35 T.C. 979">*979 Respondent determined deficiencies in the petitioner's income and excess profits taxes for the years and in the amounts as follows:

35 T.C. 979">*980 Docket No. 49145.

The parties have settled the excess profits tax issue and all standard issues other than depletion contained in this docket.

No deficiencies with respect to depletion were found by respondent for the fiscal years ending November 30, 1943, through November 30, 1947.

The respondent, as to each of these years, either agreed to the depletion allowance claimed by Shamrock in its returns or he allowed an additional depletion allowance. The amounts claimed in the returns, and the amounts 1961 U.S. Tax Ct. LEXIS 198">*200 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 issuethe amount of the depletion allowance to which it was entitled for each of the fiscal years 1943 through 1947. By a first amended petition, Shamrock contends that the "gross income from the property" at the wellhead, for depletion purposes, in terms of price per thousand cubic feet of gas (MCF) was as follows:

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 1961 U.S. Tax Ct. LEXIS 198">*201 market or field price of the gas. Alternative amounts of gross income from the property for each of the fiscal years in issue are proposed by Shamrock as the representative market or field price if the same is to be determined by other sales. These amounts are set forth to be not less than 3 cents for the fiscal year 1943; 4 cents for the fiscal year 1944; 5 cents for the fiscal year 1945; 5 cents for the fiscal year 1946; and 6 cents for the fiscal year 1947.

35 T.C. 979">*981 Based on the amounts of 3 to 6 cents stated above, Shamrock has computed its gross income from the property, allowable percentage depletion, and amount of income tax overpaid in the following amounts for each of the years involved in this docket:

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 1961 U.S. Tax Ct. LEXIS 198">*202 conditions applicable to Shamrock, the gross income from the property during each of the taxable years involved, attributable to the leasehold or other estates in the gas of Shamrock, with respect to which it is entitled to statutory percentage depletion, is "all the proceeds of the sale of the residue gas * * * plus a sum equal to an amount which is not less than 58.8% of the proceeds of all natural gasoline of not less than 14 nor more than 26 pounds vapor pressure, calculated on the basis of 26-70 natural gasoline, extracted from the raw natural gas and raw casinghead gas in the gasoline extraction plants operated by petitioner" during the years in question. Gross income from the property so calculated by Shamrock for each of the years in issue in this docket is as follows:

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 1961 U.S. Tax Ct. LEXIS 198">*203 thereof is to be given effect under Rule 50.

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

35 T.C. 979">*982 Shamrock claimed depletion on its interest in natural gas processed in its own natural gasoline extraction plants for these years on the basis that the proceeds from the sale of all the residuegas and the proceeds from the sale of 40 percent of the liquid hydrocarbons extracted from the gas constituted the gross income from the property.

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

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, 1961 U.S. Tax Ct. LEXIS 198">*204 in its first amended petition in these dockets, allegesthat the amount of depletion claimed on its returns was less than the amount of depletion to which it was entitled. Claim is accordingly made by Shamrock that its income tax for the fiscal years 1948 through 1954 was overpaid. The amounts of overpayment are alleged to be not less than the following amounts:

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

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 35 T.C. 979">*983 other sales. These amounts are set forth to be not less than 6 1/2 cents per MCF foreach of the years 1961 U.S. Tax Ct. LEXIS 198">*205 1948, 1949, and 1950, 7 1/2 cents per MCF for 1951, 8 cents per MCF for 1952, 8 1/2 cents per MCF for 1953, and 9 1/2 cents per MCF for 1954.

Based on these amounts per MCF stated above, Shamrock computes its gross income from the property, allowable percentage depletion, and amount of income tax overpaid in the following amounts:

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:

II. 1961 U.S. Tax Ct. LEXIS 198">*206 Bonus Issue.

In Docket Nos. 61315, 68580, and 77791, Shamrock raises an additional issue, concerning the treatment of bonuses, upon which it predicates a claim for additional overpayment of tax. Shamrock first contends that the total amount of bonuses or initial payments, paid or incurred by it with respect to mineral leases acquired from lessors who retained an economic interest in the property, should be deducted in full from gross income in the year in which paid or incurred. A second and alternative contention is that if such bonuses paid or incurred are held to be advance or prepaid royalties not deductible in full in the year paid, then a proportionate amount based on the anticipated productive life of the leases should be deducted from gross income. A third contention is that if neither the full amount nor a proportionate amount of the bonuses may be deducted from gross income, and the bonuses are considered or treated as capital expenditures, then the respondent erred in deducting from "gross income from the property" before computing percentage depletion a proportionate amount of the bonuses so paid.

35 T.C. 979">*984 The amounts in issue in respect of the bonuses paidand the alleged overpayments 1961 U.S. Tax Ct. LEXIS 198">*207 of income tax are as follows:

Theissues for decision are:

(1) What is the "gross income from the property" for the taxable years ending November 30, 1943, through November 30, 1954, with respect to natural gas in which petitioner owned an economic interest that was produced by petitioner 1961 U.S. Tax Ct. LEXIS 198">*208 and processed by petitioner in its gasoline extraction plants?

(2) May petitioner's expenditures for oil and gas lease bonuses be deducted from gross income, either in the year in which paid or over the estimated life of the leases for which paid, or if the expenditures for bonuses are to be treated as capital expenditures, for computing percentage depletion, must petitioner's "gross income from the property" be reduced by the amount of such bonuses over the estimated life of the leases?

FINDINGS OF FACT.

Some of the facts have been stipulated and are hereby found as stipulated.

The Shamrock Oil and Gas Corporation, hereinafter referred to as Shamrock, was incorporated in 1929 and during all of the period here involved, i.e., from December 1, 1942, through November 30, 1954, 35 T.C. 979">*985 kept its books on a fiscal year basis and on an accrual basis of accounting. The taxable years involved are the fiscal years ending November 30 of1943, 1944, 1945, 1946, 1947, 1948, 1949, 1950, 1951, 1952, 1953, and 1954.

Shamrock filed corporation income and declared value excess-profits tax returns and corporate excess profits tax returns for the fiscal years 1943 to 1946, inclusive, and corporate income tax returns 1961 U.S. Tax Ct. LEXIS 198">*209 for the fiscal years 1947 to 1954, inclusive, with the district director of internal revenue or his predecessor at Dallas, Texas.

Shamrock is an independent oil company with integrated operations for the production and processing of oil and gas and for the distribution and sale of oil and gas products to pipelines, industrial users, carbon black companies, and to Shamrock's dealers in eight States.

All of the natural gas, with respect to which there is any controversy regarding what was the "gross income from the property" for the purpose of computing percentage depletion, was produced by Shamrock and was processed in Shamrock's gasoline extraction plants.

Shamrock's principal operations for the production of natural gas have been in the West Panhandle gasfield of Texas and in the Texas Hugoton gasfield.

The Panhandle and Hugoton Gasfields.

The Panhandle gasfield starts in the eastern part of Wheeler Countyand extends northwestward across portions of Collingsworth, Gray, Hutchinson, Potter, Carson, and Moore Counties, Texas, into Dallam County, Texas, where it connects with the Texas portion of the Hugoton field. There is no physical separation between the fields designated as the East 1961 U.S. Tax Ct. LEXIS 198">*210 Panhandle field, the West Panhandle field, the TexasHugoton, Oklahoma Hugoton, or Kansas Hugoton fileds. The "East Panhandle" and the "West Panhandle" fields and the area designated "Texas Hugoton field" are all located in the State of Texas.

The East Panhandle and West Panhandle fields are both a part of the same common reservoir and are separated by the Railroad Commission of Texas for administration purposes rather than because of physical differences.

Gas was first discovered in the Panhandle of Texas in a well started in 1918 and completed in 1919 at a point approximately 20 miles north of Amarillo, Texas. Gas was first discovered in the Kansas portion of the Hugoton field in 1922 at about the same time it was discovered in what is now the Oklahoma Hugoton field. Exploration began to find production in the Texas Hugoton field as early as 1940, but it was not thought that the fields were connecteduntil about 1946 when sufficient wells had been drilled to definitely establish the connection between them.

35 T.C. 979">*986 The Oklahoma Hugoton and Kansas Hugoton fields are located in those respective States.

The Panhandle field, consisting of both the East and West Panhandle fields, contains approximately 1961 U.S. Tax Ct. LEXIS 198">*211 1,500,000 acres and is approximately 120 miles in length in an eastward and westward direction, and varies in width from 10 to approximately 50 miles. The Hugoton field extending from point of connection with Panhandle field to the northern limits of the Kansas Hugoton field, is approximately 160 miles. The total distance from the top of the Kansas Hugoton field down through the Panhandle field to its eastern tip is approximately 280 miles. Before it was known that the Panhandle field and the Hugoton field were connected, the Panhandle gasfield was known as the largest gas-producing area in the world. The Hugoton field covers approximately 900,000 acres in Oklahoma, 2,400,000 acres in Kansas, and about 640,000 acres in Texas. This, with approximately 1,500,000 to 1,600,000 acres in the Panhandle field, brings the entire reservoir, i.e., Panhandle and Hugoton fields, to approximately5,500,000 acres.

The East Panhandle field, the West Panhandle field, and the Texas portion of the Hugoton field, as well as Kansas, Oklahoma, and Texas portion of the Hugoton field are all in one reservoir which is uninterrupted and connected all the way.

The reservoir pressure in the Panhandle gasfield 1961 U.S. Tax Ct. LEXIS 198">*212 at the beginning was approximately 430 pounds per square inch. As gas has been produced through the years there have been declines in reservoir pressure from the original reservoir or rock pressure. The virgin pressure of 430 pounds per square inch was not the average pressure during the taxable years here involved. At the beginning of the taxable period the weighted average pressure in the sour gas area was approximately 350 pounds. The normal decline or withdrawals in the sour gas area has been from 10 to 12 pounds a year.

At the beginning of the taxable period the pressure in the Texas Hugoton field was very close to the virgin pressure of 430 pounds per square inch. At that time the average pressure in the sour gas portion of the field was approximately 100 pounds less than that of 430 pounds per square inch. As gas has been produced since that time pressure has become lowerin proportion to the withdrawals.

Petitioner first made an investment in compression equipment in fiscal year 1948. The purpose of the compression equipment was to maintain pressures in the lines and plants at about a 200-pound level. In later years, further investment was made by petitioner for the construction 1961 U.S. Tax Ct. LEXIS 198">*213 of additional compression plants.

Little development occurred in the Panhandle field at first because the initial well had about one-third of the normal rock pressure for 35 T.C. 979">*987 the depth from which gas was produced, and it was thought to be a freak well. Additionally, the area was not heavily populated. The rapid development of the field did not start until the Borger, Texas, boom in about 1925 with the development of an oilfield which is along the north portion or rim of the Panhandle field.

The Texas Hugoton field, in general, produces what is known as sweet gas while the Panhandle field produces both sweet and sour gas. Sour and sweet gas are both produced from the same reservoir in the Panhandle field.

In the West Panhandle field, the sour gas supply is higher in heating value than the sweet gas. This is not a result of the gas containing sulphur. The richergas is normally found closer to the oil production and the sour gas adjoins the oil-producing area of the Texas Panhandle.

A royalty interest is a right to oil and gas in place that entitles its owner to a specified fraction, in kind or in value, of the total production from the property, free of expense of development and operation. 1961 U.S. Tax Ct. LEXIS 198">*214 In Texas, customarily, a royalty owner receives one-eighth of the value of the gas.

The working interest is an interest in oil and gas in place that is burdened with the cost of development and operation of the property.

An overriding royalty is similar to a royalty in that each is a right to oil and gas in place that entitles its owner to a specified fraction of production, in kind or in value, and neither is burdened with the costs of development or operation. They differ in that an overriding royalty is created from the working interest, and its term is coextensive with that of the working interest from which it was created.

Raw gas is the gas as it comes from the well. Raw gas as it emerges from the wellhead is in a gaseous state. It is a colorless gas and essentially is a mixture of gases in equilibrium. The mixture of gas consists principallyof hydrocarbons in a gaseous form.

Residue gas is that portion of the raw gas which remains after the extraction of the liquefiable hydrocarbons which are present in the raw gas. The residue is that portion which is marketed as a gas after the liquefiable hydrocarbons are extracted. Raw natural gas in the Panhandle is composed of the residue 1961 U.S. Tax Ct. LEXIS 198">*215 elements and the liquefiable hydrocarbons.

All raw natural gas contains some liquefiable hydrocarbons in suspension. The liquefiable hydrocarbons that are generally extracted in the Panhandle field are propane, isobutane, normal butane, isopentane, normal pentane, and the remaining heaviest portion, generally called hexane-plus.

35 T.C. 979">*988 Natural gasoline includes all of these hydrocarbons in their liquid state. In the industry it is customary to apply the term natural gasoline to that portion of these liquids used by refineries in blending motor fuels. Isopentane, normal pentane, and hexanes are the same as natural gasoline. Motor fuel is motor gasoline, a finished gasoline.

In the Panhandle field, methane is the principal constituent of the natural gas and constitutes approximately 80 percent of the total volume of the raw gas. If allof the liquefiable hydrocarbons from propane or heavier hydrocarbons were removed from the Panhandle gas, approximately 95 percent of the volume of the original raw gas would remain.

Residue gas is made up principally of methane, but it also includes ethane and some inert elements such as carbon dioxide, nitrogen, and helium.

Gas, raw or residue, may be either 1961 U.S. Tax Ct. LEXIS 198">*216 sour gas or sweet gas. Sour gas is natural gas having more than 1 1/2 grains of hydrogen sulphide per 100 cubic feet, or more than 30 grains of total sulphur per 100 cubic feet. Sweet gas is all natural gas except sour and casinghead gas. Casinghead gas is any gas and/or vapor indigenous to any oil stratum and produced from such stratum with oil. Casinghead gas is gas produced with oil and comes out of solution with the oil.

Natural gas includes sweet gas, sour gas, and casinghead gas taken from the earth through gas wells, oil wells, or distillate wells.

Sour gas, before removal of the hydrogen sulphide, is not desirable for light and fuel purposes because, in burning, it produces a poisonous gas, is corrosive, and has a bad rotten-egg odor.

The heating value of sweet and sour gas is comparable. The raw sweet gas in theWest Panhandle field has a B.t.u. content of approximately 1,060 B.t.u.'s per cubic foot. Raw sour gas has a B.t.u. content of approximately 1,070 B.t.u.'s per cubic foot. The raw sweet gas in the Hugoton field portion of the Texas Panhandle has a lower heating value and ranges a little below 1,000 B.t.u.'s per cubic foot because of a higher nitrogen content.

B.t.u., 1961 U.S. Tax Ct. LEXIS 198">*217 or British thermal unit, is a standard of measurement for determining the heating value of gas.

The terms "dry gas" and "wet gas" are relative terms. Dry gas generally means gas produced from a well which does not produce oil. Cashinghead gas, sometimes called wet gas, is produced from a well which does produce oil. Wet gas contains a higher percentage of liquefiable hydrocarbons. In the oil and gas industry, the term "wet gas" is applied generally to gas having a high content of liquefiable hydrocarbons.

"LPG," or liquefied petroleum gas, consists usually of a mixture of propane and butane and is used as a gas for domestic and some industrial purposes where natural gas is not available.

35 T.C. 979">*989 Drip gasoline is a term applied to the liquefiable hydrocarbons which take on a liquid form in the gathering lines asa result of the lowering of temperature and pressure. The amount of drip gasoline which forms in the gathering line depends on the temperature and pressure in the lines, but is usually of a small quantity.

A wellhead sale of gas is a sale where the purchaser lays a line to receive the gas at the wellhead on the lease. The wellhead on a gas well is the valve at the top of the ground that 1961 U.S. Tax Ct. LEXIS 198">*218 closes the well after production is found and is the valve on the top of the pipe that extends down into the hole in the ground.

A so-called "NGAA contract" was a form of contract which was at one time proposed by the Natural Gas Association of America. A "modified NGAA contract" is a form of contract for the purchase of gas which provides for the determination of the price by the addition of a portion of the sales price for residue gas and a portion of the sales price or value of the liquids recovered.

The term "rolled in price" as used by petitioner means a combination of lower prices and higher prices resulting in an average price. Such an average price might occur in the renegotiation of a contract for the sale of gas where a new provision is added to the contract, such as increased volume to be delivered. The price set forth in the renegotiated contract for all the gas to be delivered might be an average price taking into account the price originally specified in the old contract for the volume to be delivered under that contract and a new price for the added volume to be delivered under the renegotiated contract.

Gathering lines are the lines that extend from the individual wells 1961 U.S. Tax Ct. LEXIS 198">*219 to the plant where the gas is processed for the extraction of natural gas liquids. The lines that extend beyond the extraction plant are referred to as residue or delivery lines. A transmission line is a line that carries the gas to market after it has been received in that pipeline in order to make it available to transport to the market at some distance.

During all of the period in question (i.e., from December 1, 1942, through November 30, 1954) Shamrock owned in whole or in part economic interests in the gas produced from certain properties (various producing gaswells and leases) in Moore, Hartley, and Hutchinson Counties, Texas, in the West Panhandle gasfield in the Panhandle of Texas, and during a portion of such period Shamrock additionally owned, in whole or in part, economic interestsin the gas produced from certain properties (various producing gaswells and leases) in Moore, Sherman, Dallam, and Hansford Counties, Texas, in the Texas portion of the Hugoton gasfield in the Panhandle of Texas.

35 T.C. 979">*990 Leases were obtained by Shamrock on the properties from which gas was produced and in respect of which gas Shamrock had an economic interest. The number of leases obtained in the years 1961 U.S. Tax Ct. LEXIS 198">*220 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 nonproducing, to the extent it was economically able to do so. The reason for increasing both producingand nonproducing acreage was to replace the depletion of supply and to put together additional gas supplies that could be marketed to an advantage. Shamrock's lease acreage, both producing and nonproducing, during the taxable years, in the counties designated, is shown by the following table:

35 T.C. 979">*991 After November 30, 1942, Shamrock continued to expand its exploration to obtain raw gas and attempted to obtain more sour gas at that time as well as sweet gas. Shamrock attempted to obtainmore production of all kinds.

Many of the individual leases obtained by Shamrock were for fractional interests in gas properties. The usual drilling unit for spacing gaswells is a section or a tract of 640 1961 U.S. Tax Ct. LEXIS 198">*222 acres. Following is a schedule of property units, grouped in terms of acreage, on which Shamrock had leasehold interests and from which gas was produced and processed in Shamrock's McKee or Sunray gasoline extraction plants:

Production was commenced on these several propertiesat different times during the years. Production starts, or wells which commenced to produce, are shown by year and type of gas produced: 35 T.C. 979">*992

The number of properties from which gas was produced 1961 U.S. Tax Ct. LEXIS 198">*223 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 suchwells from those plants: 35 T.C. 979">*993

35 T.C. 979">*994 Shamrock did not have an economic interest in all the gas which it produced. The following schedule sets forth production statistics for Shamrock's producing properties 1961 U.S. Tax Ct. LEXIS 198">*225 on which Shamrock had a leasehold interest and shows the total production from those properties and the volume interest of that production in which Shamrock had an economic or depletable interest:

1961 U.S. Tax Ct. LEXIS 198">*226 35 T.C. 979">*995 From 1943 to 1954, inclusive, the major portion of Shamrock's natural gas production consisted of sour gas.

The volume of gas set forth in the last column of the schedule immediately above, as Shamrock's volume interest in gas produced, entered Shamrock's gas-gathering system connected to Shamrock's McKee and Sunray gasoline extraction plants and this volume constituted part of the volume of gas which was available for processing in those plants.

Shamrock owned an economic interest in a total of 591 leaseholds on gas properties connected to Shamrock's extraction plants for the period covered by the fiscal years ended November 30, 1943, through November 30, 1954, not all of such leasehold estates being connected to the plants during such period, however. The leases between Shamrock and the royalty owners/lessors contained provisions whereby Shamrock was to pay the royalty to the royalty owners for their proportionate part of the gas production. There were 72 different gas royalty provisions in the total of 591 leases. The one provision which appeared in the most leases, 223 of the 591, provided as follows:

on gas, including casinghead gas, or other gaseous substance, produced from 1961 U.S. Tax Ct. LEXIS 198">*227 said land and sold or used off the premises or in the manufacture of gasoline or other products therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale.

Following is a schedule of the proportionate part of the gas production acquired from the royalty owners by Shamrock:

Subsequent to October 1, 1945, Shamrock endeavored to simplify its accounting to royalty owners and in place of the many different royalty 1961 U.S. Tax Ct. LEXIS 198">*228 provisions contained in the separate leases Shamrock attempted to substitute a royalty computed on a flat basis. Most of the royalty payments subsequent to that date were made on this flat royalty basis. However, in instances where Shamrock had special 35 T.C. 979">*996 contracts or royalties fixed by contract different than the NGAA or flat royalty or unit rate the contract price prevailed.

Payment of gas royalties in the following amounts was made in the taxable years by Shamrock to the royalty owners for the production (by type of gas) acquired:

1961 U.S. Tax Ct. LEXIS 198">*229 The following table sets forth the same data with respect to overriding royalties: 35 T.C. 979">*997

In all, or practically all, of the cases where Shamrock had 1961 U.S. Tax Ct. LEXIS 198">*230 a partnership or joint interest with others, Shamrock purchased the gas of its partner or joint owner. Following is a schedule of gas purchased by Shamrock from the working interest of others in Shamrock leases, for the fiscal years indicated:

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: 35 T.C. 979">*998

1961 U.S. Tax Ct. LEXIS 198">*234 35 T.C. 979">*1000 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:

35 T.C. 979">*1002 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, 1961 U.S. Tax Ct. LEXIS 198">*239 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, 1943 through 1954 were as follows:

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

The 1961 U.S. Tax Ct. LEXIS 198">*242 schedule of weighted average price paid for gas purchased under miscellaneous contracts and price paid for gas purchased from Continental Oil Company (in terms of MCF) is as follows:

The gas produced together with the gas purchased or otherwise acquired constituted the total amount of Shamrock owned gas available for processing in Shamrock's extraction plants.

Disposition of Gas.

Prior to 1933, the owner of a sour gas well had no outlet for his gas because dry gas was not permitted to be used for any purpose other than light and fuel purposes and sourgas was not suitable for pipeline purposes. At that time, sour gas wells were shut in as a general 35 T.C. 979">*1005 rule. Casinghead gas, however, 1961 U.S. Tax Ct. LEXIS 198">*243 could be burned to make carbon black.

Prior to 1941, interstate pipeline operators did not consider sour gas as a source of supply to them. They objected to sour gas because the hydrogen sulphide in the gas had a corrosive effect on the steel pipelines and on burners and its burning produced dangerous, incomplete combustion with an objectionable rotten-egg odor.

The act of the Texas legislature commonly called "the stripping law" was passed in 1933 and under this legislation it became legal to process gas to extract the liquefiable hydrocarbons and to waste the residue gas by simply venting it into the air. The volume of vented gas reached the point where it exceeded a billion cubic feet of gas per day in the Panhandle of Texas.

The conservation statutes of Texas were revised in 1935 and, in addition to other modifications, the stripping law was repealed and the "popping" of gas into the air was prohibited.

In May 1935 a new law known as House Bill No. 266 was adopted. Under this law, sour residue gas could be burned in the manufacture ofcarbon black, provided the liquefiable hydrocarbons were first extracted, and provided that the carbon black plant averaged a production yield of at 1961 U.S. Tax Ct. LEXIS 198">*244 least one pound of carbon black per thousand cubic feet of gas consumed. The statute also limited the amount that could be burned for this purpose to a total of 750 million feet of gas per day and limited the privilege of burning it to gas from common reservoirs in the State of Texas, containing both sweet and sour gas, and 200,000 acres or more in extent. The effect of these limitations was to make the law applicable only to the Panhandle field. Sweet gas could only be burned, under the statute, for carbon black manufacture if the sweet gas was casinghead gas that was produced with oil. It was not permissible to use sweet gas for any purpose other than light and fuel under House Bill No. 266 unless the sweet gas might be produced in the form of casinghead gas with oil.

In approximately 1947, an amendment was adopted which permitted the burning of sweet gas in furnace-type carbon plants, as differentiated from channel-type plants, provided the purchaser of the gas paid a price equal to the average price, which was to be determinedby the Railroad Commission of Texas, being paid for sweet gas in the field during the month in which the gas was taken.

From 1943 through 1954, approximately 1961 U.S. Tax Ct. LEXIS 198">*245 75 or 80 percent of the raw natural gas in the West Panhandle and Texas-Hugoton gasfields was owned by producers who processed their own gas. This left only 20 or 25 percent of the gross production of raw natural gas in the West Panhandle and Texas-Hugoton gasfields available for sale.

During the years 1943 through 1954, most of the gas was owned by the producer and was processed by the producer so that he either sold 35 T.C. 979">*1006 or used residue gas and liquefied hydrocarbons. The interstate pipelines in most instances processed gas produced by them.

In making contracts for the sale of raw gas or residue gas the length of the contract is a factor bearing on the contract and the price to be paid for the gas. As a general rule, purchasers are desirous of obtaining a long-term supply.

It is customary to negotiate sales of gas on relatively long-term bases. Where raw gas is sold, the investment involved in connecting the gas is great. Purchasers of raw gas must build expensive facilities to collect and process the raw gas and, therefore, such purchasers require long-term contracts. Where residue gas is sold to an interstate pipeline, a long-term contract is required for regulatory purposes. An 1961 U.S. Tax Ct. LEXIS 198">*246 interstate pipeline is often in the market for residue gas so that it can increase its market outlet. To do so it has to file application for such expansion program with the Federal Power Commission and adequate reserves is one of the factors considered by that Commission in passing on the application.

Interstate pipelines cannot get permission under the interstate pipeline regulations to construct pipelines and other facilities unless they can show a sufficient supply of gas to justify the investment. Shamrock entered into long-term contracts for the sale of residue gas because that was the only way it could sell gas to the purchaser who, in turn, had to build his facility and pipelines. Thus, Shamrock sold gas on long-term bases because that was the only way that it could sell it.

In the West Panhandle and Texas-Hugoton gasfields from 1943 through 1954, all sales of raw gas were under long-term contracts. Most of these long-term contracts had escalator clauses increasing the price on gas periodically accordingto the terms of the contract.

At all times here material and during the period from December 1, 1942, through November 30, 1954, Shamrock owned and operated a gasoline extraction 1961 U.S. Tax Ct. LEXIS 198">*247 plant known as its McKee Gasoline Plant located on Section 399, Block 44 H&TC Ry. Co. Survey, Moore County, Texas, and from July 15, 1947, through November 30, 1954, Shamrock owned and operated a gasoline extraction plant, known as its Sunray Gasoline Plant, located on Section 170, Block 3-T, T&NO Ry. Co. Survey, Moore County, Texas, approximately 3 miles east of the McKee Plant. In each of these gasoline extraction plants, various liquefiable hydrocarbons were extracted (through an absorption process) from gas in which an economic interest was owned by Shamrock and which gas was produced from properties owned in whole or in part by Shamrock. Shamrock additionally processed in such plants during such periods additional volumes of gas in which it did not own an economic interest. The gas with respect to which a controversy 35 T.C. 979">*1007 as to depletion exists is only that volume of gas in which Shamrock owned an economic interest and which gas was processed in one of the above-named Shamrock Plants (i.e., McKee or Sunray).

Shamrock constructed its first gasoline extraction plant in 1933. The Sunray plant was originally constructed by the Magnolia Petroleum Company which gathered its own gas, processed 1961 U.S. Tax Ct. LEXIS 198">*248 it, and sold the residue gas to a carbon black plant in the area of the processing plant. Shamrock purchased the Sunray Plant from the Magnolia Petroleum Company in 1947.

An extraction plant is designed to extract the liquefiable hydrocarbons from natural gas. It is a usual matter that raw gas is brought by a gathering system to a central point in the Panhandle area and in the Texas portion of the Hugoton area for processing. This is true because of the economics of handling and delivering gas. It is not feasible or practical to construct an extraction plant for each well.

Shamrock's gas-gathering system connects the individual wells and leases and brings the gas to a central point where it is processed for the extraction of the natural gas liquids and after the gas has been brought to the extraction plant and the liquids extracted, the residue gas is then delivered into the lines of the purchaser of that residue gas.

The terrain in Moore and Sherman Counties where Shamrock gas productionis carried on is generally level, smooth terrain, with practically no trees. There is no subsoil rock that would interfere with the laying of gathering lines for the production of gas. It is an ideal 1961 U.S. Tax Ct. LEXIS 198">*249 country for laying pipelines.

In Shamrock's collection lines or gathering lines sweet gas and sour gas are mixed. It is more economical to put the entire stream through the Girbitol plant than it would be to gather and process the gas separately.

After the gas is brought to the McKee and Sunray Plants, the liquefiable hydrocarbons are extracted from the gas. The residue gas remaining is sold to the pipeline companies or to other customers or utilized by Shamrock as plant fuel, etc. The liquefiable hydrocarbons, now in a liquid form, are either sold to customers or utilized by Shamrock in its refinery.

Shamrock has not made sizable sales of raw gas. Since it has had its processing plants and gathering system, it has sold only residue gas with slight exception. With respect to sales of raw gas, Shamrock made no sales during the period 1943 through 1954 at the wellhead as such as distinguished from out of its gathering system. If there were any wellhead sales they were of no consequence.

In the beginning of the taxable years in question, Shamrock sold most of its sweet gas as raw gas but processed its sour gas. However, 35 T.C. 979">*1008 in 1944 Shamrock sold most of its sweet gas producing wells 1961 U.S. Tax Ct. LEXIS 198">*250 and leases to Phillips Petroleum Company. After 1944 Shamrock made no similar sales of raw sweet gas. When Shamrock sold sour gas residue under its first residue gas pipeline contract to Panhandle Eastern Pipeline Company in 1945, it included the sale of residue gas from the sweet gas leases that were dedicated under that contract.

When the gas enters the gasoline extraction plant for processing, it goes first to the absorber which is a vessel in which the gas flows against the absorption oil. This absorber or tower at the McKee Plant is about 20 to 30 feet tall and from 5 to 7 feet in diameter. The gas goes in at the bottom of the tower and out at the top. Only line pressure is used for running the gas through the tower either without compression or after compression, as the case may be. No heat is applied at this stage. As the gas moves up the tower oil is pumped against the flow of the stream of gas, and the oil absorbs liquefiable hydrocarbons out of the raw gas stream. The natural gas not absorbed in the oil is called residue gas.

All of the liquefiable hydrocarbons are extracted at one time in the absorber, and they are then contained in the absorption oil. From the absorber, 1961 U.S. Tax Ct. LEXIS 198">*251 the oil goes to the still where heat coming from steam is applied and the temperature of the liquid is raised and the pressure controlled so that the hydrocarbons will take the form of a liquid, be boiled off, and leave the oil for recirculation. The still or heat exchangers that raise the temperature are a series of horizontal tubes where steam is used to heat the outside surface.

The boiling-off of liquids by heat and pressure is called fractionation. A further fractionation process also separates the propane, butane, isobutane, pentane, isopentane, and the hexanes-plus.

After the liquid extracted by absorption in the first tower has gone through the still, the first product that is separated or taken out of the liquid is propane. This separation is accomplished in what is called a depropanizer where the temperature is regulated so that the propane comes off the top as a gas and the remaining portion of the liquid remains in the liquid state. The propane is then cooledand becomes a liquid again. Pressure and temperature is maintained to keep it in the liquid state as it goes to the storage facility.

Each liquid extracted has its own characteristics with respect to vapor pressure. 1961 U.S. Tax Ct. LEXIS 198">*252 Propane has the highest vapor pressure. In order to retain it as a liquid, it has to be kept under a certain pressure, and that is true of the other liquids. It is easier to keep the heavier blending stock that is usually used in motor fuel in a liquid form than any of the other liquids in the higher ranks of vapor pressure.

After the propane has been taken out of the liquid, the remainder of the liquids are taken to another tower and then the butanes are taken off. There again the separation is made by boiling off the 35 T.C. 979">*1009 lighter fractions that come off the towers as a gas and leaving the balance as liquid at the bottom and the efficiency of the operation is dependent upon temperature levels, top and bottom, on the tower. These temperatures are done by steam and they are all below 200 o F.

After the butanes are taken out, the remainder is commonly referred to as butane-free material. One further step in Shamrock's operations is to take out the isopentane. Isopentane is a blending stock used principally in the industry as the material to give the volatility to aviation gasoline.

Pentanes and isopentanes are both pentanes. Pentanes and isopentanes are separated in the same manner as 1961 U.S. Tax Ct. LEXIS 198">*253 the other separations, that is, in towers with controlled heat and pressure. Butane consists of butane and isobutane. The normal butane and isobutane are separated by the same method of control of the temperature and pressure.

After the butanes have been taken out, the remainder is called pentanes-plus from which Shamrock removes the pentanes and then separates the isopentanes from the pentanes. After the pentanes have been removed from the liquid, the liquid that is left is called hexanes-plus.

Hexanes-plus and the normal pentanes are used as direct blending material in the refinery. These products are transferred to the refinery for blending into motor fuel or motor gasoline. All of these liquids are frequently called natural gasoline. Isopentane, normal pentane, and hexane are the same as natural gasoline. Natural gasoline, as ordinarily referred to in the industry, is thought of as 26-pound natural gasoline, although lower vapor pressures maybe utilized. The vapor pressure of the remaining liquids after the pentanes have been removed is approximately 10 pounds. A 12-pound natural gasoline is a butane-free material. It is the part of the total natural gasoline with everything, 1961 U.S. Tax Ct. LEXIS 198">*254 including butane and above, eliminated. The 26-pound product is a product that contains all the heavier materials with some variation, but approximately 35 to 38 percent butane in combination to give a 26-pound material which can be and has been used to a large extent in the blending of motor fuel. The difference is that lesser quantities of 26-pound gasoline can be put into a gallon of motor fuel because of its vapor pressure than the 12-pound butane-free material.

The residue gas comes off the absorber in the initial stage. It is largely methane (approximately 80 percent of the volume of the residue) and it includes some ethane, propane, and occasionally some butane, and certain inert materials such as helium, carbon dioxide, and nitrogen. After the liquefiable hydrocarbons are removed from the raw gas, there remains approximately 95 percent of the volume of the original raw gas.

35 T.C. 979">*1010 Residue gas may be either sweet or sour gas. Whereraw sweet and raw sour gas are mixed in the collection or gathering lines, as is done by Shamrock, the residue gas produced most likely will be sour residue gas.

Prior to 1941, there was considerable research done for the purpose of obtaining a process 1961 U.S. Tax Ct. LEXIS 198">*255 for removing hydrogen sulphide from sour gas. By 1941, a pilot plant to remove hydrogen sulphide had been constructed and found to be dependable and by it sour gas could be sweetened for use by interstate pipelines. The plant process is known as the Girbitol process. Shamrock owns such a plant. After the residue gas leaves Shamrock's absorber in the initial stage, it immediately goes to the Girbitol plant for the removal of hydrogen sulphide which is still in the residue at that stage.

Generally speaking, the Girbitol plant is simply another absorber or group of absorbers. The inside of an absorber contains trays (or bubble caps) and the absorbent material filters down through these trays which are placed to slow up the movement of the absorbent in order to provide maximum contact with the gas for the absorption process. An amine solution is used as an absorbent to absorb the liquid hydrogen sulphide. The process is very similarto that of the first absorber. The hydrogen sulphide is next removed by fractionation from the liquid that absorbed it as the processes already described separate the liquefiable hydrocarbons from the absorbent.

Shamrock first started taking hydrogen sulphide 1961 U.S. Tax Ct. LEXIS 198">*256 out of the residue gas in 1947 with the commencement of the sale of residue gas to Panhandle Eastern Pipeline Company. This contract, Shamrock's first contract for the sale of sweetened gas, was entered into in 1945.

The following tables show the disposition by years by Shamrock of available raw gas in terms of MCF:

The 1961 U.S. Tax Ct. LEXIS 198">*257 following table shows a percentage analysis of the disposition by years by Shamrock of total available raw gas: 35 T.C. 979">*1011

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 from1961 U.S. Tax Ct. LEXIS 198">*258 raw gas was used in Shamrock's refinery for blending gasoline and a substantial part of the gross receipts listed for such natural gasoline represents intercompany sales from Shamrock's gasoline extraction plants to Shamrock's oil refinery.

Normally Shamrock's outside sales of products consistof the higher vapor pressure materials. Shamrock sells butane, propane, and a combination of butane and propane, known in the industry as LPG, which is liquefied petroleum gas. Shamrock has at times additionally sold isobutane and isopentane.

Shamrock disposed of the total volume of residue gas it had available for sale to the various classes of purchasers and in the amounts shown on the following schedule:

1961 U.S. Tax Ct. LEXIS 198">*259 35 T.C. 979">*1012 The following table shows a summary of amounts received from the sale by Shamrock of residue gas and percentages of the amounts received from the respective sales to the total amount received therefor:

Summary of Amounts Received From Sale of Residue Gas and Percentages of the Amounts Received From the Respective Sales to the Total Amount Received Therefor

1961 U.S. Tax Ct. LEXIS 198">*260 From 1943 to 1954, inclusive, Shamrock made sales of residue gas to carbon black companies. From 1933 to 1943, most of the sour gas residue was sold to carbon black companies.

A channel-type carbon black plant operates on the basis of insufficient combustion of gas with the flame impinging upon a metal surface or channels to cause the accumulation of soot or carbon which is removed by periodically scraping that carbon black off the metal surface and collecting it. The carbon produced by the channel-type plant is in the form of fine carbon particles and is suitable for combination with natural rubber to make commercial rubber products. The carbon produced by the furnace-type method produced larger particles and this gray-type black is more effective for combination with synthetic rubber to make rubber products.

Under the sour gas law passed in 1935, the extraction of gasoline was required before the sour gas residue could be used for the manufacture of carbon black. With the passage of this sour gas law in 1935, it was necessary that Shamrock find an outlet for its residue gas. It found an outlet through the carbon black industry by inducing carbon black companies either to constructor 1961 U.S. Tax Ct. LEXIS 198">*261 move plants to an area adjacent to Shamrock's natural gasoline extraction plant.

Shamrock joined with Continental Oil Company in forming Continental Carbon Company in which Shamrock owned a 30 percent interest. Continental Oil Company likewise furnished a part of the capital for Continental Carbon Company.

35 T.C. 979">*1013 Shamrock on October 15, 1936, agreed to purchase all of the raw gas from approximately 10,000 to 12,000 acres of leases from Continental Oil Company. The purchase of the Continental Oil Company gas was a special arrangement in connection with the formation and construction of the Continental Carbon Black Plant in partnership with the Continental Oil Company.

In addition to the Continental Carbon Company, Shamrock assisted Reliance Carbon Company financially in establishing its plant near Shamrock's McKee Plant. This assistance took the form of permitting a deduction in the price paid to Shamrock for gas sold to the carbon company until the accumulated deductions equaled the cost of moving the plant from Louisiana and reconstructing it in the Panhandle of Texas.

There were five carbon black plants constructed in the vicinity of Shamrock's McKee Plant. Shamrock committedto each of these 1961 U.S. Tax Ct. LEXIS 198">*262 carbon black companies the furnishing of a definite volume of gas for the life of the field. This was necessary in order for Shamrock to induce these carbon black companies to provide the market for Shamrock's residue gas. The companies that built plants in the area and with whom Shamrock had contracts were Continental Carbon Company, Crown Carbon Company, Reliance Carbon Company, later known as United Carbon Company, and Columbian Carbon Company. To induce these carbon black companies to provide a market for the residue sour gas by locating near the McKee gasoline extraction plant, Shamrock dedicated residue gas from certain acreages for the life of the leases to the carbon black companies. All contracts made with these companies had such long-term dedications.

In September 1937, the Crown Carbon Company built a plant 0.2 of a mile from the McKee Plant and Crown purchased residue gas from Shamrock from 1943 to March 1954.

In June 1936, the Columbian Carbon Company built a plant 1.28 miles from the McKee Plant and Columbian purchased residue gas from Shamrock from 1943 to August 1953, inclusive.

In January 1937, Continental Carbon Company built a plant 2.46 milesfrom the McKee Plant 1961 U.S. Tax Ct. LEXIS 198">*263 and Continental Carbon purchased residue gas from Shamrock from 1943 to 1954, inclusive.

In June 1936, Reliance Carbon Company built a plant 0.014 of a mile from the McKee Plant and Reliance purchased residue gas from Shamrock from 1943 to January 1953.

In September 1937, Shell-Columbian Carbon Company built a plant 0.091 of a mile from the McKee Plant and Shell-Columbian purchased residue gas from Shamrock from 1943 to December 1951.

The price basis on which Shamrock sold the residue gas to the carbon black companies for supplying their requirements was 30 35 T.C. 979">*1014 percent of the carbon black yield, less certain deductions such as sales and packaging and warehouse expenses, etc., to give a net price to Shamrock in the neighborhood of 25 percent to 26 percent of the value of the carbon black produced from the gas.

Each of the contracts with these carbon black companies provided that, in the event the purchaser elected to discontinue the manufacture of carbon black, then it had the right of resale and the contract set forth the percentage basis upon which the revenue from such resale would be divided between the carbon company and Shamrock even though the carboncompany should elect to move its 1961 U.S. Tax Ct. LEXIS 198">*264 plant from the area.

The economics of the gas industry early in the taxable period changed to where all of the gas that had been sold to the carbon black companies was resold to pipeline companies. Shamrock participated in the resale of that gas and in the revenue received. Additionally, Shamrock handled, with the consent or permission of the carbon black companies, the negotiations of the contracts which were made disposing of the gas to the various pipeline companies. The first contract for the resale of this gas was made in 1947. Shamrock continued to make these contracts of resale of gas until all of the gas was sold.

At the time of the resale of this gas the value of the gas for light and fuel purposes exceeded the value of the gas for carbon black manufacture.

The delivery of gas to Continental Carbon Company started with the completion of the Continental Carbon Company's channel-type carbon black plant in 1937 and continued until the residue gas was sold to pipeline companies in increments beginning with the sale to Texoma Natural Gas Company. The date of the first sale to Texoma Natural Gas Company was July 1, 1947.

Shamrock continued to produce gas, extract gasoline, and 1961 U.S. Tax Ct. LEXIS 198">*265 sell the majority of residue gas for carbon black manufacture up to the beginning of the period here involved in 1943.

Shamrock negotiated new contracts with the carbon black companies prior to a resale of the gas to pipeline companies. In the renegotiations the prices for the gas were put on a flat basis of a certain sum per MCF and the amount that was being paid for carbon black was substantially increased. In these contract negotiations, the minimum price to be paid to Shamrock in the event of a resale was likewise increased. In the original contracts, it was provided that in the event a carbon black company ceased using gas and made a resale of the gas Shamrock would receive the first 2 cents per thousand cubic feet and the balance would be divided on a 50-50 basis between the two companies. In these renegotiated contracts 35 T.C. 979">*1015 for sale of gas to carbon black companies, it was provided that the first 3 cents would be received by Shamrock and the balance would be divided 50-50.

At the time of making these renegotiated contracts for the sale of gas to the carbon black companies, the price of residue gas in substantial quantities hadincreased from what it was in 1936.

During the period 1961 U.S. Tax Ct. LEXIS 198">*266 prior to 1943, Shamrock made two industrial sales to other users. These sales were a fuel sale to the plant of the American Zinc Company of Illinois and a fuel sale to what was then a small generating plant of the Southwestern Public Service Company, originally Panhandle Power & Light Company. Both of these plants are in the proximity of Shamrock's extraction plants.

In September 1936, the American Zinc Company built a plant 2.8 miles from the McKee Plant and American Zinc purchased residue gas from Shamrock from 1943 to 1954, inclusive.

In January 1938, Southwestern Public Service Company built a plant 0.774 of a mile from the McKee plant and Southwestern purchased residue gas from Shamrock from 1943 to 1954, inclusive.

The first pipeline from the Panhandle field was constructed in 1926. Thereafter, the major long distance pipelines in the order of their construction were:

(1) Cities Service Pipe Line which was constructed into the Kansas City, Missouri, area in 1928;

(2) CanadianRiver Pipe Line (now known as Colorado Interstate Pipeline) which began transporting gas to Denver, Colorado, and intermediate points in 1928;

(3) Panhandle Eastern Pipeline Company, which began making deliveries 1961 U.S. Tax Ct. LEXIS 198">*267 out of its initial pipeline to Indiana in June 1931;

(4) Texoma Natural Gas (now Natural Gas Pipeline of America) which began taking gas out of the West Panhandle field to the vicinity of Chicago in October 1931; and

(5) Northern Natural Pipe Line Company, which began taking gas through its pipeline into the Omaha, Nebraska, area in 1932; later to the Minneapolis, St. Paul, Iowa, and Nebraska area.

The principal other pipelines built out of the Panhandle field was the Michigan-Wisconsin Pipeline, which originates in the Texas-Hugoton field, and the El PasoNatural Gas Pipeline, which obtains substantially all its supply from the sweetened sour gas in the West Panhandle field. This latter pipeline extends to the California market. Since original construction, the early pipelines have been expanded, paralleled, duplicated, and additional facilities have been built.

All of the pipeline companies had to have long-term supplies of natural gas in order to finance the pipeline projects. In order to obtain 35 T.C. 979">*1016 such long-term supplies, the pipeline companies acquired leases on large blocks of acreage in the Panhandlefield and produced gas from their own acreage.

With one exception, that is, the 1961 U.S. Tax Ct. LEXIS 198">*268 Northern Natural Gas Company, no gas was purchased by any of the pipeline companies until 1936. In 1936, Panhandle Eastern Pipeline Company purchased gas from wells owned by what was then the King Oil Company (later sold to Phillips Petroleum Company). Likewise, in the same year, Panhandle Eastern entered into a contract with Shamrock involving the purchase of gas from two wells, which two wells were located in the sweet portion of the field in Moore County.

In the early 1930's, the majority of the sweet gas producing acreage in the Panhandle field was owned by interstate pipeline companies, but the same percentage did not apply to the total known producing acreage in the Panhandle, whether sweet or sour. The interstate pipeline companies did not own a substantial portion of the sour gas acreage.

The removal of the liquefiable hydrocarbons from natural gas is desirable from the standpoint of the pipeline company and the ordinary processing of natural gas is carried on by all major long-distance pipeline companies.

Until about 1941, sour gas was not considered as a source of supply for pipelines. Thepipeline companies would not purchase sour gas because of the corrosive effects of the 1961 U.S. Tax Ct. LEXIS 198">*269 hydrogen sulphide on the steel of which the pipelines were constructed, the danger of incomplete combustion because of the corrosion of the burner tip, and the fact that the gas would leave an objectionable odor in the house when the gas was burned.

Considerable research had been undertaken with respect to the removal of hydrogen sulphide from the sour natural gas and in 1941 a pilot plant for this purpose had been constructed and found to be dependable.

With the development of the Girbitol process and the increase in the national population, the sour gas reserve became a highly desirable source of supply for interstate pipeline companies. The pipelines in general extended their facilities greatly to take care of the new increase in population and new communities.

During the period from 1943 to 1954, there was an evolution with respect to the use of sour gas. With the development of the Girbitol process for the removal of hydrogen sulphide from gas and with the increasing market outlet for natural gas, the sour gas reserve became a desirable source of supply because in the West Panhandle Fieldit was located close to existing pipeline facilities. Panhandle Eastern Pipeline 35 T.C. 979">*1017 Company 1961 U.S. Tax Ct. LEXIS 198">*270 was the first company to make a contract and become competitive for the purchase of sour gas residue.

Negotiations were started in 1943 between Panhandle Eastern Pipeline Company and Shamrock for the purchase of gas. These negotiations started in 1943 when Panhandle Eastern became convinced it was necessary to find additional sources of supply in the Panhandle and Hugoton fields. This contract was later executed on December 28, 1945.

Shamrock had many opportunities to make sales of residue gas to the gas pipelines with deliveries beginning in the year 1947. This residue gas was the residue sour gas from which the hydrogen sulphide had been removed. Shamrock made actual sales of such gas to Texoma Natural Gas Company, Natural Gas Pipeline Company of America, and Northern Natural Gas Company.

There was an increasing demand for residue gas in the Panhandle field and in the Texas portion of the Hugoton field for interstate and intrastate pipelines over the period from 1943 through 1954, and there was a change in the uses to which residue gas has been disposed of in the Panhandle field. The principal change in the use of residue gas was from the carbon black market to the natural gas 1961 U.S. Tax Ct. LEXIS 198">*271 pipelines for light and fuel.

The change in the use of the residue gas brought about a change in the price for which the gas could be sold in the Panhandle field both at the wellhead and for residue gas. The price for which it could be sold moved upward.

From 1943 to 1954, inclusive, Shamrock used considerable quantities of its residue gas as plant fuel for the gasoline extraction plants and the oil refinery. Transfers of residue gas were treated as intercompany sales and billed at prices set by Shamrock.

The maximum length of all of Shamrock's delivery or residue lines at all times was 7.68 miles. A portion of the delivery lines equaling 1.598 miles was abandoned when the carbon black plants were abandoned. There are no delivery lines from the Sunray Plant because the residue gas is brought to the McKee Plant, a distance of 3 miles, where the hydrogen sulphide is removed.

The following purchases of raw gas in the field were reported by interstate pipeline companies to the Federal Power Commissioner during the years in issue. All of these purchases, where the point of receipt ofthe raw gas was at the well mouth, except two purchase contracts stipulated by the parties as not to be 1961 U.S. Tax Ct. LEXIS 198">*272 considered by the Court, have been considered by the Court and the basic provisions of the original contracts considered are set out following the schedules of purchases. 35 T.C. 979">*1018