Case ID: tc_35/html/0979-01.html
Source: Caselaw Access Project
Author: {"author": "Tkain, Judge:\n    ", "license": "Public Domain", "url": "https://static.case.law/"}
Date Created: 2024-08-24T03:29:51.129683

The Shamrock Oil and Gas Corporation, Petitioner, v. Commissioner of Internal Revenue, Respondent.
    Docket Nos. 49145, 61315, 68580, 77791.
    Filed March 24, 1961.
    
      'Wright Matthews, Esq., W. M. Sutton, Esq., H. A. Berry, Esq., and Ed H. Selecman, Esq., for the petitioner.
    
      Boy E. Graham, Esq., and Alien T. Ahin, Esq., for the respondent.
   Tkain, Judge:

Respondent determined deficiencies in the petitioner’s income and excess profits taxes for the years and in the amounts as follows:

Dochet No. ⅛91⅛5.

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 finally allowed, for 1943 through 1947, are set forth below:

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 issue the amount of the depletion allowance to which it was entitled for each of the fiscal years 1943 through 1947. By a first amended petition, Shamrock contends that the “gross income from the property” at the wellhead, for depletion purposes, in terms of price per thousand cubic feet of gas (MCF) was as follows:

1943- $0.028497
1944- .029895
1945- .031314
1946- .036468
1947- . 051986

This amount of gross income from the property, in terms of price per MCF, is proposed by Shamrock as the amount for which it sold the gas in the immediate vicinity of the well and as the representative 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.

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:

Shamrock makes the further allegation in its first amended petition filed in this docket that in the event it is mistaken in its allegations as to the proper method of determining the gross income from the property, then according to the peculiar 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 casing-head gas in the gasoline extraction plants operated by petitioner” during the years in question. Gross income from the property so calculated by Shamrock for each of the years in issue in this docket is as follows:

1943_$1,198,171.65
1944_ 1,336,266. 35
1945_ 1, 797, 581.40
1946_ 2, 588,789. 75
1947_ 3, 766,485.54

Docket Nos. 61315, 68580, and 77791.

I. Depletion Issue.

The respondent determined deficiencies with respect to depletion and other issues for the fiscal years ending November 30, 1948, through November 30, 1954. All issues raised by the respondent, other than the depletion issue, have been settled by the parties and the settlement thereof is to be given effect under Rule 50.

As regards the depletion allowance, the amounts claimed by Shamrock in its returns are as follows:

1948_$1,438,862.76
1949_ 1,784, 807. 95
1950_ 1, 739, 701. 77
1951_ 1,776, 849. 81
1952_ $1,725,296.81
1953_ 1, 986, 442. 36
1954_ 2, 687, 770.

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 residue gas and the proceeds from the sale of 40 percent of the liquid hydrocarbons extracted from the gas constituted the gross income from the property.

In the respective statutory notices of deficiency respondent disallowed deductions for depletion in the following amounts:

1948_ $427,905.15
1949_ 481,257.89
1950_ 397,392.97
1951_ 303,757. 97
1952_$229,111.41
1953_ 303,286. 93
1954_ 507,592.57

The basis of respondent’s action was that the gross income of the gas leases, in his opinion, was the equivalent of the market or field price before the conversion or transportation of the gas produced. This market or field price (per MCF) has been finally determined by the respondent to be the following:

Shamrock, in its first amended petition in these dockets, alleges that the amount of depletion claimed on its returns was less than the amount of depletion to which it was entitled. Claim is accordingly made by Shamrock that its income tax for the fiscal years 1948 through 1954 was overpaid. The amounts of overpayment are alleged to be not less than the following amounts:

1948_ $23, 065.45
1949_ 33,473.60
1950_ 73,972. 51
1951_ 131, 877. 66
1952- $153,224.35
1953- 132, 994. 75
1954- 113, 831. 99

Shamrock contends that the gross income from the property at the wellhead, for depletion purposes, in terms of price per MCF, was as follows:

1948_ $0.081003
1949_ .067785
1950_ .062656
1951_ . 070763
1952_ $0.072186
1953- . 079313
1954_ . 087243

This amount of gross income from the property, in terms of price per MCF, is proposed by Shamrock as the amount for which it sold the gas in the immediate vicinity of the well and as the representative market or field price of the gas. Alternative amounts of gross income for each of the fiscal years in issue are proposed by Shamrock as the representative market or field price if the same is to be determined by other sales. These amounts are set forth to be not less than 6½ cents per MCF for each of the years 1948, 1949, and 1950, 7½ cents per MCF for 1951, 8 cents per MCF for 1952,8½ cents per MCF for 1953, and 9½ 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:

In these dockets, Shamrock makes the same further allegation as it made in Docket No. 49145, that is, that in the event it is mistaken in its allegations as to the proper method of determining the gross income from the property, the gross income should be the proceeds from the sale of the residue gas plus a sum equal to an amount not less than 58.8 percent of the proceeds of all natural gasoline. Gross income so calculated by Shamrock is the following:

1948_$6,112, 670.52
1949_ 7, 367, 760. 86
1950_ 7, 235, 829.79
1951_ 7,625,687.71
1952_$7,569,782.93
1953_ 7, 505, 966. 84
1954_ 8, 987, 914.26

II. 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.

The amounts in issue in respect of the bonuses paid and the alleged overpayments of income tax are as follows:

Entire amount First Contention: deductible Overpayment
1948- $276,441.11 $105,047.62
1949- 177, 630.31 67,499. 51
1950_ 287, 024. 73 117, 479. 22
1951- 30, 266. 20 15, 201.20
1952- 168, 728.19 87, 738. 66
1953- 302, 237. 68 157,163. 59
1954- 408, 387. 75 212,361. 63
Second Contention: Proportionate amount deductible Overpayment
1948_ $17, 006. 30 $6,462.43
1949- 18, 331. 85 6, 966.10
1950- 19, 920. 90 8,153. 62
3951- 21,713.41 10,905.56
1952- 24, 532. 01 12, 756. 95
1953- 28,829.12 14,991.14
1954- 83, 756.15 17, 553. 20
Third Contention Capital investment Amount deducted from “gross income from the property” (iallocate part) Loss in percentage depletion allowance Overpayment
1948_ $276, 441. 11 $17, 006. 39 $4, 676. 76 $1, 777. 17
1949_ 177, 630. 31 18, 331. 85 5, 041. 26 1, 915. 68
1950_ 287, 024. 73 19, 920. 90 5, 478. 25 2, 242. 25
1951_ 30, 266. 20 21, 713. 41 5, 971. 18 2, 999. 03
1952__ 168, 728. 19 24, 532. 01 6, 746. 30 3, 508. 07
1953_ 302, 237. 68 28, 829. 12 6, 003. 01 2, 375. 13
1954.. 408, 387. 75 33, 756. 15 9, 282. 94 4, 827. 13

The issues 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 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, 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 of 1943, 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 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 County and 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 Hugo-ton field. There is no physical separation between the fields designated as the East Panhandle field, the West Panhandle field, the Texas Hugoton, 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 connected until about 1946 when sufficient wells had been drilled to definitely establish the connection between them.

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 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 approximately 5,500,000 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 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 lower in 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 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 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 richer gas 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. 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.

Haw gas is the gas as it comes from the well. Paw 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 principally of 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 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.

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 all of 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 sour gas or sweet gas. Sour gas is natural gas having more than 1½ 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 the West 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., 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.

Drip gasoline is a term applied to the liquefiable hydrocarbons which take on a liquid form in the gathering lines as a 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 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 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 interests in 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.

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 from 1926 to 1954, broken down into the different type gas properties, is set forth in the schedule below:

During all of the period from 1943 through 1954, it was Shamrock’s practice to expand its acreage holding, both producing and nonproduc-ing, to the extent it was economically able to do so. The reason for increasing both producing and 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 Fiscal Years 1944 Through 1954.

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 obtain more 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 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:

Production was commenced on these several properties at different times during the years. Production starts, or wells which commenced to produce, are shown by year and type of gas produced:

The number of properties from which gas was produced in the years in issue was as follows:

The following table shows the number of Shamrock wholly or partially owned wells in the West Panhandle and Hugoton gasfields which were connected to the McKee and Sunray plants at the end of the fiscal years 1943 through 1954 and the distances of such wells from those plants:

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 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:

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 said land and sold or used oft 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:

Subsequent to October 1, 1945, Shamrock endeavored to simplify its accounting to royalty owners and in place of the many different royalty 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 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:

The following table sets forth the same data with respect to overriding royalties:

In all, or practically all, of the cases where Shamrock had 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:

The following table shows a detailed breakdown of gas purchased from the working interest of others in Shamrock leases (1943-1954) in terms of MCF and price per MCF:

The following schedule shows the weighted average paid for gas purchased from the working interest of others in Shamrock leases:

In addition to purchasing gas from the working interests of others in its leases, Shamrock purchased casinghead gas during some of the years in issue. These purchases, by year, are set forth below:

These casinghead gas purchases by Shamrock (1947 through 1954) in terms of MCF and price per MCF are set forth in detail in the following table:

Following is a schedule of the weighted average price paid for casinghead gas purchased by Shamrock in terms of MCF:

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, first under miscellaneous contracts excepting the Continental Oil contract, and second under the Continental Oil contract, follows:

Shamrock’s sour gas purchases from the Continental Oil Company for the years ended November 30, 1948 through 1954 were as follows:

Following is a schedule of sour gas and sweet gas purchased under miscellaneous contracts by Shamrock for the years 1943 through 1954 in terms of MCF and price per MCF:

The 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:

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 sour gas was not suitable for pipeline purposes. At that time, sour gas wells were shut in as a general rule. Casinghead gas, however, 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 of carbon black, provided the liquefiable hydrocarbons were first extracted, and provided that the carbon black plant averaged a production yield of at 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 Ho. 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 determined by the Bailroad 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 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 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 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 according to 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 plant known as its McKee Gasoline Plant located on Section 399, Block 44 H&TC Ey. 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 Ey. 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 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 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 production is 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 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, in 1944 Shamrock sold most of its sweet gas producing wells 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. Ko 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, 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 cooled and 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. 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 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° 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 iso-pentanes are separated in the same manner as 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 may be 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, 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.

Residue gas may be either sweet or sour gas. Where raw 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 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 similar to 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 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:

The following table shows a percentage analysis of the disposition by years by Shamrock of total available raw gas:

From 1943 to 1954, inclusive, Shamrock either sold the liquefied hydrocarbons which were extracted from the raw gas to others or transferred them to Shamrock’s refinery. These transfers to the refinery were treated as intercompany sales and a price was set by Shamrock for these sales.

A major portion of the natural gasoline extracted by Shamrock from 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 consist of 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:

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:

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 construct or 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.

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 Eeliance 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 committed to each of these 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, Eeliance 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 miles from the McKee Plant and Continental Carbon purchased residue gas from Shamrock from 1943 to 1954, inclusive.

In June 1936, Eeliance Carbon Company built a plant 0.014 of a mile from the McKee Plant and Eeliance 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 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 carbon company should elect to move its 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 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 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 had increased from what it was in 1936.

During the period 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) Canadian River 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 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 Paso Natural 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 such long-term supplies, the pipeline companies acquired leases on large blocks of acreage in the Panhandle field and produced gas from their own acreage.

With one exception, that is, the 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 1930⅛, 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. The pipeline companies would not purchase sour gas because of the corrosive effects of the 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 Field it was located close to existing pipeline facilities. Panhandle Eastern Pipeline Company 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 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 intercom-pany 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 of the raw gas was at the well mouth, except two purchase contracts stipulated by the parties as not to be 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.

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:
⅜ * * * * ⅜ ⅜
(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 conditions in each case; 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 27⅛ 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 to the years 1943 through 1954, contain the following material relevant to this issue:

The term “gross income from the property,” as used in sections 114(b) (3) and 114(b) (4) (A) ⅜ * ⅜ 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 Eevenue Act of 1926 have contained substantially the same language as that quoted above.

Early in the history of percentage depletion on oil and gas the question arose as to the point at which the “gross income” was to be measured. It was decided, and not contested here, that this point was the well mouth and that the “gross income from the property” was the gross income from the sale of the mineral at that point. Brea Canon Oil Co., 29 B.T.A. 1134 (1934), aff'd. Brea Oanon Oil Co. v. Commissioner, 77 F. 2d 67 (C.A. 9, 1935); Signal Gasoline Corporation, 30 B.T.A. 568 (1934), aff'd. 77 F. 2d 728 (C.A. 9, 1935); Greensboro Gas Co., 30 B.T.A. 1362 (1934), aff'd. 79 F. 2d 701 (C.A. 3, 1935); Consumers Natural Gas Co., 30 B.T.A. 1263 (1934), aff'd. 78 F. 2d 161 (C.A.2,1935).

The regulation, which both petitioner 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 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 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 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 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 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, 730 (C.A. 10, 1956), the United States Court of Appeals for the Tenth Circuit said:

“Prevailing field price” lias 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 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 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 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 price was 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 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.

In 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 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 to establish the value of the gas would not be admissible.

In Shamrock Oil & Gas Corporation v. Cofee, 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 of ⅜ 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.[]

What 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 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 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.
* ⅜ * 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 substantially similar to that of the gas here involved. * ⅝ * 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. * * *
⅜ * * Certain features of eases 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 to ascertain 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, will require the lessee to pay the reasonable value of such part of lessor’s property as has been taken theretofore.
* ⅜ ⅜ 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.
* ⅛ * * * * *
* * * Under the evidence in this case the only substantial market for the plaintiffs’ gas is that afforded by plants that 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 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” 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 the ascertainment of the representative market or field price as the regulations intended. Bather, 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).

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.

Bespondent has combined the weighted average price paid by petitioner in each of the years in issue for this gas so acquired and has 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, 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 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. 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 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 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 hi 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 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 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 companies during the years in 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 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 actually paid 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 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 da Gas Corporation v. Cofee, 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, 382 (1938). “The amount of depletion allowable to producers may 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, 730 (1948).

Although in the case of integrated producers who manufacture or convert oil or gas 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 representative market 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. 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 market value 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 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 production of 1,164,328 MCF) 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 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 the respondent 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 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 transportation is 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 ⅜ * ⅜ 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 buyers for raw gas. Includible in this weighted average, under the facts of this case, are the prices paid by 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 (1932).

In the ordinary oil and gas lease, the lessor reserves a royalty interest, commonly one-eighth, in any production from the property which follows its exploitation. The word “royalty” as used in such a lease generally refers to 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, 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 (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 greater detail, may be summarized 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 deducted1 from the “gross income from the property” upon which percentage depletion is computed, 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 paid or incurred; (2) alternatively, petitioner 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 with such bonuses in the hands of the lessor-recipient. 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. Rejecting this conclusion and refusing to be bound by technical differences in the property laws of the several States, 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 statute authorizes a depletion allowance upon the royalties alone. See Ferguson v. Commissioner, 45 F. (2d) 573, 577. But bonus payments to the lessor Rave 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 P. (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; Burkett v. Commissioner, 31 F. (2d) 667, and see the same case before the Board of Tax Appeals, 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 payments by 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, 357-358.

The above-quoted language 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 (1932), which involved specifically the computation of the depletion deduction, the Court said (at p. 302) :

We think it no longer open to doubt that when 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. Karmel, 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 provides. ⅜ * *

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 feroentage depletion, an allowance which, in the case of oil and gas wells, was first provided by the Revenue Act of 1926. The significance of this fact will receive further comment below.

In any event, the rule that a cash bonus was ordinary income de-pletable in the hands of the lessor became firmly established. See Palmer v. Bender, 287 U.S. 551 (1933) ; Anderson v. Helvering, 310 U.S. 404 (1940); Burton-Button Oil Co. v. Commissioner, 328 U.S. 25 (1946). 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 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. 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 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 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. 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 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, nor the Court of Appeals, mentioned such an issue or alluded to the subject of depletion 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 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 royalties received in later taxable years.”

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 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 recoverable through depletion deductions on the basis of royalties thereafter received.[]

The 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 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. Eeceipt of a bonus essentially only affected the timing of the lessor’s depletion recovery. It is apparent 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 as early as his regulations under the 1918 Act. 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 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 toot a position with respect to applicability of percentage depletion to lease bonuses. In G.C.M. 11384 he ruled that “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.

However, 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. 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. ⅜ * * [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 compute it under section 204(e), 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, 327,328.]

Thus, even if we were to assume that 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 termination of the lease, on account of bonus paid at tbe execution of the lease, if no mineral has then been extracted, we express no opinion. [293 U.S. 322, 328.]

Previously, in 1927, the Commissioner had ruled in this connection that article 216(a) of Eegulations 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. 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 Supreme Court’s view, tbe 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. 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 (e), Regulations 69, with which all prior and subsequent regulations are 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 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.[]

The regulations in question have received approval by the courts. Douglas v. Commissioner, 322 U.S. 275 (1944); Sneed v. Commissioner, 119 F. 2d 767 (C.A. 5, 1941), affirming 40 B.T.A. 1136 (1939); Crabb v. Commissioner, 119 F. 2d 772 (C.A. 5, 1941), affirming 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. However, it has become established that any production whatsoever, no matter how minimal, will prevent operation of the restoration rule. Crabb v. Commissioner, supra.

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-fayee, 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, 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:

As the mineral 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’s mineral 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 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.”

Similarly, 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 (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 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 in the regulations applicable to the taxable years here at issue as follows:

In 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 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 bands 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 (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 (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 “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, 591) :

Under Helvering v. Twin Bell Syndicate, 293 U.S. 312, 55 S. Ot. 174, 79 B. 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, 966, 967) :

The lessee of an oil and gas lease may elect between cost and percentage depletion in a particular tax 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 ease, 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 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,” 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) .

In 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 the alternative 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 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. In so holding, the courts have pointed to the example of a manufacturer to whom the proceeds of the sale 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.

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.” 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 includes the amount of a bonus, any additional exclusion by way of deduction of a portion of the bonus annually, would be tantamount to 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.

In 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,” although, like expenditures for physical property (recoverable through depreciation), they would seem clearly to be capital in nature and represent part of the cost basis of the property. United States v. Dakota-Montana Oil Co., 288 U.S. 459 (1938). If the taxpayer elects 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,” 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 tcmto 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); 1950-1 C.B. 48. Here, too, there is no adjustment of the base for percentage depletion.

Finally, where the taxpayer exercises his option to expense intangible drilling costs, there again is no reduction of the base for percentage depletion, 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 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 for decision was whether the taxpayer, the owner of sulphur rights under the contract “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 and maintained, in the alternative that, if the payments were construed 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, that there are many factual dissimilarities between the situation there under consideration and that presented by the instant case. Moreover, while the trial court 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 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 advance royalties by the lessor,” citing Bankers’ Pocahontas Coal Co. v. Burnet, 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 Sumray Oil Co., Canadian River Cas 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 both the operators who make them and the owners, lessors, vendors, grantors, however they may be classed, who received them. If they are capital 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 hy the other. ⅞ * * [Emphasis added.]
* * * * * * *
* * ⅜ 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 mate 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.[]

As 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 the District Court in the latter 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.

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 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. However, a careful examination of the authorities suggests 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 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:

Gash bonus payments, when included in a royalty lease, are regarded as advance royalties, and are given the same tax consequences.[]

As 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 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 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 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 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 of many 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 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 bonus in 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.

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 (1934). 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 depletion allowance was reiterated in Treasury Regulations 111, applicable to years beginning after December 31, 1941; in Treasury Regulations 118, applicable to years beginning after December 31, 1951; and in Income Tax Regulations 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 to make rules and regulations in this entire area.

This 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 Rimer 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, supra, and by the Tenth Circuit in 8unray 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 promulgated a number of years after the decision in Burton-Button. To hold otherwise now, would be to ignore the fact that Congress has reposed the regulatory authority in the. Secretary of the Treasury or 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 vmder Bide 50 
      
       Regs. Ill, sec. 29.23(m)-l(f), for the period through December 31, 1951, and Regs. 118, sec. 39.23(m) — 1(e) (1) and sec. 39.23(m)-l(e) (2).
     
      
       See. 204(c)(2) of tie 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)-l (1935) ; Regs. 94, art. 23(m)-l(g) (1936) ; Regs. 101, art. 23(m) — 1(g) (1939); Regs. 103, sec. 19.23(m)-l (f) (1940); Regs. Ill, sec. 29.23 (m) — 1(f) (1943) ; Regs. 118, sec. 39.23(m)-l(e) (1) (1953).
     
      
       See footnote 1, supra.
      
     
      
       Cf. Sartor v. United Gas Public Service Co., 186 La. 555, 173 So. 103 (1937), wherein the lease provided that the lessor should be paid “(⅜) 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.”
     
      
       See the dictum of the united States Supreme Court in Sartor v. Arkansas Gas Corp., 321 U.S. 620, 622 (1944), wherein it was said: “It is held in Louisiana that the market price under such leases is to he 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 3tf 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.’ ”
     
      
       140 F. 2d at 410. See also Continental Oil Co. v. United States, 184 F. 2d 802, 817 (C.A. 9, 1950), footnote 6.
     
      
       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.)
     
      
       See Stephens County v. Mid-Kansas Oil & Gas Co., 113 Tex. 160, 2, 54 S.W. 290 (1923), and Tideioater Associated Oil Co. v. Clemens, 123 S.W. 2d 780 (Tex. Civ. App., 1938). This is the vie-w of the Texas law held, by the united States Court of Appeals for the Fifth Circuit. See Phillips Petroleum Co. v. Bynum, 155 F. 2d 196, 199.
     
      
       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 ⅜ percent of 7 cents, or 1.925 cents, and at a tax rate ofi 52 percent result in a tax saying of 1.001 cent from which the additional payment of li cent must be subtracted to arrive at the net benefit. Furthermox-e, 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.
     
      
       56 F. 2d 153 (C.A. 5, 1932).
     
      
      See also Bankers’ Pocahontas Coal Co. v. Burnet, 287 U.S. 308 (1932).
     
      
      Revenue Act of 1926, sec. 204(c) (2). The Act made the depletion provisions effective as of January 1,1925, sec. 286.
     
      
       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.)
     
      
       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.)
     
      
       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, 407; Euleon Jock Gracey, 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, 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, 321, nor that some of the payments were in the form of a bonus for the contract. Burnet v. Harmel, 287 U.S. 103, 111; Murphy Oil Co. v. Burnet, 287 U.S. 299, 302. * * *”
     
      
       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.
     
      
       See footnote 12, supra.
      
     
      
       19 Ii.T.A. 376 (1930).
     
      
       56 F. 2d 153 (1932).
     
      
       T.D. 3938, V — 2 C.B. 117 (1926) ; Regs. 69, art. 216(a), under Revenue Act of 1926.
     
      
       See footnote 16, supra.
      
     
      
      XII-1 C.B. 64 (1933), revoked by G.C.M. 14448, XIV-1 C.B. 98 (1935).
     
      
       See Baker, “The Nature of Depletable Income,” 7 Tax L. Kev. 267, 274 (1952).
     
      
       I.T. 2861, VI-1 C.B. 78 (1927).
     
      
       G.C.M. 14448, XIV-1 C.B. 98 (1935).
     
      
       Regs. Ill, sec. 29.23(m)-10(e) ; Regs. 118, sec. 39.23(m)-10(e).
     
      
       The Court in Driscoll v. Commissioner, 147 F. 23 493 (C.A. 5, 1945), referred to the allowance in such a case as “synthetic depletion.”
     
      
       1941-1 C.B. 214, 217.
     
      
       Regs. Ill, see. 29.23(m)-10(a) ; Regs. 118, sec. 39.23(m)-10(a) ; see. 1.612-3(a) (3). Income Tax Regs.
     
      
       Regs. Ill, sec. 29.23(m)-l(f) (4) ; Regs. 118, sec. 39.23(m)-1(e) (5). The two regulations are identical. The regulations promulgated under thel954 Code (sec. 1.613-2(c) (5) (ii)) refer to “bonus payments” rather than to “royalties in the form of bonus payments.”
     
      
       See. 23(m), I.R.C. 1939 ; sec. 611(b) (1), I.E.C. 1954.
     
      
      
        Belvering v. Twin Bell Syndicate, supra.
      
     
      
      
        Sunray Oil Co. v. Commissioner, 147 F. 2d 962, and Canadian River Gas Co. v. Biggins, 151 F. 2d 954, Judge Learned Hand dissenting on this point in the latter case.
     
      
       See 2 Mertens, Law of Federal Income Taxation, sec. 12.31; Id. at yol. 4, see. 25, 27; and cases cited therein.
     
      
       See footnote 20.
     
      
       See sec. 114(b) (3), 1939 Code ; sec. 613(a), 1954 Code.
     
      
       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 actuaUy drilling the well. Mertens, op. cit. supra, vol. 4, sec. 24.48b ; Regs. 118, see. 8».23(m)-16(a)«(l).
     
      
       For example, Regs. 118, see. 39.23 (m)-16(b) (1).
     
      
       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 60 percent of net income limitation on the depletion allowance. Regs. 118, sec. 39.23(m)-l(g) ; sec. 1.614-4, Income Tax Regs.
     
      
       Deductible in full under section 23(a)(1)(A) of the 1939 Code as ordinary and necessary business expenses.
     
      
       133 F. Supp. 197 (195S).
     
      
       The quotation is a composite of language appearing on pages 27, 32, and 35 of 328 TJ.S.
     
      
       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.
     
      
       This Court Is no exception. For example, see Westatee Petroleum Co., 21 T.C. 35, 39 (1953).
     
      
       See footnote 14, supra.
      
     
      
       See. 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.
     
      
       Sec. 39.23(m) — 10(a).
     
      
       Sec. 1.612-3 (a) (3). These regulations were promulgated subsequent to enactment of the Internal Revenue Code of 1954.
     
      
       Sec. 23(m), 1939 Code; sec. 611, 1954 Code.
     
      
       The Fifth Circuit may have overruled Quintana in its more recent Jefferson Lake Sul-phur Company case.