Court Opinion

ID: 4619514
Source: CourtListenerOpinion
Date Created: 2020-11-21 02:40:47.106254+00
Date Added: 2024-06-11T07:55:39.552804
License: Public Domain

The Shamrock Oil and Gas Corporation, Petitioner, v. Commissioner of Internal Revenue, RespondentShamrock Oil & Gas Corp. v. CommissionerDocket Nos. 49145, 61315, 68580, 77791United States Tax Court35 T.C. 979; 1961 U.S. Tax Ct. LEXIS 198; 13 Oil & Gas Rep. 1090; March 24, 1961, Filed *198 Decisions 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., and Ed H. Selecman, Esq., for the petitioner.Roy E. Graham, Esq., and Allen 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 (orDeficiency inFiscal year ended Nov. 30 --Docket No.overassessment)excess profitsin income taxtax194349145$ 8,275.66 $ 242,520.761944491451,625.87 61,139.20194549145(9,205.72)80,655.0819464914515,434.98 5,112.8219474914528,010.94 194861315207,474.99 194961315236,827.51 195061315275,399.99 195168580268,247.74 195268580277,543.20 195377791348,770.37 195477791479,017.43 *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 onFinally allowedreturn1943$ 398,550.58$ 402,258.981944334,916.17351,466.081945369,307.99377,784.801946633,938.45633,938.451947727,438.54727,438.54 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$ 0.0284971944.0298951945.0313141946.0364681947.051986This 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 incomePercentageOverpaymentfrom thedepletionproperty1943$ 1,140,878.52$ 313,741.59$ 158,018.9819441,663,055.48457,340.26255,116.4919452,555,600.60702,790.16207,671.4319462,928,683.45805,387.95125,105.3719473,662,165.941,007,095.63181,520.19Shamrock 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$ 1,198,171.6519441,336,266.3519451,797,581.4019462,588,789.7519473,766,485.54Docket 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$ 1,438,862.7619491,784,807.9519501,739,701.7719511,776,849.8119521,725,296.8119531,986,442.3619542,687,770.27*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$ 427,905.151949481,257.891950397,392.971951303,757.971952229,111.411953303,286.931954507,592.57The 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:  Gas1948194919501951Sweet$ 0.043602$ 0.044427$ 0.043898$ 0.049699Sour.041425.041323.041861.048224Casinghead.039497.031852.031187.039618Weighted average.041876.041106.040681.047353Gas195219531954Sweet$ 0.054298$ 0.062649$ 0.072486Sour.055060.054893.061690Casinghead.050746.051306.048840Weighted Average.054181.055800.061317Shamrock, *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$ 23,065.45194933,473.60195073,972.511951131,877.661952153,224.351953132,994.751954113,831.99Shamrock contends that the gross income from the property at the wellhead, for depletion purposes, in terms of price per MCF, was as follows:1948$ 0.0810031949.0677851950.0626561951.0707631952.0721861953.0793131954.087243 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 incomePercentageOverpaymentdepletion1948$ 4,431,021.85$ 1,218,531.01$ 23,065.4519495,341,355.761,468,872.8333,473.6019505,494,012.741,510,853.5073,972.5119515,973,652.201,642,754.35131,877.6619525,874,591.441,615,512.65153,224.3519536,348,503.201,745,838.00132,994.7519547,132,385.491,961,406.01113,831.99 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$ 6,112,670.5219497,367,760.8619507,235,829.7919517,625,687.7119527,569,782.9319537,505,966.8419548,987,914.26II. *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 amountFirst Contention:deductibleOverpayment1948$ 276,441.11$ 105,047.621949177,630.3167,499.511950287,024.73117,479.22195130,266.2015,201.201952168,728.1987,738.661953302,237.68157,163.591954408,387.75212,361.63Proportionate amountSecond Contention:deductibleOverpayment1948$ 17,006.30$ 6,462.43194918,331.856,966.10195019,920.908,153.62195121,713.4110,905.56195224,532.0112,756.95195328,829.1214,991.14195433,756.1517,553.20Amount deductedfrom "gross incomefrom the property"Third Contention:Capital investment(allocate part)1948$ 276,441.11$ 17,006.391949177,630.3118,331.851950287,024.7319,920.90195130,266.2021,713.411952168,728.1924,532.011953302,237.6828,829.121954408,387.7533,756.15Loss in percentageThird Contention:depletion allowanceOverpayment1948$ 4,676.76$ 1,777.1719495,041.26  1,915.6819505,478.25  2,242.2519515,971.18  2,999.0319526,746.30  3,508.0719536,003.01  2,375.1319549,282.94  4,827.13Theissues 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 gasSweet gasCasingheadpropertypropertygas propertyleasesleasesleases1926301192771192811929119305319312193219331193413193525193640153193721111193871619391111940151119418511942551194341619442512311945371221946121511947161291948951019493611950319511195211195323195411 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:Shamrock's Producing and Nonproducing Gas Lease Acreage in Moore, Hutchinson,Sherman, Dallam, Hansford, and Hartley Counties at End of FiscalYears 1944 Through 1954.County194419451946194719481949Moore:Producing24,725.1643,328.5951,194.1254,303.3753,030.5256,687.19Nonproducing35,578.6420,567.5723,983.9126,750.1433,425.5829,665.85Hutchinson:Producing2,195.362,195.362,195.362,845.604,118.104,627.36Nonproducing805.51805.51805.513,835.274,831.515,522.25Sherman:Producing9,960.3323,133.0928,713.92Nonproducing63,956.8970,267.2171,193.2163,153.2746,133.3341,687.76Dallam:Producing213.00213.00Nonproducing21,843.3320,296.3324,719.2052,750.6271,961.4171,996.63Hansford:ProducingNonproducing1,028.001,028.001,319.82Hartley:ProducingNonproducing2,150.382,154.01*221 Shamrock's Producing and Nonproducing Gas Lease Acreage in Moore, Hutchinson,Sherman, Dallam, Hansford, and Hartley Counties at End of FiscalYears 1944 Through 1954.County19501951195219531954Moore:Producing59,575.2665,422.8572,821.3377,828.6184,005.75Nonproducing26,910.4921,132.9114,457.0910,141.434,861.42Hutchinson:Producing4,950.874,950.875,110.877,980.878,160.87Nonproducing5,548.855,548.855,548.855,568.855,388.85Sherman:Producing32,560.7249,015.4458,409.7465,818.1169,156.56Nonproducing36,792.1117,568.898,616.834,535.747,445.34Dallam:Producing213.00213.00415.48415.48415.48Nonproducing73,521.3169,158.8165,072.4564,272.4563,572.16Hansford:Producing291.82291.82291.82Nonproducing1,560.761,560.761,268.941,268.945,508.94Hartley:Producing437.50Nonproducing8,348.458,348.4522,707.4822,707.4822,266.35*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:1 Number of Property Units, in Terms of Acreage, on Which Shamrock HadLeasehold InterestsAcres0-200201-400401-600601-800Sour23231174Sweet497108Casinghead97141 Number of Property Units, in Terms of Acreage, on Which Shamrock HadLeasehold InterestsAcres801-1,0001,001-1,2001,200-1,4001,401-1,600Sour111Sweet2Casinghead1 Number of Property Units, in Terms of Acreage, on Which Shamrock HadLeasehold InterestsAcres1,601-1,8001,801-2,0002,001-2,5002,501-3,000Sour221SweetCasinghead1 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 gasSweet gasCasingheadgas19303193111932193321934519354193614193773193831193931194031941511942511943219443319452591946512194781931948316319491154195049219519281195214141953125195468119551The number of properties from which gas was produced *223 in the years in issue was as follows:Sour gasSweet gasCasingheadTotalpropertiespropertiesgaspropertiesproperties19434735019444755219456977619467814921947872561181948903810138194910042131551950103471416419511075914180195212066152011953123682221319541267623225The 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 Number of Shamrock Wholly or Partially Owned Wells in West Panhandleand Hugoton Gas Fields Connected to McKee and Sunray Plantsat End of Fiscal Years 1943 Through 1954 and Distances of Such WellsFrom Said PlantsNumber ofNumber ofwells connectedwell connectedto McKeeto Sunray(M) Plant(S) Plant1943West Panhandle gasfield58Hugoton gasfield1944West Panhandle gasfield61Hugoton gasfield1945West Panhandle gasfield91Hugoton gasfield1946West Panhandle gasfield108Hugoton gasfield1947West Panhandle gasfield10516Hugoton gasfield171948West Panhandle gasfield10618Hugoton gasfield451949West Panhandle gasfield11219Hugoton gasfield541950West Panhandle gasfield11419Hugoton gasfield631951West Panhandle gasfield11719Hugoton gasfield1021952West Panhandle gasfield12122Hugoton gasfield1231953West Panhandle gasfield13229Hugoton gasfield1261954West Panhandle gasfield13629Hugoton gasfield134*224 Number of Shamrock Wholly or Partially Owned Wells in West Panhandleand Hugoton Gas Fields Connected to McKee and Sunray Plantsat End of Fiscal Years 1943 Through 1954 and Distances of Such WellsFrom Said PlantsLocation of wells in relation to plants -- miles fromrespective plants0-55-1010-1515-2020-2525-30MSMSMSMSMSMS1943West Panhandlegasfield 391432Hugoton gasfield1944West Panhandlegasfield 391552Hugoton gasfield1945West Panhandlegasfield 4323187Hugoton gasfield1946West Panhandlegasfield 462526101Hugoton gasfield1947West Panhandlegasfield 54718325671Hugoton gasfield42741948West Panhandlegasfield 547174276711Hugoton gasfield73201411949West Panhandlegasfield 587184286721Hugoton gasfield193201921950West Panhandlegasfield 607184285731Hugoton gasfield2113202161951West Panhandlegasfield 63718428731Hugoton gasfield3287342461952West Panhandlegasfield 647215286741Hugoton gasfield3348482461953West Panhandlegasfield 671026530107411Hugoton gasfield3359492461954West Panhandlegasfield 671029631107311Hugoton gasfield3371251247*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 aLeasehold InterestNumber ofTotalShamrock'sFiscal year and type of propertyproducingproductionvolumepropertiesinterest1943Sour4742,797,84633,152,426Sweet35,573,5524,876,858Casinghead1944Sour4746,713,86636,185,839Sweet56,160,6255,390,548Casinghead1945Sour6957,716,23645,690,510Sweet76,362,1105,421,502Casinghead1946Sour7863,472,38951,416,735Sweet148,693,0187,156,934Casinghead1947Sour8759,947,04248,518,539Sweet2514,949,75912,435,818Casinghead694,01081,7421948Sour9063,172,93149,934,823Sweet3822,515,17117,631,858Casinghead10701,449602,8861949Sour10080,943,21064,106,207Sweet4221,982,24117,000,100Casinghead131,242,6701,068,3971950Sour10381,087,86863,917,913Sweet4724,788,53319,395,429Casinghead141,408,3231,209,9311951Sour10774,032,63756,825,870Sweet5927,285,42121,438,800Casinghead141,608,7201,384,0261952Sour12064,116,72449,666,349Sweet6627,987,22321,967,801Casinghead152,080,2051,798,2431953Sour12364,347,81749,508,315Sweet6827,623,26821,704,621Casinghead226,866,0513,475,3371954Sour12660,441,14246,712,381Sweet7628,129,49522,134,537Casinghead2311,227,7756,230,824*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 YearsEnded Nov. 30, 1943 Through 1954SourSweetCasingheadOverridingTotalroyalty19435,274,576696,695720,3716,691,64219445,758,630410,295759,7196,928,64419457,043,161514,306756,4398,313,90619467,513,079701,681476,9048,691,66419477,367,1591,654,17312,300597,2929,630,92419487,784,4032,512,72389,119849,93811,236,183194910,519,8092,470,371158,604822,95713,971,741195010,491,6012,791,679176,039765,74614,225,06519519,148,1123,073,141200,691869,05513,090,99919527,932,0373,144,324260,019830,97312,167,35319537,826,5023,124,9391,021,5551,237,99913,210,99519547,384,6253,192,8321,796,7341,584,51313,958,704 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 FiscalYears 1943 to 1954 InclusiveSour GasMCFAmountPrice perMCF19435,274,576$ 57,880.20$ 0.010973 19445,758,63066,778.67.011596319457,043,161108,427.12.015395 19467,513,079226,111.98.030096 19477,367,159231,683.26.031448 19487,784,403306,557.16.039381 194910,519,809422,757.35.040187 195010,491,601464,238.53.044249 19519,148,112453,864.36.049613 19527,932,037477,216.71.056381 19537,826,502447,982.81.061072 19547,384,625488,689.86.066177 Sweet Gas1943696,6959,736.28.0139751944410,29512,299.87.0299781945514,30617,643.08.0343051946701,68124,624.77.03509419471,654,17360,646.72.03686919482,512,723110,391.37.04393319492,470,371109,662.33.04439119502,791,679138,838.43.04973319513,073,141171,911.65.05594019523,144,324194,605.56.06189119533,124,939207,755.09.06648319543,192,832228,882.40.071686Casinghead Gas194712,300369.05.030004194889,1193,243.95.0364001949158,6045,092.92.0321111950176,0395,335.43.0303081951200,6916,377.08.0317761952260,0198,986.77.03456219531,021,55548,477.06.04745419541,796,73482,795.45.046081*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 FiscalYears 1943 to 1954 InclusiveOverriding RoyaltiesSourSweetMCFAmountPrice perMCFAmountPrice perMCFMCF1943720,371$ 7,936.40$ 0.0110171944759,7198,822.11.0116121945756,4399,383.18.0124041946469,7768,520.39.0181377,128$ 254.72$ 0.03574 1947433,26913,358.12.030831163,5055,842.31.0357321948554,70421,185.85.038193284,35111,246.67.0395521949564,72018,296.85.032400234,2648,677.27.0370411950482,85616,705.67.034598260,54111,932.37.0457981951525,98422,427.93.042640322,48717,693.55.0548661952484,39422,611.87.046681324,63919,442.61.0598901953675,28035,180.08.052097307,10919,967.72.0650181954766,21547,401.81.061865316,78022,250.81.070241Schedule of Gas Royalties Paid by Shamrockto Royalty Owners for FiscalYears 1943 to 1954 InclusiveOverriding RoyaltiesCasingheadMCFAmountPrice perMCF19431944194519461947518$ 15.54$ 0.030000194810,883501.32.046065194923,973792.34.033051195022,349675.84.030240195120,584666.42.032376195221,940759.94.0346371953255,61012,250.47.0479261954501,51823,231.18.046322 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 FromWorking Interest of Others inShamrock Leases for Years Ended No. 30, 1943Through 1954, InclusiveNumber ofVolume --contractsMCF 14.65PSIA194353,575,339194453,930,223194574,156,4291946104,128,787194782,919,3621948154,233,0921949206,481,5731950217,598,3201951217,200,0891952215,907,0401953215,571,2771954204,994,952The 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 Schedule of Gas Purchased From Working Interest of Others inShamrock Leases 1943-1954 in Terms of MCF and Price per MCF19431944Purchased from --Type ofgasVolumePriceVolumePriceH. C. Fownes IISour400,058$ 0.010957445,880$ 0.011726Warren Oil Corp., Dye,do  1,749,668.0110951,869,367.011857Solow, Cornell & King.  E. B. Clarkdo  350,047.010917443,852.011620Phillips Petroleum Codo  423,304.011072442,334.011662Magnolia Petroleum Codo  Magnolia Petroleum CoSweetShell Oil Codo  Sinclair Oil & GasSourMagnolia Petroleum Codo  E. W. MeansSweetE. W. Meansdo  Dave RubinSourSinclair Oil & Gas CoSweetSmith & Fowlstondo  Continental Oil CoSour652,262.010738728,790.011205Shell-Sinclairdo  Texas Companydo *231 Schedule of Gas Purchased From Working Interest of Others inShamrock Leases 1943-1954 in Terms of MCF and Price per MCF19451946Purchased from --VolumePriceVolumePriceH. C. Fownes II480,986$ 0.012433361,171$ 0.029343Warren Oil Corp., Dye,1,851,008.0124761,553,084.029427Solow, Cornell & King.  E. B. Clark441,769.012479340,761.029947Phillips Petroleum Co483,220.012458333,248.029561Magnolia Petroleum Co13,302.012467253,671.029588Magnolia Petroleum Co145,345.031265392,429.031265Shell Oil Co57,029.031265Sinclair Oil & Gas82,422.031265Magnolia Petroleum CoE. W. MeansE. W. MeansDave RubinSinclair Oil & Gas CoSmith & FowlstonContinental Oil Co740,799.012260534,927.029552Shell-Sinclair220,045.029784Texas CompanySchedule of Gas Purchased From Working Interest of Others inShamrock Leases 1943-1954 in Terms of MCF and Price per MCF19471948Purchased from --VolumePriceVolumePriceH. C. Fownes II274,253$ 0.031265242,657$ 0.035512Warren Oil Corp., Dye,1,196,134.0312651,028,898.037121Solow, Cornell & King.  E. B. Clark287,721.031265275,122.036743Phillips Petroleum Co299,961.031265298,008.036900Magnolia Petroleum Co225,122.031265198,931.034541Magnolia Petroleum Co338,689.031265266,815.039440Shell Oil Co72,182.031265130,954.038755Sinclair Oil & Gas225,300.031265243,180.034012Magnolia Petroleum Co686,499.035223E. W. Means1,858.038546E. W. Means294,898.040087Dave Rubin17,251.046360Sinclair Oil & Gas Co197,134.037883Smith & Fowlston313,963.040198Continental Oil CoShell-SinclairTexas Company36,924.044049*232 Schedule of Gas Purchased From Working Interest of Others inShamrock Leases 1943-1954 in Terms of MCF and Price per MCF19491950Purchased fromType ofgasVolumePriceVolumePriceH. C. Fownes IISour69,613$ 0.03241763,391$ 0.039786Warren Oil Corp., Dye,do  1433,963.0432421,047,118.041498Solow, Cornell & King.  E. B. Clarkdo  198,355.031095192,826.034279Phillips Petroleum Codo  317,668.032199252,424.028264Magnolia Petroleum Codo  189,672.029298159,548.028337Magnolia Petroleum CoSweet206,719.040198203,110.040198Shell Oil Codo  166,293.040198167,447.040198Sinclair Oil & GasSour242,577.030317213,415.028527Magnolia Petroleum Codo  1,267,031.0298231,172,603.028528E. W. MeansSweet21,784.03886428,858.039457E. W. Meansdo  259,350.039642331,660.039651Dave RubinSour26,073.0486427,207.047201Sinclair Oil & Gas CoSweet203,217.040198200,541.040198Smith & Fowlstondo  572,915.039969641,447.039814Magnolia Petroleum CoSour520,215.0353221,387,282.035407Magnolia Petroleum Codo  16,371.04737532,012.047091Fowlston & PriceSweet40,857.03991356,344.040074J. W. HuffSour428,556.0446651,137,554.044665Sinclair Oil & Gas anddo  257,234.028571246,638.028029Magnolia Petroleum Co.  Magnolia Petroleum Codo  18,067.047881Texas Companydo  43,110.04183738,828.040459*233 Schedule of Gas Purchased From Working Interest of Others inShamrock Leases 1943-1954 in Terms of MCF and Price per MCF19511952Purchased fromVolumePriceVolumePriceH. C. Fownes II54,228$ 0.04912249,406$ 0.050000Warren Oil Corp., Dye,1,060,116.045797927,585.047201Solow, Cornell & King.  E. B. Clark186,490.045000166,206.045000Phillips Petroleum Co292,843.033207221,153.035593Magnolia Petroleum Co133,086.031802110,664.034631Magnolia Petroleum Co211,504.053176182,313.056478Shell Oil Co156,707.053425160,100.056404Sinclair Oil & Gas201,219.032528176,113.045434Magnolia Petroleum Co1,391,536.0323301,122,107.034758E. W. Means23,833.03947747,233.039199E. W. Means293,622.039581235,639.039536Dave Rubin4,324.0497962,624.051955Sinclair Oil & Gas Co178,923.049260171,440.054788Smith & Fowlston600,136.039962487,744.039979Magnolia Petroleum Co1,262,574.0354141,005,250.044647Magnolia Petroleum Co23,170.04990722,427.051783Fowlston & Price57,556.04007843,233.040036J. W. Huff711,969.044665501,500.044665Sinclair Oil & Gas and283,558.031805206,941.044032Magnolia Petroleum Co.  Magnolia Petroleum Co28,465.04967521,978.051535Texas Company44,230.04386845,384.045224Schedule of Gas Purchased From Working Interest of Others inShamrock Leases 1943-1954 in Terms of MCF and Price per MCF19531954Purchased fromVolumePriceVolumePriceH. C. Fownes II47,823$ 0.05000032,793$ 0.050000Warren Oil Corp., Dye,856,767.051557759,747.056994Solow, Cornell & King.  E. B. Clark151,384.045000129,804.045000Phillips Petroleum Co257,049.058662226,468.065000Magnolia Petroleum Co115,259.03637287,082.039949Magnolia Petroleum Co166,812.061692144,509.073504Shell Oil Co135,145.062255110,135.074168Sinclair Oil & Gas167,705.055000142,186.055000Magnolia Petroleum Co994,009.036276870,197.039945E. W. Means74,588.04182079,166.071794E. W. Means253,796.057617259,826.072423Dave Rubin1,722.056310Sinclair Oil & Gas Co154,301.060000124,200.060000Smith & Fowlston452,336.054985438,478.073751Magnolia Petroleum Co976,332.056914937,145.068963Magnolia Petroleum Co20,939.05756121,392.069576Fowlston & Price42,725.03965942,203.067523J. W. Huff430,964.044665360,206.059036Sinclair Oil & Gas and210,201.055000176,116.055000Magnolia Petroleum Co.  Magnolia Petroleum Co21,354.05736521,410.068490Texas Company40,066.05036331,889.056166*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 Paidfor Gas Purchased From WorkingInterest of Others in Shamrock LeasesWeightedaverage priceYearper MCF1943$ 0.0109941944.0116731945.0130891946.0297751947.0312651948.0371171949.0368541950.0368441951.0392361952.0430731953.0504661954.059552In 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 CasingheadGas Purchases for YearsEnded Nov. 30, 1947 Through 1954YearNumber ofVolume-MCFcontracts14.65 PSIA1947229,9141948132,040,8581949194,109,3061950206,941,0931951206,491,6481952198,601,6111953236,949,3131954286,049,833These 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:Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954in Terms of MCF and Price per MCF19471948Purchased from --VolumePriceVolumePriceShell Oil Co22,817$ 0.030000135,142$ 0.057794Phillips Petroleum Co7,097.030000304,359.039161Dave Rubin-Kerr-McGee  643,152.036352Gayden & Cree34,590.051847Champlin Refining Co21,461.030092Magnolia Petroleum Co47,420.062247American Liberty OilCo  Holt Brothers385.086779Kerr-McGee-DaveRubin  Power Petroleum Co134,724.032887Rosenblum & RubinGold-RubinContinental Oil Co535,414.037312E. M. SolowHerman Brothers-DollieAdams  114,831.046376Holt, Sparks & Plummer*235 Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954in Terms of MCF and Price per MCF19491950Purchased from --VolumePriceVolumePriceShell Oil Co125,325$ 0.039130124,860$ 0.032436Phillips Petroleum Co460,733.031447255,339.030052Dave Rubin-Kerr-McGee  231,123.0310761,784,121.030300Gayden & Cree35,191.04171452,802.036306Champlin Refining Co46,404.03051645,952.03000 Magnolia Petroleum Co83,803.032272122,914.030394American Liberty OilCo  703,001.031131326,938.030499Holt Brothers1,222.05383827,223.031063Kerr-McGee-DaveRubin  101,001.030268138,618.031507Power Petroleum Co193,593.03055170,627.030692Rosenblum & Rubin63,562.03000 Gold-Rubin376,388.0302581,912,305.030279Continental Oil Co596,123.032906860,778.032072E. M. Solow36,636.03000 Herman Brothers-DollieAdams  117,946.04010093,787.047551Holt, Sparks & Plummer11,026.04983840,125.03000 Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954in Terms of MCF and Price per MCF19481949Purchased from --VolumePriceVolumePriceService Drilling Co50,111$ 0.032898869,462$ 0.030307Service Drilling CoSkelly Oil Co14,616.03252135,095.030936The Texas Co4,653.05129839,410.038401Stewart, Smith & Phillips18,898.031375Nabob Production Co*236 Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954in Terms of MCF and Price per MCF19501951Purchased from --VolumePriceVolumePriceService Drilling Co712,576$ 0.03247944,382$ 0.046038Service Drilling Co6,575.05526520,727.052795Skelly Oil Co28,813.03063828,950.034252The Texas Co65,203.03459961,208.046088Stewart, Smith & PhillipsNabob Production Co234,901.032189274,610.036969Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954in Terms of MCF and Price per MCF19511952Purchased from --VolumePriceVolumePricePhillips PetroleumCo  146,247$ 0.039026172,091$ 0.040749Phillips PetroleumCo  203,706.031368215,572.033172Dave Rubin-Kerr-McGee1,524,727.0381824,408,620.051181Gayden & Cree51,900.04714555,920.057341Champlin RefiningCo  45,666.03061842,377.031353Magnolia PetroleumCo  96,138.03198391,780.035269American Liberty OilCo  130,500.033711241,633.056698Holt Brothers21,052.0434199,795.041454Kerr-McGee-DaveRubin  300,261.036988Power Petroleum Co179,914.04151484,923.043463Riedell, Bollig &Skelly Oil Co  Gold-Rubin1,600,214.035929227,074.05000 Continental Oil Co844,005.0540521,353,219.061350E. M. Solow370,330.031556860,575.045432Herman Brothers --Dollie Adams  112,899.05608178,859.064239Holt, Sparks & Plummer34,212.03000 32,962.030036*237 Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954in Terms of MCF and Price per MCF19531954Purchased from --VolumePriceVolumePricePhillips PetroleumCo  107,221$ 0.049197115,698$ 0.05000 Phillips PetroleumCo  143,253.035214114,221.035776Dave Rubin-Kerr-McGee2,660,251.051890Gayden & Cree37,902.06137946,297.050348Champlin RefiningCo  Magnolia PetroleumCo  83,286.045140228,615.049309American Liberty OilCo  141,912.05832662,953.052342Holt Brothers72,068.03353 421,406.042175Kerr-McGee-DaveRubin  Power Petroleum CoRiedell, Bollig &Skelly Oil Co  14,310.04909693,513.037374Gold-RubinContinental Oil Co1,006,652.064660808,635.056062E. M. Solow1,444,995.050227956,114.05000 Herman Brothers --Dollie Adams  45,654.06536719,414.080931Holt, Sparks & Plummer30,073.03084422,322.040978Schedule of Casinghead Gas Purchased by Shamrock 1947 through 1954in Terms of MCF and Price per MCF19521953Purchased from --VolumePriceVolumePriceService Drilling Co425,627$ 0.053877284,418$ 0.056100Service Drilling Co12,572.04887820,180.051304Skelly Oil Company8,732.0468445,821.059189The Texas Company29,549.05747913,335.076725Nabob Production Co249,731.042088223,132.050839Mayfield, Sigfried, Rooney,et al  78,773.05000 Casey, Liversay & PhillipsPetroleum Co 291,281.03900 General American Oil Co212,385.05000 Casey, Liversay & PhillipsPetroleum Co  299,792.039145Skelly Oil Co31,907.05000 Major & BeachJ. M. Huber Corp712.05000 Riedell & Skelly Oil CoHolifield, Major & BeachMcDaniel & McDanielPower Petroleum CoVan Norman Oil CoM & D Oil CompanyA. C. Sorelle & A. C. Sorelle,Jr  *238 Schedule of Casinghead Gas Purchased by Shamrock 1947through 1954 in Terms of MCF and Price per MCF1954Purchased from --VolumePriceService Drilling Co237,749$ 0.050736Service Drilling Co38,670.05000 Skelly Oil Company5,417.063306The Texas Company6,973.069762Nabob Production Co54,181.056437Mayfield, Sigfried, Rooney,et al  86,589.05000 Casey, Liversay & PhillipsPetroleum Co  General American Oil Co334,853.05000 Casey, Liversay & PhillipsPetroleum Co  1,406,498.049287Skelly Oil CoMajor & Beach11,000.05000 J. M. Huber Corp782,278.05000 Riedell & Skelly Oil Co70,386.05000 Holifield, Major & Beach38,614.049984McDaniel & McDaniel2,698.05000 Power Petroleum Co76,527.05000 Van Norman Oil Co3,046.05000 M & D Oil Company4,803.047847A. 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 averageYearprice per MCF1947$ 0.03000 1948.0395971949.0318351950.0312121951.0398831952.0512771953.0519971954.049868 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 UnderMiscellaneous Contractsfor Years Ended Nov. 30, 1943 Through 1954Number ofVolume-MCFsuppliers14.65 PSIA194341,421,177194441,425,705194541,554,827194641,001,454194762,647,204194856,347,9431949118,351,9811950108,662,02519511211,741,40019521115,808,6421953148,120,0221954146,782,300Shamrock's sour gas purchases from the Continental Oil Company for the years ended November 30, 1943 through 1954 were as follows:Volume-MCFYear14.65 PSIA19439,768,880194410,631,082194510,634,02719469,475,58119479,263,16319489,965,399194911,258,72719509,672,18919519,790,79519528,962,65719538,340,98019547,132,210Following 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 Shamrock1943-1954 in Terms of MCF and Price per MCF19431944Purchased from --VolumePriceVolumePriceCities Service Oil Co241,652$ 0.010883248,657$ 0.0113996Phillips Petroleum Co375,007.010660378,653.011097 Magnolia Petroleum Co282,228.011338248,980.011943 Sunset Oil Co522,290.010957549,415.011618 Continental Oil Co9,768,880.01177110,631,082.015081 Liveoak CorporationJoe WorshamHerman Brothers, IncSchedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock1943-1954 in Terms of MCF and Price per MCF19451946Purchased from --VolumePriceVolumePriceCities Service Oil Co255,834$ 0.012223 195,597$ 0.014990Phillips Petroleum Co476,031.011881 318,083.014564Magnolia Petroleum Co268,983.013443 173,501.015763Sunset Oil Co553,979.012437 314,273.015261Continental Oil Co10,634,027.01230959,475,581.020512Liveoak CorporationJoe WorshamHerman Brothers, Inc*240 Schedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock1943-1954 in Terms of MCF and Price per MCF19471948Purchased from --VolumePriceVolumePriceCities Service Oil Co170,166$ 0.023484171,425$ 0.036395Phillips Petroleum Co182,468.021686Magnolia Petroleum Co89,789.022729Sunset Oil Co321,261.023542Continental Oil Co9,263,163.0307969,965,399.044438Liveoak Corporation684,688.035349829,691.04624 Joe Worsham173,960.031265398,250.043841Herman Brothers, Inc46,753.030000Schedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock1943-1954 in Terms of MCF and Price per MCF19491950Purchased from --VolumePriceVolumePriceCities Service Oil Co175,448$ 0.033856126,409$ 0.040198Phillips Petroleum Co1,023,510.066996Continental Oil Co11,258,727.0424949,672,189.040832Liveoak Corporation741,160.048451746,375.047621Joe Worsham328,128.048805301,529.047653Herman Brothers, Inc90,562.03042060,674.030000Fowlston & Schroeter164,193.035732315,718.035732Stewart & Smith & PhillipsPhillips Petroleum CoDave RubinDollie Adams Oil CoTexas CoWalter CaldwellWitco Chemical CorpStanolind Oil & Gas and J. J.Zofness  J. M. HuberSchedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock1943-1954 in Terms of MCF and Price per MCF19511952Purchased from --VolumePriceVolumePriceCities Service Oil Co139,834$ 0.040198139,561$ 0.042355Phillips Petroleum CoContinental Oil Co9,790,795.0440578,962,657.046095Liveoak Corporation707,559.049894619,488.052083Joe Worsham341,328.050018317,118.052026Herman Brothers, IncFowlston & Schroeter285,200.040000262,719.035732Stewart & Smith & Phillips244,070.050000180,902.054577Phillips Petroleum Co3,826,062.0700008,708,136.070000Dave Rubin562,037.0650001,288,534.065000Dollie Adams Oil Co43,683.03014916,805.030029Texas CoWalter CaldwellWitco Chemical CorpStanolind Oil & Gas and J. J.Zofness  J. M. HuberSchedule of Sour Gas Purchased Under Miscellaneous Contracts by Shamrock1943-1954 in Terms of MCF and Price per MCF19531954Purchased from --VolumePriceVolumePriceCities Service Oil Co121,228$ 0.05724299,765$ 0.069254Phillips Petroleum CoContinental Oil Co8,340,980.0503477,132,210.056631Liveoak Corporation557,994.057129487,191.069323Joe Worsham292,774.057234270,238.069586Herman Brothers, IncFowlston & Schroeter280,343.035732267,592.057907Stewart & Smith & Phillips163,453.060000114,300.065000Phillips Petroleum Co490,367.070000520,999.10    Dave Rubin539,059.065000Dollie Adams Oil Co29,010.03193415,554.037869Texas Co86,696.060000102,291.059752Walter Caldwell89,789.060000Witco Chemical Corp1,439,783.060000723,893.060000Stanolind Oil & Gas and J. J.Zofness  67,053.065000J. M. Huber230,238.065000*241 *1004 Schedule of Sweet Gas Purchased Under Miscellaneous Contracts byShamrock 1947-1954 in Terms of MCF and Price per MCF19471948Purchased from --VolumePriceVolumePriceLiveoak Corporation879,760$ 0.0357322,409,493$ 0.049448 Texas Co145,112.0399182,492,331.040081 Shell Oil CoMagnolia Oil CoUnited ProducingCo., Inc  Stanolind Oil & GasSchedule of Sweet Gas Purchased Under Miscellaneous Contracts byShamrock 1947-1954 in Terms of MCF and Price per MCF19491950Purchased from --VolumePriceVolumePriceLiveoak Corporation2,580,431$ 0.0528202,418,099$ 0.051995Texas Co2,034,686.0400052,110,323.039975Shell Oil Co50,144.039879121,291.039760Magnolia Oil Co11,610.039712141,768.039669United ProducingCo., Inc  87,601.050655413,834.052084Stanolind Oil & Gas1,064,508.0401401,906,005.040181Schedule of Sweet Gas Purchased Under Miscellaneous Contracts byShamrock 1947-1954 in Terms of MCF and Price per MCF19511952Purchased from --VolumePriceVolumePriceLiveoak Corporation2,476,052$ 0.0544092,173,583$ 0.056518Texas Co2,050,672.0398941,703,478.043252Shell Oil Co109,918.03974493,941.039874Magnolia Oil CoUnited ProducingCo., Inc  446,209.054239304,377.056358Stanolind Oil & Gas508,776.040198Schedule of Sweet Gas Purchased Under Miscellaneous Contracts byShamrock 1947-1954 in Terms of MCF and Price per MCF19531954Purchased from --VolumePriceVolumePriceLiveoak Corporation1,984,309$ 0.0616551,715,524$ 0.073914Texas Co1,626,978.0616891,711,098.073418Shell Oil Co80,611.04910890,644.073254Magnolia Oil CoUnited ProducingCo., Inc  337,628.062116365,920.073748Stanolind Oil & GasThe *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 GasPurchased Under MiscellaneousContracts and Price Paid for Gas Purchased fromContinental Oil Company (in Term of MCF)Weighted averagePrice perprice perMCF paid forMCF paid forgas purchasedgas purchasedfrom Continentalunder miscellaneousOil Co.contracts1943$ 0.010942$ 0.0117711944.011498.0150811945.012406.0123101946.015074.0205121947.031893.0307961948.044504.0444381949.048178.0424941950.044715.0408321951.055497.0440571952.062320.0460951953.060382.0503471954.072249.056631 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 -- inTerms of MCFTotalGatheringavailableRaw gasandraw gassalesextractionlosses194369,300,388148,8551,883,780194476,888,480377,3911,476,699194591,096,177369,5591,859,025194696,994,242149,5411,024,3751947109,374,8582,757,9182,205,5271948130,836,1921,818,2912,378,9611949160,244,539336,5402,896,8181950159,770,389994,3283,251,4931951150,687,5881,080,5741,748,7271952144,770,2861,384,5583,043,0311953137,836,6831,145,3063,840,9111954133,690,0731,159,7714,333,917Disposition by Years of Total Available Raw Gas -- inTerms of MCFResidue gasResidue gasTotal residueconsumedreturned undergas availableas plantprocessingfor sale byfuel, etc.contractsShamrock19434,088,8779,230,22153,948,65519444,228,76011,537,07059,268,56019453,565,89814,213,66771,088,02819463,620,99013,912,99378,286,34319474,123,98520,733,36979,554,05919485,094,45222,457,30199,087,18719495,798,65525,535,698125,676,82819505,389,44825,251,366124,883,75419517,699,43022,558,881117,599,97619528,124,65619,943,432112,274,60919539,276,82418,764,486104,809,15619549,534,62916,309,574102,352,182The *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 ofTotal Available Raw GasTotalRaw gasGatheringavailablesalesand extractionraw gaslossesPercent19431000.212.7219441000.491.9219451000.412.0419461000.151.0619471002.522.0219481001.391.8219491000.211.8119501000.622.0419511000.721.1619521000.962.1019531000.832.7919541000.873.24Percentage Analysis of Disposition by Years of TotalAvailable Raw GasResidue gasResidue gasTotal residueconsumed asreturnedgas availableplant fuel,under processingfor sale byetc.contractsShamrockPercent19435.9013.3277.8519445.5015.0177.0819453.9115.6178.0319463.7314.3580.7119473.7718.9572.7419483.8917.1675.7319493.6215.9378.4319503.3715.8078.1719515.1114.9778.0419525.6113.7877.5519536.7313.6176.0419547.1312.2076.56From 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 ShamrockResiduePercentageTotal residuegas sold toof residuegas availablecarbongas sold tofor saleblack manufacturerscarbonblack manufacturersPercent194353,948,65550,480,41593.5 194459,268,56056,266,36994.93194571,088,02868,894,81496.91194678,286,34375,283,20696.16194779,554,05965,012,65381.72194899,087,18767,754,53668.381949125,676,82857,664,65645.881950124,883,75454,376,85843.541951117,599,97643,590,41337.071952112,274,60935,031,64931.201953104,809,15613,181,02812.581954102,352,1822,827,9172.76Disposition by Years of Total Residue Gas Available forSale by ShamrockResiduePercentageResiduePercentagegas sold toof residuegas sold toof residueinterstategas sold toothergas sold topipelinesinterstateindustrialotherpipelinesusersindustrialusersPercentPercent19433,468,2406.4319443,002,1915.0719452,193,2143.0919463,003,1373.84194710,803,72813.583,737,6784.70194827,062,84827.314,269,8034.31194963,110,87450.224,901,2983.90195065,251,42652.255,255,4704.21195168,021,71557.845,987,8485.09195270,024,61862.377,218,3426.43195384,174,59780.317,453,5317.11195491,874,68489.767,649,5817.48*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 ThereforCarbon black manufacturersInterstate pipelinesPercentPercentof totalof totalAmountamountAmountamountof residueof residuesalessales1943$ 437,513.4479.931944481,606.3483.311945902,290.5292.6919461,768,634.1293.3419472,225,207.4076.40$ 521,266.5917.9019483,269,308.6366.601,420,918.5928.9419492,648,533.1739.263,845,576.8757.0019502,512,008.0737.973,815,239.2557.6719512,097,711.6731.504,154,679.8762.3919521,684,288.5825.254,518,819.6667.741953623,752.099.235,733,715.9284.851954153,263.001.857,598,590.6691.43Other industrial usersTotalamount receivedPercentfromof totalsale ofAmountamountresidue gasof residuesales1943$ 109,880.2620.07$ 547,393.70194496,515.6116.69578,121.95194571,139.027.31973,429.541946126,208.186.661,894,842.301947166,075.725.702,912,549.711948219,009.094.464,909,236.311949252,435.743.746,746,545.781950288,016.924.366,615,264.241951407,082.616.116,659,474.151952468,101.097.016,671,209.331953400,328.535.926,757,796.541954558,673.086.728,310,526.74*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 Raw Gas Purchased by Interstate Pipeline CompaniesDuring Calendar Year1943Date ofPurchaserSellercontract1943NoneNone2/27/37Northern NaturalIndependent Natural2/1/37Panhandle EasternShamrock4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips9/27/35do   Northern Natural9/27/35do   do   8/4/30do   Navajo Natural2/1/29West Texas Gas CoRed River Gas19442/27/37Northern NaturalIndependent Natural2/1/37Panhandle EasternPhillips Petroleum4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips Petroleum9/27/35do   Northern Natural9/27/35do   do    8/4/30do   Navajo Natural2/1/29West Texas GasRed River Gas19458/18/45Panhandle EasternShell Oil2/27/37Northern NaturalIndependent Natural2/1/37Panhandle EasternPhillips Petroleum4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips Petroleum9/27/35do   Northern Natural9/27/35do   do    8/4/30do   Navajo Natural2/1/29West Texas GasRed River Gas19465/10/46Panhandle EasternBurnett-Cornelius6/16/46do   do   6/16/46do   do   6/16/46do   Navajo Natural8/18/45do   Shell Oil2/27/37Northern NaturalIndependent Natural2/1/37Panhandle EasternPhillips Petroleum4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips Petroleum11/27/36do   do    6/27/35do   Northern Natural9/27/35do   do    8/4/30do   Navajo Natural2/1/29West Texas GasRed River Gas19479/1/47Northern NaturalHagy-Harrington-Marsh5/10/46Panhandle EasternBurnett-Cornelius6/16/46do   do    6/16/46do   do    6/16/46do   Navajo Natural8/18/45do   Shell Oil12/27/37Northern NaturalJ. M. Huber2/27/37do   Independent Natural2/1/37Panhandle EasternPhillips Petroleum10/30/36do   do    7/12/36do   do    11/27/36do   do    9/27/35do   Northern Natural9/27/35do   do   8/4/30do   Navajo Natural2/1/29West Texas GasRed River Gas19488/1/48Northern NaturalWilliams-Phillips1/12/48Panhandle EasternShamrock9/1/47Northern NaturalHarrington-Marsh5/10/46Panhandle EasternBurnett-Cornelius6/16/46do   do   6/16/46do   do   6/16/46do   Navajo Natural8/18/45do   Shell Oil2/27/37Northern NaturalIndependent Natural2/1/37Panhandle EasternPhillips Petroleum2/1/37do   do    4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips Petroleum7/12/36do   do   11/27/36do   do   9/27/35do   Northern Natural9/27/35do   do    8/4/30do   Navajo Natural2/1/29West Texas GasRed River Gas194911/26/48Cities Service GasBurnett Cornelius8/1/48Northern NaturalPhillips Petroleum1/12/48Panhandle EasternShamrock9/1/47Northern NaturalPanoma5/10/46Panhandle EasternBurnett-Cornelius6/16/46do   do    6/16/46do   do    6/16/46do   Navajo Natural6/16/46do   do    8/18/45do   Shell Oil2/27/37Northern NaturalIndependent Natural2/1/37Panhandle EasternPhillips Petroleum2/1/37do   do   4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips Petroleum7/12/36do   do    11/27/36do   do    9/27/35do   Northern Natural9/27/35do   do    8/4/30do   Navajo Natural2/1/29West Texas GasRed River Gas2/1/29do   do    19509/25/50Panhandle EasternBritain4/5/50do   Burnett-Cornelius12/1/49do   Dunn-Kimberlin10/14/49do   Skelly Oil11/26/48Cities Service GasBurnett-Cornelius8/1/48Northern NaturalPhillips Texas1/12/48Panhandle EasternShamrock9/1/47Northern NaturalPanoma Corp5/10/46Panhandle EasternBurnett-Cornelius6/16/46do   do    6/16/46do   Navajo Natural6/16/46do   do    8/18/45do   Shell Oil2/1/37do   Phillips Petroleum2/1/37Panhandle EasternPhillips Petroleum4/21/36Northern NaturalJ. M. Huber2/27/36do   Indenpendent Natural10/30/36Panhandle EasternPhillips Petroleum7/12/36do   do    11/27/36do   do    9/27/35do   Northern Natural9/27/35do   do    8/4/30do   Navajo Natural2/1/29West Texas GasRed River Gas19519/5/51Panhandle EasternBurnett-Cornelius2/11/50Natural Gas Pipelinedo    6/8/50do   Red River Gas9/25/50Panhandle EasternBritain4/5/50do   Burnett-Cornelius1/7/49Natural Gas PipelineCities Service Gas9/29/49do   Earl Nutter12/1/49Panhandle EasternDunn-Kimberlin10/14/49do   Skelly11/26/48Cities Service GasBurnett-Cornelius8/1/48Northern NaturalPhillips-Texas1/12/48Panhandle EasternShamrock9/1/47Northern NaturalPanoma5/10/46Panhandle EasternBurnett-Cornelius5/10/46do   do    6/16/46do   do    6/16/46do   Navajo Natural6/16/46do   do    8/18/45do   Shell Oil2/27/37Northern NaturalIndependent Natural2/1/37Panhandle EasternPhillips Petroleum2/1/37do   do    4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips Petroleum7/12/36do   do    11/27/36do   do    8/4/30do   Navajo Natural2/1/29West Texas GasRed River Gas19522/8/52Natural Gas PipelinePanhandle Eastern7/1/52Northern NaturalPanoma11/1/52Northern NaturalNorthern NaturalGas Co.  Gas Producing Co.  4/17/51Northern NaturalShamrock4/12/51do   do    8/30/51Panhandle EasternShell-Sinclair2/11/50Natural Gas PipelineBurnett-Cornelius6/8/50do   Red River Gas9/25/50Panhandle EasternBritain4/5/50do   Burnett-Cornelius9/5/50do   do    1/7/49Natural Gas PipelineCities Service Gas9/29/49do   Earl Nutter12/1/49Panhandle EasternDunn-Kimberlin10/31/49Southwestern PublicShamrock11/26/48Cities Service GasBurnett-Cornelius8/1/48Northern NaturalPhillips-Texas6/16/48Panhandle EasternNavajo Natural1/12/48do   Shamrock5/10/46do   Burnett-Cornelius5/10/46do   do    6/16/46do   do    6/16/46do   Navajo Natural8/18/45do   Shell Oil2/27/37Northern NaturalIndependent Natural2/1/37Panhandle EasternPhillips Petroleum2/1/37do   do    4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips Petroleum7/12/36do   do    11/27/36do   do    9/21/35do   J. M. Huber6/29/35Southwestern Publicdo    6/29/35do   do    8/4/30Panhandle EasternNavajo Natural2/1/29West Texas GasRed River Gas6/16/27Southwestern PublicPhillips Petroleum7/10/26do   do    19534/30/53Cities Service GasCities Service Gas3/30/53Natural Gas PipelineKimberlin-Howse8/20/53do   Panhandle Eastern6/8/53do   Phillips Petroleum8/28/53Northern NaturalIndependent6/1/53do   Cities Service Oil6/13/53do   Huval-Dunigan5/22/53do   Texas Co12/15/53do   Phillips-Texas10/1/53Southwestern PublicJ. M. Huber10/1/53do   do    11/2/53do   Phillips Petroleum11/19/52Colorado InterstateA. E. Herrmann12/16/52do   H. F. Sears7/1/52Northern NaturalPanoma11/1/52do   Northern Natural11/9/52Southwestern PublicH. B. Dunn9/5/51Panhandle EasternBurnett-Cornelius2/11/50Natural Gas Pipelinedo    6/8/50do   Red River Gas9/25/50Panhandle EasternBritain4/5/50do   Burnett-Cornelius9/29/49Natural Gas PipelineEarl Nutter1/7/49do   Cities Service Gas12/1/49Panhandle EasternDunn-Kimberlin10/14/49do   Skelly Oil12/31/49Southwestern PublicShamrock11/26/48Cities Service GasBurnett-Cornelius1/12/48Panhandle EasternShamrock3/4/48do   Skelly-Cabot5/10/46do   do    5/10/46do   do    6/16/46do   do    6/16/46Panhandle EasternNavajo Natural6/16/46do   do    8/18/45do   Shell Oil2/1/37do   Phillips Petroleum2/1/37do   do    4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips Petroleum7/12/36do   do    11/27/36do   do    9/21/35do   J. M. Huber8/4/30do   Navajo Natural7/10/26Southwestern PublicPhillips Petroleum19545/11/54Colorado InterstateWitco Chemical2/2/54Natural Gas PipelinePhillips Petroleum4/30/53Cities Service GasCities Service4/30/53do   do    3/30/53Natural Gas PipelineKimberlin-Howse6/1/53Northern NaturalCities Service Oil6/13/53do   Huval-Dunigan8/28/53do   Independent Natural5/22/53do   Texas Company12/15/53do   Phillips Petroleum10/1/53Southwestern PublicJ. M. Huber10/1/53do   do    11/2/53do   Phillips Petroleum11/2/53do   do    11/19/52Colorado InterstateA. E. Herrmann12/16/52do   H. F. Sears7/1/52Northern NaturalDorchester11/1/52do   Northern Natural11/9/52Southwestern PublicH. B. Dunn9/5/51Panhandle EasternBurnett-Cornelius2/11/50Natural Gas Pipelinedo    9/25/50Panhandle EasternB. M. Britain4/5/50do   Burnett-Cornelius1/7/49Natural Gas PipelineCities Service9/29/49do   Earl Nutter12/1/49Panhandle EasternDunn-Kimberlin10/31/49Southwestern PublicShamrock11/26/48Cities Service GasBurnett-Cornelius5/10/46Panhandle Easterndo    5/10/46do   do    6/16/46do   do    6/16/46do   Navajo Natural6/16/46do   do    8/18/45do   Shell Oil2/1/37do   Phillips Petroleum2/1/37do   do    4/21/36Northern NaturalJ. M. Huber10/30/36Panhandle EasternPhillips Petroleum7/12/36do   do    11/27/36do   do    9/21/35do   J. M. Huber8/4/30do   Navajo Natural*273 Raw Gas Purchased by Interstate Pipeline Companies During Calendar Year1943ApproximateB.t.u.MFC DeliveryCents/Date ofPoint ofper cu.atMCF atContractreceiptft.14.65 PSIA14.65PSIA19432/27/37Skellytown1,06812,628,374$ 0.050970 2/1/37Moore Co1,01214,674,343.031757 4/21/36Skellytown(1)  2,149,237.031265 10/30/36Moore Co1,012652,945.022332 9/27/35do   1,012287,753.031265 9/27/35Carson Co1,012230,155.031265 8/4/30Well mouth1,012898,783.031265 2/1/29do   1,00410,480,640.037110 19442/27/37Skellytown1,06812,683,733.050909 2/1/37Moore Co1,01014,330,621.031737 4/21/36Skellytown(1)  2,509,163.031265 10/30/36Moore Co1,010411,245.022332 9/27/35do   1,010255,236.031265 9/27/35Carson Co1,010175,030.031265 8/4/30Well mouth1,0101,764,416.031265 2/1/29do   1,04012,082,846.036915 19458/18/45Moore Co1,0031,076.035725 2/27/37Skellytown1,06012,674,584.050838 2/1/37Moore Co1,00313,139,136.031747 4/21/36Skellytown(1)  3,375,689.031326 10/30/36Moore Co1,003484,710.022332 9/27/35do   1,003200,331.031265 9/27/35Carson Co1,003178,267.031265 8/4/30Well mouth1,0031,434,683.031265 2/1/29do   1,04012,518,420.036907 19465/10/46Carson Co1,016276,690.037965 6/16/46do   1,01696,583.037965 6/16/46Carson &1,016161,926.037965 Hutch.  6/16/46do   1,016170,788.037965 8/18/45Moore Co1,016310,416.035732 2/27/37Skellytown1,04712,850,449.050722 2/1/37Moore Co1,01611,470,984.031824 4/21/36Skellytown(1)  3,404,250.035732 10/30/36Moore Co1,016553,972.022332 11/27/36do   1,0161,767,959.031265 6/27/35do   1,016181,269.031265 9/27/35Carson Co1,016215,696.031265 8/4/30Well mouth1,0161,551,185.031265 2/1/29do   1,04012,011,675.036946 19479/1/47Well mouth(1)  8,215,730.046898 5/10/46Carson Co1,015635,516.037965 6/16/46do   1,015276,764.037965 6/16/46Carson & Hutch.1,015282,376.037965 6/16/46do   1,015473,972.037965 8/18/45Moore Co1,015278,665.035732 12/27/37Skellytown(1)  3,457,335.035732 2/27/37do   1,04912,598,472.050918 2/1/37Moore Co1,0159,565,221.031824 10/30/36do   1,015432,643.022332 7/12/36do   1,015460,845.031265 11/27/36do   1,0151,464,171.031422 9/27/35do   1,015158,795.031265 9/27/35Carson Co1,015152,998.031265 8/4/30Well mouth1,0152,203,278.031265 2/1/29do   1,04013,845,606.036787 19488/1/48Well mouth(1)  33,754.044664 1/12/48Moore Co1,015140,249.044664 9/1/47Well mouth(1)  23,324,303.046898 5/10/46Carson Co1,015734,882.037965 6/16/46do   1,015280,672.037965 6/16/46Carson & Hutch.1,015270,337.037965 6/16/46do   1,015449,906.037965 8/18/45Moore Co1,015210,827.035629 2/27/37Skellytown1,05612,920,229.051024 2/1/37Moore Co1,015478,329.032242 2/1/37do   1,0159,809,937.031824 4/21/36Skellytown(1)  2,191,911.035732 10/30/36Moore Co1,015484,240.022332 7/12/36do   1,015539,122.031265 11/27/36do   1,0151,076,375.031342 9/27/35do   1,015179,389.031265 9/27/35Carson Co1,015171,497.031265 8/4/30Well mouth1,0151,407,669.045015 2/1/29do   1,04014,117,493.036780 194911/26/48Production line.1,0811,916,297.049131 8/1/48Well mouth(1)  355,792.044665 1/12/48do   1,015227,864.044664 9/1/47do   (1)  25,538,167.046898 5/10/46Carson Co1,0151,067,626.038196 6/16/46do   1,015144,027.038802 6/16/46Carson & Hutch.1,015393,256.037933 6/16/46Well mouth1,015477,079.037999 6/16/46do   1,015148,789.038881 8/18/45Moore Co1,015248,024.035740 2/27/37Skellytown1,05512,578,884.051148 2/1/37Moore Co1,015567,268.031803 2/1/37do   1,01511,808,203.031811 4/21/36Skellytown(1)  3,172,139.035732 10/30/36Moore Co1,015477,360.022313 7/12/36do   1,015641,607.031276 11/27/36do   1,0151,229,193.031244 9/27/35do   1,015170,556.031337 9/27/35Carson Co1,015208,129.031217 8/4/30Well mouth1,0152,087,371.040188 2/1/29do   1,0407,538,739.043137 2/1/29do   1,0403,354,464.043618 19509/25/50Well mouth1,01563,856.054999 4/5/50Carson & Potter.1,0152,200,970.050000 12/1/49Well mouth1,015190,492.053709 10/14/49Hutch. & Moore.1,0151,963,395.053744 11/26/48Production line.1,0811,509,687.049131 8/1/48Well mouth1,073310,709.044665 1/12/48do   1,015229,415.044678 9/1/47do   (1)  27,343,903.046898 5/10/46Carson Co1,015965,200.038033 6/16/46do   1,015433,529.037751 6/16/46Well mouth1,015545,231.038116 6/16/46do   1,015286,870.038970 8/18/45Moore Co1,015257,885.035912 2/1/37do   1,015561,542.031762 2/1/37Moore Co1,01510,891,484.031793 4/21/36Skellytown(1)  3,247,883.035732 2/27/36do   1,05012,620,252.051052 10/30/36Moore Co1,015432,311.022200 7/12/36do   1,015652,084.031364 11/27/36do   1,0151,100,664.031210 9/27/35do   1,015137,721.031590 9/27/35Carson Co1,015187,797.031054 8/4/30Well mouth1,0151,981,671.040140 2/1/29Fritch. Texas.1,0408,360,407.043759 19519/5/51Well mouth1,015127,819.055000 2/11/50Skellytown(1)  211,205.058360 6/8/50Fritch, Texas.(1)  3,385,646.053597 9/25/50Well mouth1,0151,102,443.055000 4/5/50Carson & Potter.1,0151,757,088.050000 1/7/49Fritch, Texas.(1)  6,421,031.071463 9/29/49Skellytown(1)  445,203.058158 12/1/49Well mouth1,015232,747.053721 10/14/49Hutch. & Moore.1,0152,647,499.053773 11/26/48Carson Co1,0791,760,357.049131 8/1/48Well mouth1,061288,360.044664 1/12/48do   1,015171,688.044744 9/1/47do   (1)  26,069,862.046898 5/10/46Carson Co1,015498,802.038154 5/10/46do   1,015604,148.038136 6/16/46do   1,015422,531.037928 6/16/46Well mouth1,015620,846.038134 6/16/46do   1,015331,570.038988 8/18/45Moore Co1,015228,981.040298 2/27/37Skellytown1,05012,570,392.50894 2/1/37Moore Co1,015556,779.031870 2/1/37do   1,01510,236,103.031913 4/21/36Skellytown1,1103,458,588.035732 10/30/36Moore Co1,015415,535.022200 7/12/36do   1,015630,717.031440 11/27/36do   1,015913,163.031310 8/4/30Well mouth1,0151,922,452.040189 2/1/29Fritch, Texas.1,04010,404,454.043818 19522/8/52Moore Co1,0827,366,342.093800 7/1/52Well mouth(1)  25,216,364.063463 11/1/52do   1,0841,443,235.081164 4/14/51Sunray, Texas.95412,850,537.096373 4/12/51do   95410,454,488.055796 8/30/51Moore Co1,01511,580,777.086637 2/11/50Skellytown1,090200,450.062694 6/8/50Fritch, Texas.1,0813,997,675.053597 9/25/50Well mouth1,0151,088,790.054998 4/5/50Carson & Potter.1,0151,700,591.049999 9/5/50Potter Co1,015364,175.054998 1/7/49Fritch, Texas.1,09010,743,014.086053 9/29/49Skellytown1,090407,940.062693 12/1/49Well mouth1,015193,671.053725 10/31/49Sherman Co1,000250,564.095351 11/26/48Carson Co1,0791,560,237.049131 8/1/48Well mouth1,079269,712.054816 6/16/48do   1,015314,267.039053 1/12/48do   1,015126,165.044822 5/10/46Carson Co1,015487,768.038326 5/10/46do   1,015565,287.038290 6/16/46do   1,015419,218.038080 6/16/46Well mouth1,015585,048.038199 8/18/45Moore Co1,015211,567.040351 2/27/37Skellytown1,02512,620,612.050393 2/1/37Moore Co1,015512,418.031872 2/1/37do   1,01510,414,633.031939 4/21/36Skellytown1,1173,562,265.035732 10/30/36Moore Co1,015508,574.022195 7/12/36do   1,015568,200.031436 11/27/36do   1,0151,129,727.031310 9/21/35Carson Co1,0153,770,922.040126 6/29/35Skellytown1,00025,959.093962 6/29/35Borger, Texas.1,000815,125.093514 8/4/30Well mouth1,0152,062,395.041778 2/1/29do   1,04010,390,762.043823 6/16/27Phillips, Texas.1,00036,135.066632 7/10/26Riverview1,0006,045.053176 19534/30/53Well mouth1,10341,039,490.067960 3/30/53Carson Co1,093118,605.080000 8/20/53Moore Co1,084834,053.100000 6/8/53do   1,0727,347,545.100000 8/28/53Skellytown1,02512,720,414.051711 6/1/53Well mouth1,084241,277.081670 6/13/53do   1,06749,136.081867 5/22/53do   1,078421,305.092035 12/15/53do   1,079239,864.064798 10/1/53Skellytown1,00024,397.011352510/1/53Borger, Texas.1,000783,229.011349411/2/53Phillips, Texas.1,00034,459.089451 11/19/52Well mouth1,001223,972.080000 12/16/52do   1,047664,688.084700 7/1/52do   1,00020,930,896.081300 11/1/52do   1,0737,213,064.081183 11/9/52Hansford Co.1,000112,551.084895 9/5/51Potter Co1,015256,464.055000 2/11/50Skellytown1,090183,958.062690 6/8/50Fritch, Texas.1,0851,144,327.062530 9/25/50Well mouth1,0151,373,652.063150 4/5/50Carson & Potter.1,0151,497,492.050000 9/29/49Skellytown1,091343,102.062690 1/7/49Fritch, Texas.1,09012,331,878.096656 12/1/49Well mouth1,015230,960.053719 10/14/49Hutch. & Moore Co.1,0152,522,903.054361 12/31/49Sherman Co.1,000160,279.091723 11/26/48Production lines.1,1031,385,848.049131 1/12/48Well mouth1,01586,453.044972 3/4/48Hutch. Co1,0151,438,339.054300 5/10/46Carson Co1,015404,810.038349 5/10/46do   1,015508,901.038324 6/16/46do   1,015363,445.038075 6/16/46Well mouth1,015563,773.038196 6/16/46do   1,015309,828.039060 8/18/45Moore Co1,015207,717.040353 2/1/37do   1,015484,277.031876 2/1/37do   1,0159,314,409.031944 4/21/36Skellytown1,1192,995,190.035732 10/30/36Moore Co1,015445,420.022190 7/12/36do   1,015608,655.031438 11/27/36do   1,015985,859.031314 9/21/35Carson Co1,0153,136,554.040147 8/4/30Well mouth1,0151,762,919.044910 7/10/26Riverview Plant.1,0006,006.059947 19545/11/54Field Point1,096111,050.01518052/2/54Moore Co1,08112,890,127.01400004/30/53Well mouth1,0131,424,646.077478 4/30/53do   1,01347,861,367.092071 3/30/53Carson Co1,093128,716.080452 6/1/53Well mouth1,084355,867.080000 6/13/53do   1,067108,900.080000 8/28/53Skellytown.1,0253,677,406.052227 5/22/53Well mouth1,078953,238.080000 12/15/53do   1,079214,026.074083 10/1/53Skellytown.1,00021,921.015133410/1/53Borger, Texas.1,000751,352.014602511/2/53Phillips, Texas.1,00032,659.014994211/2/53Riverview Plant.1,0005,349.010675511/19/52Well mouth1,030226,386.088296 12/16/52do   1,075802,599.089955 7/1/52do   1,00019,230,348.080000 11/1/52do   9926,822,493.080400 11/9/52Hansford Co.1,000130,919.090649 9/5/51Well mouth1,015215,947.055213 2/11/50Skellytown1,092161,479.063037 9/25/50Well mouth1,0151,295,810.070403 4/5/50do   1,0151,064,245.080211 1/7/49Fritch, Texas1,08610,229,048.01056929/29/29Skellytown1,091274,137.063055 12/1/49Well mouth1,015152,794.054223 10/31/49Sherman Co.1,000123,768.010681811/26/48Production lines.1,1031,100,256.049131 5/10/46Well mouth1,015334,570.038345 5/10/46do  1,015389,820.038320 6/16/46Field Point1,015284,205.038075 6/16/46do   1,015493,958.038198 6/16/46Well mouth1,015269,520.039062 8/18/45do   1,015182,058.040366 2/1/37Field Point1,015441,548.078134 2/1/37do   1,0157,846,147.031940 4/21/36Skellytown1,1162,799,292.036630 10/30/36Field Point1,015364,576.022196 7/12/36do   1,015460,634.031439 11/27/36do   1,015965,298.01465259/21/35do   1,0152,865,478.040147 8/4/30Well mouth1,0151,405,568.044907 *274 Not available. *1024 Tabulation and Comparison of Basic Provisions of Original Contracts Under Which Pipeline Companies Made Field Purchases of Gas at WellHead in Texas Panhandle Area During Years 1943 Through 1954 as Reportedto Federal Power Commission(Price converted to rate at 14.65 PSIA)PurchaserSellerDate ofSweet or sourcontractPanhandleNavajo8-4-30See remarksEastern.Natural gas.Do    do    9-1-47Sulphur fee merchantablegas.Natural gasBurnett-2-11-50Not more than 1 grainPipeline.Cornelius.H[2]S or 30 grains sulphurper 100 cu. ft.NorthernPhillips8-1-48(2*280 )Natural.Petroleum.Natural GasI. Earl9-29-49Not more than 1 grainPipeline.Nutter.H[2]S or 30 grains sulphurper 100 cu. ft.PanhandleDunn-12-1-49Not more than 1 grainEastern.Kimberlin.H[2]S or 20 grains sulphurper 100 cu. ft.Do    Burnett-4-5-50do    Cornelius.Do    B. M. Britain9-25-50do    Do    Burnett-9-5-51do    Cornelius.NorthernNorthern11-1-52Not more than 1/2 grainNatural.Natural GasH[2]S or 20 grains sulphurProducingper 100 cu. ft.Company.SouthwesternH. B. Dunn11-9-52(2)Public Service.ColoradoA. E. Herrmann11-19-52Not more than 1 grainInterstate.Corp.,H[2]S or 20 grains sulphuret al.per 100 cu. ft.Do    H. F. Sears12-16-52do    Natural GasKimberlin &3-30-53Not more than 1 grainPipeline.Howse.H[2]S or 30 grains sulphurper 100 cu. ft.Cities ServiceCities Service4-30-53Not more than 1 grainGas Co.Gas Prod. Co.H[2]S or 20 grains sulphur(Formerlyper 100 cu. ft.Empire GasCo.).NorthernTexas5-22-53do    Natural.Company.Do    Cities Service6-1-53do    Oil Co.Do    Huval and6-13-53do    Dunigan.Do    Phillips12-15-53do    Petroleum.*275 n1Tabulation and Comparison of Basic Provisions of Original Contracts Under Which Pipeline Companies Made Field Purchases of Gas at WellHead in Texas Panhandle Area During Years 1943 Through 1954 asReported to Federal Power Commission(Price converted to rate at 14.65 PSIA)ContractRequiredpricePurchaserB.t.u.Contract minimumcents/MCF(14.65PSIA)Panhandle950See remarks3.1265Eastern.Do    950Ratably with gas delivered4.0198into buyer's line.Natural Gas(2)  Full allowable5.35974Pipeline.Northern(2)  Ratably with wells producing4.4665Natural.into buyer's line.Natural Gas(2)  Full allowable, ratably5.3598Pipeline.Panhandle(2)  Ratably with gas delivered5.3600Eastern.into buyer's line.Do    97590% of legal allowable5.0000Do    975Ratably with gas delivered5.5000into buyer's line.Do    975Legal allowable5.5000Nothern1,000Ratably with gas purchased8.0000Natural.and produced bybuyer.Southwestern(2)  Ratably with wells connected9.0000Public Service.to Phillips line.Colorado1,000Maximum allowable8.0000Interstate.Do    1,000do    8.5000Natural Gas(2)  Full allowable8.0000Pipeline.Cities Service900An annual volume of6.7961Gas Co.80,754,778 MCF.Northern950Ratably with gas buyer8.0000Natural.is taking in Carson andGray Counties.Do    950do    8.0000Do    950do    8.0000Do    950do    8.0000*276 n1Tabulation and Comparison of Basic Provisions of Original Contracts Under Which Pipeline Companies Made Field Purchases of Gas at WellHead in Texas Panhandle Area During Years 1943 Through 1954 as Reportedto Federal Power Commission(Price converted to rate at 14.65 PSIA)AreaDedicatedPurchaserDelivery pointacresFieldCountyPanhandleWellhead of the1.961W. PanCarsonEastern.individual wells.Do    do    1.961do  do  Natural GasWellhead-buyer164.3do  do  Pipeline.to install gatheringandmeteringfacilities.Northerndo    498.9do  do  Natural.Natural Gasdo    567do  do  Pipeline.Panhandledo    160do  MooreEastern.Do    do    310.8do  Carson,Potter.Do    do    600do  Moore,Potter.Do    do    124.7do  PotterNorthernWellhead-buyer15,200W. PanCarson,Natural.to install gatheringGray.andmeteringfacilities.Southwesterndo    640T. HugoHansford.Public Service.Coloradodo    160W. PanMooreInterstate.Do    do    302.6do  Hutch.,Moore,Potter.Natural Gasdo    80do  CarsonPipeline.Cities Servicedo    102,143 Tdo  Carson,Gas Co.88,686 OGray.Northerndo    2,160do  GrayNatural.Do    do    640do  Carson,Gray.Do    do    320do  GrayDo    do    498.9do  Carsonn1Tabulation and Comparison of Basic Provisions of Original Contracts Under Which Pipeline Companies Made Field Purchases of Gas at WellHead in Texas Panhandle Area During Years 1943 Through 1954 as Reportedto Federal Power Commission(Price converted to rate at 14.65 PSIA)PurchaserTermSpecial provisions andremarksPanhandleLife of leaseGas to be purchased onEastern.a pro rata basis withother wells connectedto Buyer's line.Buyer may reject gas ifit contains more than20 grains of sulphur per100 cu. ft.Do    do    Second 5 year period,the price shall be4.4665 cents/MCF; next 5years, 4.9131 cents/MCF;thereafter for each 5year period, theweighted average price.This is a modificationof the above contract.Natural GasSo long as gas canFor 5 year period beginningPipeline.be delivered in7-1-51, the pricecommercialshall be 6.25303 cents/MCF;quantities.thereafter, the priceshall be 7.14632 cents/MCFNorthern5 yrs. & thereafterThe base price is theNatural.on 60 days' noticeprice shown or theof termination.weighted averageprice, whichever ishigher.  When theweighted average priceexceeds the priceshown, then suchweighted average priceshall prevail.Natural GasSo long as gasDuring 5 year periodPipeline.can be deliveredbeginning 7-1-51, thein commercialprice shall be 6.2530 cents/quantities.MCF.  Beginning7-1-56 and thereafterthe price shall be7.1463 cents/MCF.  Cityof White Deer hasfirst call on gas producedfrom this lease.PanhandleSo long as gas isFor the second 5 yearEastern.produced inperiod, the price shallpaying quantities.be 5.8000 cents/MCF; forthe third 5 yearperiod, 6.2500 cents/MCF;for each 5 year periodthereafter the priceshall be the weightedaverage field price.Do    do    If Buyer is requiredto treat gas for removalof sulphur, theprice shall be reduced0.2500 cents/MCF.  From4-1-55 to 4-1-60, theprice shall be 7.0000 cents/MCF; thereafter,8.0000 cents/MCF.Do    do    For the second 5year period the priceshall be 7.0000 cents/MCF;thereafter, 8.0000 cents/MCF.Do    do    If Buyer is requiredto treat gas for theremoval of sulphur,the price shall bereduced 0.2500 cents/MCF.For second 5 yearperiod, the price shallbe 7.0000 cents/MCF;thereafter, 8.0000 cents/MCF.NothernAs long as gasFor each 5 yearNatural.can be deliveredperiod beginningin commercial1-1-58, the price shallquantities.be determined bynegotiation, but shallnot be less than8.0000 cents/MCF.SouthwesternTo 1-1-63Beginning 1-1-57 thePublic Service.price shall be 10.0000 centsMCF.  Purchaseunder this contractis engaged in distributionof gas fordomestic and industrialuse in Stratfordand other areasin the vicinity of thiswell, and purchasesthis gas to supplementits requirementsfor gas being distributedby it.Southwestern asBuyer of gas deliversthe gas through aconnecting line toPhillips' line andtakes a like volume ofgas from Phillips'line near City ofStratford.Colorado20 yrs. & thereafterIf Buyer at any timeInterstate.as long as gaspays more thancan be delivered.8.0000 cents/MCF for gasin Moore County,then price paid sellershall be adjustedaccordingly.Do    do    For each 5 year periodafter the initial 5 yearperiod, the price shallbe negotiated, butshall not be less than9.5000 cents/MCF.  IfBuyer at any timepays more than theprices stated in theCounties of Moore,Hutchinson andPotter, the price paidSeller shall be adjustedaccordingly.Natural GasSo long as gasNone.Pipeline.can be deliveredin commercialquantities.Cities Service20 yrs. fromPrice intended to beGas Co.4-1-53 & thereafterprevailing field priceas long asand to be adjustedgas can be deliveredfrom time to time toin commercialreflect such prevailingquantities.field price.  Contractalso covers acreage inOklahoma HugotonField.Northern20 yrs. from dateFor each 5 year periodNatural.of initial deliverybeginning 7-1-58, theor 6-30-53price is to be determinedwhichever isby negotiation,earlier.but shall not be lessthan 8.0000 cents/MCF.Do    So long as gasDo.   can be deliveredin commercialquantities.Do    do    Do.   Do    To 12-31-73Do.   *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 under section 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, 1 contain the following material relevant to this issue:*1029  The term "gross income from the property," as used in sections 114(b)(3) and 114(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.  2Early 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), affd.  Brea Canon Oil Co. v. Commissioner, 77 F. 2d 67 (C.A. 9, 1935);  Signal Gasoline Corporation, 30 B.T.A. 568">30 B.T.A. 568 (1934),affd.  77 F. 2d 728 (C.A. 9, 1935); Greensboro Gas Co., 30 B.T.A. 1362 (1934), affd.  79 F. 2d 701 (C.A. 3, 1935); Consumers Natural Gas Co., 30 B.T.A. 1263">30 B.T.A. 1263 (1934), affd.  78 F. 2d 161 (C.A. 2, 1935).The regulation, 3 which both petitioner *281 and respondent recognize as applicable to the determination of the "gross income from the property" for purposes of computing the depletion allowance, contains first the statement that the "gross income from the property" means the amount for which the taxpayer sells the oil and gas in the immediate vicinity of the well.  Petitioner, perhaps to avoid the difficulties present in the remaining provisions of this regulation, contends that, considering the nature of its operations, it sells the natural gas in the immediate vicinity of the well and that its income from said sales, adjusted to approximate a selling price at the well mouth, constitutes the "gross income from the property." We do not agree.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.Furthermore, petitioner's raw gas was produced from many different wells ranging in distance from less than 1 mile to more than 25 miles from these plants. Accordingly, we must conclude that petitioner did not sell raw gas in the immediate vicinity of the well and that petitioner's "gross income from the property" may not be determined under the first provision of the applicable regulation."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, 730(C.A. 10, 1956), the United States Court of Appeals for the Tenth Circuit said:"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 924 (C.A. 5, 1935), the court approved as reasonable and within the contemplation of the parties the interpretation of the District Court that market pricewas the average price in the field at the well.  However, the court found that on the facts of the case the term "market price" was interchangeable with the term "market value" and that certain evidence was inadmissible to prove that value.  In a later case, Sartor v. United Gas Public Service Co., 84 F. 2d 436 (C.A. 5, 1936), the court held that although the lease provided for the royalty to be calculated at the rate of market price at the well, if none was sold at the well and if there was no actual market price established day by day in the field, the lessors were entitled *286 to prove the fair value at the well and to do that by showing what the lessee got for it day by day in the field.  4In an opinion at 134 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 Sartor v.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.  5*288 In Shamrock Oil & Gas Corporation v. Coffee, 140 F. 2d 409 (C.A. 5, 1944), where the royalty provision involved contained the language "On gas produced from said land and sold or used off the land, or in the manufacture of gasoline * * * the market price at the well *289 of 1/8 of the gas so sold or used," the court made this distinction: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.  6What was meant by "price * * * paid * * * in the same market" came up in Phillips Petroleum Co. v. Bynum, 155 F. 2d 196 (C.A. 5, 1946), where the lessors contended that no market price for their gas had ever been established by *290 actual and comparable sales in the county in which their property was located and that having shown an absence of market price in the county they were not required to show an absence of market price throughout the entire Panhandle Field but *1033  were then entitled to prove the fair and reasonable value of the gas taken and used by the lessee. The court disagreed.  In part it said:We 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." See Phillips Petroleum Co. v. Johnson, 155 F. 2d 185 (C.A. 5, 1946).  7*295  Market 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, 8 title to the royalty gas, usually one-eighth of production, is in the lessee. He does not purchase this gas from the lessor, he is merely obligated to compensate the lessor for the gas taken.  There is no option in the lessor to sell or not to sell this gas to the lessee. Consequently, there is not the negotiation between the parties as to the matter of price that we deem necessary for the determination of a representative market or field price.  The lessee is not a buyer.  Dissatisfaction on the part of the lessor regarding the price paid does not enable him to negotiate in the market for a better price.  He must accept the price offered or seek relief *297 in the courts.  See Arkansas Natural Gas Co. v. Sartor, supra, and similar cases cited above. 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.  9*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.At that point we see no basis for disregarding evidence of market or field price based on purchases from working interests, casinghead purchases, and purchases under miscellaneous contracts because of alleged differences in volume.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, does not, we believe, extend to the situation and contracts described above.  There the court found that pipeline companies do *302 not buy gas at the well and they had not, and never had, furnished a market for gas of any person situated similarly to the plaintiff.  However, the evidence of price that was improperly excluded by respondent in the instant case is only of pipeline purchases of raw gas at the well mouth and from sellers including, among others, Shamrock Oil & Gas Corporation.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."Nor, when oil or gas is produced, does the statute base the percentage on market value.  The gross income from time to time may be more or less than market value according to the bearing of particular contracts." Helvering v. Mountain Producers Corporation, 303 U.S. 376">303 U.S. 376, 382 (1938). "The amount of depletion allowable to producers may *1038  vary with their individual situations, depending on what they can command at the well for their product in its crude state." James P. Evans, Sr., 11 T.C. 726">11 T.C. 726, 730 (1948).Although 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. There the respondent limited the depletion allowance to 50 percent of what it determined to be the petitioner's net income.  On appeal, the Second Circuit viewed the issue as whether the percentage for depletion was to be computed upon "the income of the taxpayer derived from the sale of gas to consumers at the meter, or upon so much of that income as is estimated to represent the value of the gas at the mouth of the well." Speaking for the court, Judge Learned Hand said: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. 103 (1932).In 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). Unlike rent, it represents a division or sharing of the production or its proceeds. 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. 312 (1934).It 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.In that case, the issue before the Court was whether cash bonus payments received by the taxpayer for the grant of oil and gas leases were taxable as ordinary income or as capital gain.  The lower court had held that, since under Texas law an oil and gas lease is regarded as a present sale of the oil and gas in place, the gain resulting from the cash payment received as consideration for the leases in question was taxable only as gain from the sale of capital assets.  10 Rejecting this conclusion and refusing to be bound by technical differences in the property laws of the several States, 11 the Supreme Court declared (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, 577. But bonus *314 payments to the *1042  lessor have been deemed to be subject to depletion allowances under § 214a(9), Revenue Act of 1924, by Art. 216, Treasury 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) 17. The distinction, so far as we are advised, has not been taken in any other case.  See Alexander v.King, supra; Ferguson v. Commissioner, 59 F. (2d) 891; Appeal of Nelson Land & Oil Co., 3 B.T.A. 315">3 B.T.A. 315; Burkett v. Commissioner, 31 F. (2d) 667, and see the same case before the Board of Tax Appeals, 7 B.T.A. 560">7 B.T.A. 560; Berg v. Commissioner, 33 F. (2d) 641; Hirschi 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.  See Work v. Mosier, 261 U.S. 352">261 U.S. 352, 357-358.The 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. 299 (1932), which involved specifically the computation of the depletion deduction, the Court said (at p. 302):We 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. This is obvious where royalties alone are insufficient to return the capital investment.  A distinction between royalties and bonus, which would allow a depletion deduction on the former but tax the latter in full as income, when received, making no provision for a reasonably anticipated production of oil on the leased premises, would deny the "reasonable allowance for depletion" which the statute *316 provides.  * * *At this juncture, it may be noted that Burnet v. Harmel arose under the Revenue Act of 1924, and that Murphy Oil Co. v. Burnet arose under the Revenue Act of 1918, neither of which statute made any provisions for percentage depletion, an allowance which, in the case of oil and gas wells, was first provided by the Revenue Act of 1926.  12 The significance of this fact will receive further comment below.In any event, the rule that a cash bonus was ordinary income depletable in the hands of the lessor became firmly established.  See Palmer v. Bender, 287 U.S. 551 (1933); 13Anderson v. Helvering, 310 U.S. 404*1043  (1940); 14Burton-Sutton Oil Co. v. Commissioner, 328 U.S. 25 (1946). 15*319  However, none of these cases cast additional light on the reasoning which underlay the Supreme Court's conclusion, enunciated in Burnet v. Harmel and Murphy 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.  16*320  These various regulations are substantially identical in language.  The earliest, that contained in Treasury 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 and Murphy 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. 17 Under the provisions of law applicable to the two cases cited, the depletion allowance was, at all events, a fixed amount, either cost, or March 1, 1913, value, or the value of the minerals discovered.  Regs. 45, art. 203.  The overall amount of depletion to be recovered having been determined, the regulation quoted above merely sets out the method of recovery, requiring simply that the lessor's capital be recovered first out of the bonus, if any, and then out of royalties, presumably because that was the normal order of receipt of the two categories of income. That the bonus per se was not made part of the depletion base by the regulation was perfectly clear due to the fact that, if the lessor's value for depletion (whether based on cost or *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 in Burnet v. Harmel.  Neither the trial court, 18 nor the Court of Appeals, 19 mentioned such an issue or alluded to the subject ofdepletion in any manner at all.  The conclusion is inescapable that Burnet v. Harmel, supra, stood for no more than that a cash bonus was ordinary income and not capital gain in the hands of the lessor. It *322 is equally clear that, later comments to the contrary notwithstanding, the case did not stand for the proposition that such bonuses, as such, are subject to the allowance for depletion and, for that matter, could not stand for such a proposition because there was no such issue before the Court.In Murphy Oil Co. v. Burnet, supra, the Court set out the sole issue to be decided as being "whether the Commissioner correctly calculated the deduction for depletion for the years in question, by treating the bonus previously received by the petitioner as a return of capital and by reducing 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.  20The amendment thus provided for an allocation of the depletion between bonus and royalties. For example, where a lessor received a $ 1 million bonus, the anticipated royalties were estimated at $ 2 million, and the value to be recovered through depletion was $ 2 million, the regulation provided that one-third of that $ 2 million be recovered from the bonus and two-thirds from the royalties. Again, it should be noted that, under *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 and Murphy 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.  21 That treatment, as we have seen, provided that: (1) A lease bonus was part of the base upon which the lessee's cost depletion allowance was based; (2) the bonus was not part of the depletion base of the lessor to whom paid; but (3) the lessor was entitled to recover his depletion allowance(computed on a base which did not include the bonus) first from any bonus received and then from royalties, the amount of any bonus, to the extent it exceeded the depletion to be recovered, being treated as ordinary income taxable in full.With the enactment of percentage depletion in 1926, however, the whole depletion concept underwent radical alteration.  There no longer was any such thing as a "total" percentage depletion, ascertainable in advance, to be recovered from a mineral property.  The allowance became an "open-end" affair so that depletion is applicable so long as there is gross income from the property.  Thus, what had been previously a matter *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. 1138422 he ruledthat "a practical application of the law and regulations in the light of the language used in the 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.  23However, in Herring v. Commissioner, 293 U.S. 322 (1934), the Supreme Court specifically rejected the ruling in question, holding lease bonuses to be depletable without reference to the possibility of production. *327 The Court stated: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 in section 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 under section 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 in Herring 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.  24 This administrative construction was consistent with an interpretation of the statute and regulations thereunder to the effect that it was not the bonus itself which was subject to depletion but simply the cost (or alternative statutory basis) of the mineral property.  That this was the case is borne out by the requirement of article 216(a) (and of its predecessors) to the effect that the depletion recoverable from royalties must be reduced by any depletion previously deducted with respect to a bonus.Be that as it may, following the decision of Herring v. Commissioner, supra, the Commissioner ruled that, under the *330 Supreme *1048  Court's view, the distinction between bonuses for leases in proven and unproven areas could not be sustained and that a percentage depletion deduction was allowable in every case of a bonus payment received in advance of production.  25 However, in the same ruling, the Commissioner pointed out that:The grant of the deduction is in any case upon the ground of "a reasonable allowance for depletion." If on the termination of the lease there has been no production, then there has in fact been no depletion. Ordinarily the Government may recoup only by restoring the deduction to income and asserting the tax against the taxpayer in the year of the termination of the lease. Cost depletion on an advance royalty has always been allowed on condition that if the anticipated production does not materialize, the taxpayer will restore the amount of the deduction to income as of the year the lease terminates, expires, or is abandoned.  (See article 216(b) and (c), Regulations 69, with which all prior and subsequent regulationsare identical.) Since the "nature and purpose of the allowance is the same," as the Supreme Court has pointed out, whether the deduction be computed on the cost basis *331 or on a per cent of the gross income from the property, it follows that the taxpayer must be deemed to have taken the bonus depletion deduction on the percentage of income basis on the condition that he will restore the amount of such deduction to income as of the year of the termination of the lease where there has been no production from the leased premises.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.  26The regulations in question have received approval by the courts.   Douglas v. Commissioner, 322 U.S. 275">322 U.S. 275 (1944);Sneed v. Commissioner, 119 F. 2d 767 (C.A. 5, 1941), affirming 40 B.T.A. 1136">40 B.T.A. 1136 (1939); Crabb v. Commissioner, 119 F. 2d 772*332 (C.A. 5, 1941), affirming 41 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.  27 However, it has become established that any production whatsoever, no matter how minimal, will prevent operation of the restoration rule.  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.  In G.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: 28As the mineral *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." 29Similarly, since it had become established law that a bonus was subject to percentage depletion in the hands of the lessor and since depletion cannot exceed production ( Helvering v. Twin Bell Syndicate, supra), it necessarily followed that the lessee's depletion base had to be reduced by an equivalent amount.  See also Kirby Petroleum Co. v. Commissioner, 326 U.S. 599">326 U.S. 599 (1946). For example, where a lessor reserves a right to the usual one-eighth share of production, receiving in addition a $ 100,000 cash bonus at the time of execution of the lease, and the lessee receives a right to the remaining seven-eighths of production, the lessor computes his depletion allowance on the basis of his one-eighth interest in the oil and gas produced plus $ 100,000.  Consequently, the lessee's "gross income from the property" for purposes *335 of his depletion base could not be his seven-eighths share of actual production but rather that amount less 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: 30In all cases there shall be excluded in determining the "gross income from the property" an amount equal to any rents or royalties which were paid or incurred by the taxpayer in respect of the property and are not otherwise excluded from the "gross income from the property." If royalties in the form of bonus payments have been paid in respect of the property in the taxable year or any prior years, or if advanced royalties have been paid in respect of the property in any taxable year ending prior to December 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 that part of such payments which is allocable to the product sold during the current taxable year.  If advanced royalties have been paid in respect of the property in any taxable year ending on or after December *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 962 (C.A. 10, 1945), affirming 3 T.C. 251">3 T.C. 251 (1944); Canadian River Gas Co. v. Higgins, 151 F. 2d 954 (C.A. 2, 1945); Quintana Petroleum Co. v. Commissioner, 143 F. 2d 588 (C.A. 5, 1944), affirming 44 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, in Quintana Petroleum Co. v. Commissioner, supra, the court said (143 F.2d 588">143 F. 2d 588, 591):Under Helvering 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 the Sunray Oil Co. and Canadian 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. There has been no subsequent decision to the contrary.  Therefore, at least insofar *339 as the lessor is concerned, the question must be considered closed.  This being the case, there can be no alternative to sustaining the respondent's regulation requiring the reduction of the lessee's gross income from the property by that portion of a cash bonus previously paid which is allocable to production in the taxable year.  Such a result conforms to the statutory requirement that, in the case of leases, the depletion allowance "be equitably apportioned between the lessor and lessee," 31 and conforms to the rule that there can only be one allowance for depletion with respect to a given barrel of oil (or other unit of production).  32In addition to the contention just rejected that a cash bonus should not be deducted from its gross income from the property for depletion purposes, the petitioner also contends in thealternative that, as payor, it should be permitted to exclude from gross income (for tax purposes) either the entire bonus in the year paid or a portion thereof determined by spreading the bonus over the life of the lease. Since, as early as Burnet v. 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.  33 In so holding, the courts have pointed to the example of a manufacturer to whom the proceeds of *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.  34*341 Of 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." 35 It is this latter provision which the petitioner here seeks to have us invalidate.  Understandably, the regulatory assurance of recovery "through the depletion allowance" provides but scant comfort to the lessee who must, pursuant to other provisions of the same regulations, exclude from the base for his depletion allowance the very amount he is told he can only recover by virtue of that same allowance. In the Sunray Oil Co. and Canadian River Gas Co. cases, the courts rationalized this result on the ground that, since the lessee's basis for cost 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. 36In any event, the overall tax treatment of income and expenditures with respect to mineral properties would seem devoid of any such clear pattern as would establish a fixed and consistent relationship between expensing, capitalizing, and the depletion allowance. For example, a taxpayer may, at his option,  expense or capitalize so-called "intangible drilling and development costs," 37 although, like expenditures for physical property (recoverable through depreciation), they would seem clearly to be capital in nature and represent part *1053  of the cost basis of the property.  United States v. Dakota-Montana Oil Co., 288 U.S. 459">288 U.S. 459 (1933).If the taxpayer elects *343 to capitalize his intangible drilling and development costs, the regulations providing the option have required uniformly that the amounts so capitalized are "returnable through depletion," 38 as is the case with respect to bonus expenditures, although here, such recovery would seem to have considerably more substance because, unlike in the case of the bonus, there is no provision in the regulations or elsewhere for a pro tanto reduction in the "gross income from the property."So-called "geological and geophysical exploration expenditures" must be capitalized, with no expensing option available.  Louisiana Land & Exploration Co., 7 T.C. 507 (1946),affirmed on other issues 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, 39 and advantageous treatment which would indeed seem to provide for a form of double recovery. Thus, the treatment accorded a bonus in the hands of the lessee clearly would seem less liberal than that accorded the other types of expenditure just described, all of these disparate treatments being found in regulations rather than in the statute.  Therefore, at the least, it would not seem of controlling significance that some doubling up of tax benefits might result, as suggested in the 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 542 (C.A. 5, 1956).  Under the facts of that case, a sulphur company, which previously had agreed by contract to pay $ 7,500 per quarter for sulphur rights acquired under the contract, entered into a subsequent agreement with the taxpayer whereby the taxpayer agreed to assume the $ 7,500 quarterly payments (in addition to other obligations) and, in return, acquired the right to explore and otherwise develop the property in question and produce sulphur.  The issue fordecision was whether the taxpayer, the owner of sulphur rights under the contract *1054  "having many attributes of a mineral lease, was entitled, for income tax purposes, to deduct fixed rentals payable periodically during the primary term of the lease; or whether such amounts should be capitalized as leasehold costs." The taxpayer contended that the quarterly payments were deductible as lease rentals 40 and maintained, in the alternative that, if the payments were construed *346 to be bonuses, they should be treated as advance royalties under Burton-Sutton Oil Co. v. Commissioner, supra, and excluded in full from the taxable income.It is apparent from a reading of the opinion, including that of the trial court, 41 that there are many factual dissimilarities between the situation there under consideration and that presented by the instant case.  Moreover, while the trialcourt held the payments in question not to be delay rentals but excludible as advance royalties, the Court of Appeals, in addition to sustaining the result reached by the court below "on the grounds assigned by it," also held the payments deductible as delay rentals.  Nevertheless, despite rather clear distinctions between the 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," citing Bankers' Pocahontas Coal Co. v. Burnet, 287 U.S. 308">287 U.S. 308 (1932); Burnet v. Harmel, Murphy Oil Co. v. Burnet, and Palmer v. Bender, all supra.  From this premise the court concluded that those same payments "should be excludable as such [advance royalties] by the lessee," on the authority of Burton-Sutton Oil Co. v. Commissioner, supra.The court recognized that the result reached was contrary to the earlier decisions in the Sunray Oil Co., Canadian River Gas Co., and Quintana Petroleum Co. cases, but considered their authority to have been superseded by the more recent Supreme Court decision in Burton-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.  42As an arrangement involving the sharing of net profits, 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 in Burton-Sutton, that they were advance royalties to the lessee and as such deductible in their entirety in the year paid.  43 In 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 cited Burnet v. Harmel, Bankers' Pocahontas Coal Co. v. Burnet, Murphy Oil Co. v. Burnet, and Palmer v. Bender, all supra, 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.  44 However, a careful examination of the authorities suggests *1056  that the labeling of bonuses as "advance royalties" has been more fortuitous than otherwise.  For example, the opinion in Burnet 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.  In Murphy 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 the timing 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,the Court referred to a bonus as "a payment in advance for oil and gas to be extracted." Later, in Anderson v. Helvering, supra, the Supreme Court did state:Cash bonus payments, when included in a royalty lease, are regarded as advance royalties, and are given the same tax consequences.  45As authority for that statement, the Court cited the same cases just discussed.  Certainly 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 in Burton-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 in Burton-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, the petitioner also contends for the annual deduction from gross income of a proportionate part of the bonus, based upon the anticipated productive life of the lease. Such an alternative form of recovery would at least be consistent with the capital investment status of a bonus and with the treatment accorded a cash bonusin the case of the ordinary real estate lease. However, as we have seen, the regulations make no provision for such a deduction, providing merely that recovery is to be through depletion.*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. 435 (1934). *356 This the petitioner here cannot do.The 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, 46 applicable to years beginning after December 31, 1941; in Treasury Regulations 118, 47 applicable to years beginning after December 31, 1951; and in Income Tax Regulations 48 applicable to years after December 31, 1953.  The basic provisions of law applicable to the taxation of income with respect to mineral properties were reenacted, subsequent to the adoption of the rule in regulations, in the Internal Revenue Code of 1939 and the Internal Revenue Code of 1954.  In view of this unusually long history of readoption of the regulation in question, involving no legislative enactment to the contrary, we find no alternative to upholding the regulation. In reaching this conclusion we are not unmindful of the fact that Congress has made an express delegation of authority *357 to make rules and regulations in this entire area.  49This conclusion has strong support in the fact, as pointed out above, that the regulations in question have been upheld by the Second Circuit in Canadian River Gas Co. v. Higgins, supra; by the Third Circuit in Baton Coal Co. v. Commissioner, 51 F. 2d 469 (C.A. 3, 1931); by the Fifth Circuit in Quintana Petroleum Co. v. Commissioner, 50 supra, and by the Tenth Circuit in Sunray Oil Co. v. Commissioner.  While Burton-Sutton was decided by the Supreme Court subsequent to those decisions, the rule in question was restated in Treasury Regulations 118 and in Income Tax Regulations, both of which were *1059  promulgated a number of years after the decision in Burton-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.  Footnotes1. 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. 555, 173 So. 103">173 So. 103 (1937), wherein the lease provided that the lessor should be paid" (1/8) of the value↩ 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, 622 (1944), wherein it was said: "It is held in Louisiana that the market price under such leases is to be ascertained at the wellhead, if there is an established market price at that point.  Unfortunately, this rule requires that the price for royalty purposes be ascertained at a place and time at which few commercial sales of gas occur.  The lessees who market this royalty gas along with their own production do not customarily make their deliveries at the wellhead but transmit gas from the several wells some distance in gathering lines, turning it over to large buyers at points somewhat removed, and under conditions of delivery different from wellhead deliveries.  The price producers receive at these delivery stations often is substantially above the 3 cents price to the landowner.  The practice of fixing the price of landowner's royalty gas at one time and place and of marketing his gas for a different price at another delivery point raises the dissatisfaction and problems which produce this case."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 also Continental Oil Co. v. United States, 184 F. 2d 802, 817↩ (C.A. 9, 1950), footnote 6.7. 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-eighth of 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 of net 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. 160, 254 S.W. 290">254 S.W. 290 (1923), and Tidewater Associated Oil Co. v. Clemens, 123 S.W. 2d 780 (Tex. Civ. App., 1938).  This is the view of the Texas law held by the United States Court of Appeals for the Fifth Circuit.  See Phillips Petroleum Co. v. Bynum, 196">155 F. 2d 196, 199↩.9. 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. 404, 407; Euleon Jock Gracey, 5 T.C. 296">5 T.C. 296, 302; Kirby Petroleum Co. v. Commissioner, supra.Whether the instrument creating the rights is a lease, a sublease or an assignment has not been deemed significant from the federal tax viewpoint in determining whether or not the taxpayer had an economic interest in the oil in place. Palmer v. Bender, 287 U.S. 551">287 U.S. 551, 557, 558. Nor has the title to the oil in place been considered by this Court as decisive of the capital investment of the taxpayer in the oil. Technical title to the property depleted would ordinarily be required for the application of depletion or depreciation.  It is not material whether the payment to the assignor is in oil or in cash which is the proceeds of the oil, Helvering v. Twin Bell Syndicate, 293 U.S. 312">293 U.S. 312, 321, nor that some of the payments were in the form of a bonus for the contract. Burnet v. Harmel, 287 U.S. 103">287 U.S. 103, 111; Murphy Oil Co. v. Burnet, 287 U.S. 299">287 U.S. 299, 302↩. * * *"16. 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 by G.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↩ (C.A. 5, 1945), referred to the allowance in such a case as "synthetic depletion."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↩.32. Helvering v. Twin Bell Syndicate, supra↩.33. Sunray Oil Co. v. Commissioner, 147 F. 2d 962, and Canadian River Gas Co. v. Higgins, 151 F. 2d 954↩, Judge Learned Hand dissenting on this point in the latter case.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↩ (C.A. 5, 1956)) case would seem to follow.  For example, the amount of the payment would no longer be part of the lessee's basis in the property and, thus, not part of the base for cost depletion nor recoverable on abandonment.44. This Court is no exception.  For example, see Westates Petroleum Co., 21 T.C. 35">21 T.C. 35, 39↩ (1953).45. 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 recent Jefferson Lake Sulphur Company↩ case.