. Anderson v.Helvering did not hold (as it could not since the issue was not involved) that bonuses *352 were excludible or deductible by the payor in determining net income, as is here contended. No such allowance was in effect at the time of the decision or had been permitted under regulations or administrative practice during all the years prior thereto; nor has such an exclusion or deduction been allowed in the 20 years since the decision. Therefore, when the Court indicated that a cash bonus is given the same tax consequences as an advance royalty it could only have meant with respect to the depletion allowance.The various applicable regulations have never considered bonuses to be advance royalties and have referred to each separately. In
G.C.M. 22730 ,supra , from which we have already quoted at some length, the Commissioner declared specifically: "A cash bonus, though termed an advance royalty payment, paid to a lessor without regard to production and often in a year when there is no production, is not a division of products or proceeds therefrom. * * *"Therefore, while references to bonuses as "advance royalties" are not lacking in the cases, the authority for such terminology, including in particular those very cases to which reference for such authority *353 is most commonly made, is far from clear. It is difficult not to conclude that the frame of reference grew up in response to the need for *1057 at least a semantic rationalization for a tax treatment which was otherwise lacking in logical basis. Certainly, whatever tendency there may have been in the cases to refer to a bonus as an "advance royalty," it seems clear that a bonus is not a royalty at all. Payable in any event, irrespective of production, it fits none of the accepted definitions of a "royalty" as representing"a share of the product or profit."
J. T. Sneed, Jr., supra .Under these circumstances, we cannot accept the petitioner's argument that the broad generalization represented by the two sentences of the
Burton-Sutton opinion, handed down some 15 years ago, can form the basis now for overturning court decisions and regulations of many years' standing, particularly when, as we have pointed out, the specific issue here was not before the Court inBurton-Sutton and when, indeed, the significance of the language in question to that decision is far from clear. Furthermore, it appears to us that the whole philosophy underlying the Supreme Court's decision inBurton-Sutton was *354 that substance and not form should govern the determination of the nature of mineral interests and the tax consequences which should flow therefrom. To seize upon the use of the phrase "advance royalties" with reference to bonuses as somehow requiring the conversion into a deductible expense of the lessee of what has been treated without exception over the years as a capital investment, would seem to be contrary to the basic principle of that decision.With the advantage ofmany years' hindsight, we might agree readily that a bonus should not enter into the lessor's percentage depletion base, that the lessee's "gross income from the property" should remain unaffected by reason of such a bonus payment, and that, finally, the amount of the bonus should be a capital investment recoverable only through the depletion allowance (this last, of course, being the treatment actually accorded). To discard the latter treatment as a nondeductible capital expense for the sake of theoretical conformity with the treatment for depletion purposes would be to eliminate the only aspect of the taxation of bonuses which would seem to possess a logical foundation.
As an alternative to the deduction or exclusion *355 in full in the year paid or incurred permitted by the court in
Lambert v.Jefferson Lake Sulphur Company, supra *1058 Whatever form of deduction or exclusion of a bonus from the gross income of the payor is contended for by the petitioner, it is plainly contrary to the regulations. Certainly, the statute itself contains no provision for such a deduction or exclusion. It is well established that deductions are a matter of legislative grace; and that only as there is clear provision therefor can any particular deduction be allowed. Thus, a taxpayer seeking a deduction must be able to point to an applicable statute and show that he comes within its terms.
New Colonial Co. v.Helvering , 292 U.S. 435">292 U.S. 435The regulatory treatment which the petitioner would have us overturn has been continued in effect without change since the regulations promulgated under the Revenue Act of 1926, that is to say since the allowance of percentage depletion was first provided. That bonus payments are recoverable by the lessee only through the depletionallowance was reiterated in
Treasury Regulations 111 ,Treasury Regulations 118 , *357 to make rules and regulations in this entire area.Canadian River Gas Co. v.Higgins, supra Baton Coal Co. v.Commissioner , 51 F. 2d 469Quintana Petroleum Co. v.Commissioner, Sunray Oil Co. v.Commissioner . WhileBurton-Sutton was decided by the Supreme Court subsequent to those decisions, the rule in question was restated inTreasury Regulations 118 and in Income Tax Regulations, both of which were *1059 promulgated a number of years after the decision inBurton-Sutton . To hold otherwise now, would be to ignore the fact that *358 Congress has reposed the regulatory authority in the Secretary of the Treasuryor his delegate (previously the Commissioner of Internal Revenue) and not in the courts.Illogical the tax treatment of bonus payments may well be; perplexing it certainly is. However, whatever its infirmities, it is firmly imbedded in the practices of the oil and gas industry, a part of the established framework within which leases are acquired and bonuses negotiated. If the practice of years is to be changed, it would seem desirable that such change be considered in the light of all the complex interrelationships involved. Such a consideration of the problem could most suitably be given by the Congress itself.
The various overpayments claimed by the petitioner by virtue of its several alternative contentions with respect to the bonus issue are disallowed.
Decisions will be entered under Rule 50 .Footnotes
1. A property unit may consist of one or more leasehold interests.↩
2.
Sec. 204(c)(2) of the Revenue Act of 1926, 44 Stat. 16. For the legislative history of percentage depletion, see Austin, "Percentage Depletion: Its Background and Legislative History," 21 Kan. City L. Rev. 22 (1952).See also Regs. 69, art. 201, 1602 (1926); Regs. 74, art. 221(i) (1931); Regs. 77, art. 221 (1933); Regs. 86, art. 23(m)-1 (1935); Regs. 94, art. 23(m)-1(g) (1936); Regs. 101, art. 23(m)-1(g) (1939); Regs. 103, sec. 19.23(m)-1(f) (1940); Regs. 111, sec. 29.23(m)-1(f) (1943); Regs. 118, sec. 39.23(m)-1(e)(1) (1953).↩
1. Regs. 111, sec. 29.23(m)-1(f), for the period through December 31, 1951, and Regs. 118, sec. 39.23(m)-1(e)(1) and sec. 39.23(m)-1(e)(2).↩
3. See footnote 1,
supra↩ .4. Cf.
Sartor v.United Gas Public Service Co ., 186 La. 555">186 La. 555value↩ of such gas." (Emphasis added.) It was the opinion of the Supreme Court of Louisiana that "Where there is no stipulation to the contrary in a lease contract of this kind, 'market value' is understood to mean the current market price paid for gas at the well or in the field where it is produced."5. See the dictum of the United States Supreme Court in
Sartor v.Arkansas Gas Corp ., 321 U.S. 620">321 U.S. 620"The Court of Appeals, correctly we think, followed the Louisiana substantive rule that the inquiry in a case of this kind shall determine (1) the market price at the well, or (2) if there is no market price at the well for the gas, what it is actually worth there, and 'in determining this actual value * * * every factor properly bearing upon its establishment should be taken into consideration. Included in these are the fixed royalties obtaining in the leases in the field considered in the light of their respective dates, the prices paid under the pipeline contracts, and what elements, besides the value as such of the gas, were included in those prices, the conditions existing when they were made, and any changes of conditions, the end and aim of the whole inquiry, where there was no market price at the well, being to ascertain, upon a fair consideration of all relevant factors, the fair value at the well of the gas produced and sold by defendant.'"
6.
140 F. 2d at 410 . See alsoContinental Oil Co. v.United States , 184 F. 2d 802, 817↩7. In that case the royalty provision in the lease read as follows: "If any well on said premises shall produce natural gas in paying quantities, and such natural gas is
used off the premises or marketed by lessee , then lessor shall be paid at the rate of one-eighthof the net proceeds derived from the sale of gas at mouth of well . * * *" Referring to the royalty the court said: "As to it there is no mention of either market price or market value, or a fixed price, but ofnet proceeds , which generally means the receipts, less expenses, of an actual sale. * * * There were no net proceeds derived at the mouth of the well. But if the raw gas had been sold at a market off the premises, the net proceeds at the mouth of the well might well mean the actual proceeds less the expense of transportation. * * *"* * * In so far as the gas was 'marketed' we think the stipulation for a share of the 'net proceeds derived' ought to be enforced, effect being given to the words 'net at the mouth of the well' by allowing as expense the cost of transporting, separating, and marketing. * * *" (
155 F. 2d at 188, 189↩ .)8. See
Stephens County v.Mid-Kansas Oil & Gas Co ., 113 Tex. 160">113 Tex. 160Tidewater Associated Oil Co. v.Clemens , 123 S.W. 2d 780Phillips Petroleum Co. v.Bynum , 196">155 F. 2d 1969. The amount of the tax saving will depend on the extent of the royalty interest. In a one-eighth royalty an additional payment of 1 cent per MCF would increase the "gross income from the property" in the amount of 7 cents, increase the depletion allowance by 27 1/2 percent of 7 cents, or 1.925 cents, and at a tax rate of 52 percent result in a tax saving of 1.001 cent from which the additional payment of 1 cent must be subtracted to arrive at the net benefit. Furthermore, any increase in the royalty payment must be examined with a view to the percentage depletion limitation of 50 percent of the net income from the property.
10.
56 F. 2d 153↩ (C.A. 5, 1932).11. See also
Bankers' Pocahontas Coal Co. v.Burnet , 287 U.S. 308↩ (1932)12. Revenue Act of 1926,
sec. 204(c)(2)↩ . The Act made the depletion provisions effective as of January 1, 1925, sec. 286.13. Therein the Court said: "the lessor's right to a depletion allowance does not depend upon his retention of ownership or any other particular form of legal interest in the mineral content of the land. It is enough if, by virtue of the leasing transaction, he has retained a right to share in the oil produced. If so he has an economic interest in the oil, in place, which is depleted by production. Thus, we have recently held that the lessor is entitled to a depletion allowance on bonus and royalties, although by the local law ownership of the minerals, in place, passed from the lessor upon the execution of the lease. * * *" (
287 U.S. at 557↩ .)14. In this case the Court said: "The holder of a royalty interest -- that is, a right to receive a specified percentage of all oil and gas produced during the term of the lease -- is deemed to have 'an economic interest' in the oil in place which is depleted by severance. * * * [Citations omitted.] Cash bonus payments, when included in a royalty lease, are regarded as advance royalties, and are given the same tax consequences. * * *" (Citations omitted.
310 U.S. at 409↩ .)15. See
328 U.S. at 32, 33 , where the Court said:"It seems generally accepted that it is the owner of a capital investment or economic interest in the oil in place who is entitled to the depletion.
Anderson v.Helvering , 310 U.S. 404">310 U.S. 404Euleon Jock Gracey , 5 T.C. 296">5 T.C. 296Kirby Petroleum Co. v.Commissioner, supra .Palmer v.Bender , 287 U.S. 551">287 U.S. 551Helvering v.Twin Bell Syndicate , 293 U.S. 312">293 U.S. 312Burnet v.Harmel , 287 U.S. 103">287 U.S. 103Murphy Oil Co. v.Burnet , 287 U.S. 299">287 U.S. 29916. Regs. 45 (1920 ed.), art. 215(a), under Revenue Act of 1918; Regs. 62 (1922 ed.), art. 215(a), under Revenue Act of 1921; Regs. 65, art. 216(a), under Revenue Act of 1924.
17. See footnote 12,
supra↩ .18.
19 B.T.A. 376">19 B.T.A. 376↩ (1930).19.
56 F. 2d 153↩ (1932) .20.
T.D. 3938 ,V-2 C.B. 117 (1926) ↩; Regs. 69, art. 216(a), under Revenue Act of 1926.21. See footnote 16,
supra↩ .22.
XII-1 C.B. 64 (1933) , revoked byG.C.M. 14448 ,XIV-1 C.B. 98 (1935) ↩.23. See Baker, "The Nature of Depletable Income,"
7 Tax L. Rev. 267">7 Tax L. Rev. 267 , 274↩ (1952).24.
I.T. 2361 ,VI-1 C.B. 73 (1927) ↩.25.
G.C.M. 14448 ,XIV-1 C.B. 98 (1935) ↩.26. Regs. 111, sec. 29.23(m)-10(c); Regs. 118, sec. 39.23(m)-10(c).↩
27. The Court in
Driscoll v.Commissioner , 147 F. 2d 493↩28.
1 C.B. 214">1941-1 C.B. 214↩ , 217.29. Regs. 111, sec. 29.23(m)-10(a); Regs. 118, sec. 39.23(m)-10(a); sec. 1.612-3(a)(3). Income Tax Regs.↩
30. Regs. 111, sec. 29.23(m)-1(f)(4); Regs. 118, sec. 39.23(m)-1(e)(5). The two regulations are identical. The regulations promulgated under the 1954 Code (sec. 1.613-2(c)(5) (ii) refer to "bonus payments" rather than to "royalties in the form of bonus payments."↩
31.
Sec. 23(m), I.R.C. 1939 ;sec. 611(b)(1), I.R.C. 1954↩ .33.
Sunray Oil Co. v.Commissioner , 147 F. 2d 962Canadian River Gas Co. v.Higgins , 151 F. 2d 954↩34. See 2 Mertens, Law of Federal Income Taxation, sec. 12.31; id. at vol. 4, sec. 25, 27; and cases cited therein.
35. See footnote 29.↩
36. See
sec. 114(b)(3) ,1939 ↩ Code; sec. 613(a), 1954 Code.37. In general, these costs include those for clearing the site of the well, digging a sludge pit, hauling, erecting derricks, laying lines for water, and the wages, fuel, repairs, etc., necessary for actually drilling the well. Mertens, op. cit.
supra↩ , vol. 4, sec. 24.48b; Regs. 118, sec. 39.23(m)-16(a)(1).38. For example, Regs. 118, sec. 39.23(m)-16(b)(1).↩
39. In the case of such an election to expense, the regulations do provide that the deductions must be taken into account in computing net income from the property for purposes of the 50 percent of net income limitation on the depletion allowance. Regs. 118, sec. 39.23(m)-1(g);
sec. 1.614-4, Income Tax Regs.↩ 40. Deductible in full under
section 23(a)(1)(A)↩ of the 1939 Code as ordinary and necessary business expenses.41.
133 F. Supp. 197">133 F. Supp. 197↩ (1955).42. The quotation is a composite of language appearing on pages 27, 32, and 35 of 328 U.S.↩
43. If the payment is to be treated in all events as an advance royalty to the lessee, other results not considered in the
Jefferson Lake Sulphur Company , (236 F. 2d 542↩44. This Court is no exception. For example, see
Westates Petroleum Co ., 21 T.C. 35">21 T.C. 3545. See footnote 14,
supra↩ .46. Sec. 29.23(m)-10(a). These regulations were promulgated subsequent to the enactment of the Internal Revenue Code of 1939 which included a reenactment, as part of the general codification, of the then-applicable depletion provisions.↩
47. Sec. 39.23(m)-10(a).↩
48. Sec. 1.612-3(a)(3). These regulations were promulgated subsequent to enactment of the Internal Revenue Code of 1954.↩
49.
Sec. 23(m) ,1939 Code;sec. 611 ,1954 ↩ Code.50. The Fifth Circuit may have overruled
Quintana in its more recentJefferson Lake Sulphur Company↩ case.
Document Info
Docket Number： Docket Nos. 49145, 61315, 68580, 77791
Citation Numbers： 35 T.C. 979, 1961 U.S. Tax Ct. LEXIS 198, 13 Oil & Gas Rep. 1090
Judges： Train
Filed Date： 3/24/1961
Precedential Status： Precedential
Modified Date： 10/19/2024