
    408 F. 2d 690
    PANHANDLE EASTERN PIPE LINE CO. v. THE UNITED STATES
    [Nos. 547-58,166-60 and 400-61.
    Decided March 14, 1969.
    Defendant’s motion for rehearing denied May 16, 1969]
    
      
      John P. Lipscomb, Jr., attorney of record, for plaintiff. Thomas E. J enks and J ohn P. Persons, of counsel.
    
      Theodore D. Peyser, with whom was Assistant Attorney General Mitchell Bogovin, for defendant. Philip B. Miller, of counsel.
    
      J. D. Durand, for amicus curiae, Association of Oil Pipe Lines.
    Before Cowen, Chief Judge, Dtoutee, Davis, Collins, Skelton, and Nichols, Judges.
    
   Cowen, Chief Judge,

delivered the opinion of the court:

The petitions in these three consolidated actions assert that plaintiff is entitled to recover a total of $4,054,532.38 in federal income taxes, plus deficiency interest, paid for the calendar years 1952 through 1956, and statutory interest thereon.

Four principal issues are raised for decision. The first issue is the right of plaintiff to deductions from its gross income during the years 1954, 1955, and 1956, for depreciation of its investment in its main-line transmission system’s rights-of-way.

The second and third issues involve the proper method of determining, for the purpose of computing deductions for percentage depletion allowance, plaintiff’s gross income from the production of natural gas from properties (wells) in which it had an economic interest located in (a) the Hugoton Embayment in the States of Kansas, Oklahoma, and Texas, during all of the years in suit, i.e., 1952 through 1956; and (b) the Howell Field, Michigan, during the year 1952. While these issues are basically interrelated, they are treated separately since they present different questions.

The fourth issue is raised by defendant’s claimed setoff. For the years 1954 through 1956, plaintiff claimed and was allowed to depreciate its investment in gathering lines’ rights-of-way on the double declining balance method. Defendant claims this depreciation should have been computed by the straight line method.

Preliminary to outlining the positions and relevant contentions of the parties with respect to the above issues, the detailed findings of fact, m/m, will be summarized in order to provide a background for the discussion that follows.

Plaintiff is a Delaware corporation with its principal business office located in Kansas City, Missouri. At all times material here, plaintiff was an interstate natural gas company under the Act of Congress dated June 21, 1988, known as the “Natural Gas Act,” 15 U.S.C. § 717. As such, a substantial portion of plaintiff’s operations was subject to the jurisdiction of the Federal Power Commission (FPC). Plaintiff is principally engaged in the business of producing, purchasing, transporting by pipeline, and selling natural gas to utility companies for resale and directly to industries for their own use. It was so engaged during all the years in question and the major part of the gas produced by plaintiff was sold to gas distribution companies for resale. Plaintiff also operates a natural gasoline plant and other facilities for the separation of heavier hydrocarbons from raw natural gas both at central points and on its producing properties. In addition to these sources of income, plaintiff derives revenue from other companies for the separation by them of such hydrocarbons from plaintiff’s raw natural gas stream. It also is engaged in the production and sale of oil.

As of December 31, 1956, plaintiff’s principal natural gas transmission system extended a distance of approximately 1,200 miles starting from the Hugoton Embayment in the Panhandle of Texas, and going through Oklahoma, Kansas, Missouri, Illinois, Indiana, Ohio, to Detroit, Michigan. This system consisted of three parallel lines, two of which extended along the entire 1,200 miles. The third line extended from plaintiff’s compressor station at Eiberal, Kansas, to a point 78 miles from Detroit. As of December 31, 1951, and December 31,1956, respectively, plaintiff’s transmission system consisted of 4,758 miles and 4,961 miles (round figures), respectively, of main-line pipe of various sizes ranging from 20 to 30 inches in diameter.

As of the same last above-mentioned dates, plaintiff’s gathering systems, which extended out from the main transmission line into the various producing fields and moved the gas to the main line, consisted of 509 miles and 1,174 miles (round figures), respectively, of various sizes of pipe ranging from 3 to 20 inches in diameter.

In order to construct its pipeline transmission system, including lateral or sales lines, plaintiff has over the years obtained from the owners of the land through which the lines are laid, right-of-way grants or agreements. In most instances, it has been able to reach an agreement with the landowners involved. However, in the few cases in which this was not possible, plaintiff has had to exercise its power of condemnation which permits the laying of a single pipeline for the transportation of natural gas, only, through an owner’s land.

Plaintiff’s procedure in obtaining right-of-way agreements may be summarized as follows: Its engineering department gives a map or sketch, indicating the route of the pipeline, to the right-of-way division which prepares a certificate of title describing each of the tracts of land to be traversed. These are sent to outside abstractors who supply the name of the latest owner of record and how title was obtained. From this information, the right-of-way division prepares the agreements and related papers which are sent to agents who negotiate with the landowners. After an agreement is secured, it is acknowledged, checked, and recorded.

By these agreements, plaintiff acquired the right to lay one or more pipelines across the grantor’s land, and the right to go thereon for the purpose of operating, maintaining, repairing, and replacing the line or lines. The agreements generally contain a stated nominal consideration of $1. They also provide for a payment to the landowner of a fixed amount per linear rod crossed over the land in the course of construction of the pipeline. This payment, known as a “roddage fee,” is usually made at the time the pipelines are actually laid. While the roddage fee rate is specified and varies from 250 in the older agreements up to $5 being paid currently, depending upon the area to be crossed, plaintiff usually pays the “going price” as set up by other pipeline companies.

In some of the states through which plaintiff’s transmission and gathering systems extend, the right-of-way agreements permit the “transportation of oil, gas, or other substances.” In other states such agreements provide only for the “transportation of natural gas.”

The agreements normally do not have an expiration date and thus are for an indefinite period of time.

Less than 10 percent of the 6000 separate right-of-way agreements held by plaintiff during the period 1952 through 1956, specified the width of the right-of-way granted or limited the number of pipelines plaintiff was permitted to lay across the landowner’s property. Despite the lack of width designation in such agreements, plaintiff, as a matter of practice, confines its operations to the route of the pipeline and within a specified width of its own determination, normally about 25 feet. Agreements which do not specify the width of the right-of-way or limit plaintiff to laying but one pipeline are known as “multiple line” agreements. Plaintiff prefers, and attempts to obtain, a multiple line agreement. The principal advantage of such type of an agreement is that it eliminates the need for instituting a condemnation action if plaintiff desires to lay additional pipelines and the landowner refuses to enter into a new agreement. Another but secondary advantage of relative unimportance is that when additional lines are required, plaintiff does not have to pay the nominal consideration uniformly stated in both the single and multiple line types of agreements, or incur the expense of recording fees which run from $1 to $2 per instrument.

Plaintiff acquired some of its right-of-way agreements from predecessor corporations which were named as the grantees in these agreements and were the parties that ob-tamed tlie agreements from tbe landowners. All of plaintiff’s right-of-way agreements are transferable.

In addition to right-of-way agreements, plaintiff has to obtain licenses or permits when its pipelines cross a state highway, county road, railroad, or navigable stream.

-■ In the acquisition of its rights-of-way, plaintiff incurs or pays, in addition to the stated consideration, roddage fees, and' expenses of obtaining necessary licenses and permits, various other costs, including notary, abstract, recording and legal fees, office, clerical and secretarial expenses, the expenses of negotiating the right-Of-way agreements, and legal expenditures and other expenses relating to condemnation proceedings. During the years in question, plaintiff’s investments in its transmission lines’ rights-of-way (exclusive of its gathering lines’ rights-of-way) covering the above-mentioned items ranged from $1,914,490.11 on December 31, 1951, to $2,365,744 on December 31,1956. Plaintiff capitalized these investments on' its books' of account and for federal income tax purposes.

During the years 1952 through 1956, plaintiff produced natural gas from wells in which it had an economic interest in the States of Kansas, Oklahoma, and Texas in the Hugoton Embáyment. Most of this gas was transported away from the wellhead through plaintiff’s gathering and main-line transmission systems prior to sale. In the year 1952, plaintiff also produced natural gas from 14 wells in which it had an economic (lease) interest located in Howell Field, Michigan. Plaintiff sold all of this production to one customer for a single price at various delivery points, one of which was located on the lease property near the wellhead of a certain well. Part of the production from the latter well and all of the production from the 13 other wells were transported off of the lease property to another delivery point which was located some distance from the wells.

Plaintiff filed 'federal income tax returns for each of years 1952 through 1956, and claimed therein, inter alia, certain deductions for depreciation and amortization of the costs which it had incurred in connection with the acquisition of its rights-of-way and capitalized. Plaintiff also claimed in these returns, deductions for percentage depletion allowance with respect to the production from its properties in both the Hugoton Embayment and the Howell Field during all of the years in suit. In the final determinations of plaintiff’s income tax liabilities for the years in question, the Commissioner of Internal Revenue (Commissioner) disallowed in their entirety plaintiff’s claimed deductions for depreciation and amortization mentioned above. He also determined that plaintiff’s gross income from its said properties in each of these years, upon the basis of which income plaintiff was entitled to deductions for percentage depletion, was less than the amount calculated by plaintiff. Based upon his determinations, the Commissioner computed and allowed deductions for percentage depletion for each year in an amount less than that to which plaintiff claimed it was entitled.

Deficiency taxes resulting from the Commissioner’s dis-allowances and determinations with respect to plaintiff’s claimed deductions for depreciation and amortization of rights-of-way acquisition costs, and for percentage depletion, were assessed by the Commissioner and paid by plaintiff in due course. Thereafter, plaintiff timely filed claims for refunds covering the issues raised in its petition in this consolidated proceeding and such claims were denied. Subsequently, these suits were brought.

l

DEPRECIATION OP RIGHTS-OP-WAT ACQUISITION COSTS ISSUE

When, these cases were tried, one of the principal issues to be resolved was whether plaintiff’s rights-of-way in its mainline transmission systems have a useful life coextensive with the useful life of plaintiff’s pipelines, thereby entitling plaintiff to a depreciation deduction for the acquisition costs of the rights-of-way. On October 17, 1968, the court handed down its decision in Badger Pipe Line Co. v. United States, 185 Ct. Cl. 547, 401 F. 2d 799 (1968), a case involving the same issue in a similar factual situation. There, the court adopted the opinion and recommended conclusion of law of Commissioner George Willi, after the defendant had withdrawn its notice of intention to except to the commissioner’s report. We held that the taxpayer’s rights-of-way had a useful life coterminous with the useful life of its pipelines and that the capitalized costs of the rights-of-way were therefore depreciable under the provisions of Section 167 of the Internal Revenue Code of 1954. In these cases, argued to the court after Badger was decided, the trial commissioner in his findings of fact made the same determinations in favor of plaintiff and defendant has not excepted to such findings. However, defendant contends that such rights-of-way constitute intangible assets within the meaning of Section 167 (c) of the Code and consequently that for the years 1954 through 1956, plaintiff’s allowances for the depreciation of the acquisition costs of the rights-of-way that were not covered by certificates of necessity must be computed by the straight line method. Since plaintiff maintains that it is legally entitled to depreciate such acquisition costs in those years by use of the double declining balance method, this dispute presents the only issue that remains for decision on this phase of the litigation.

In his opinion on the question, the trial commissioner concluded in part as follows:

Plaintiff has contended that the installation of pipe pursuant to a particular easement that has been obtained from the property owner transforms the easement right from an intangible asset into a tangible asset. This contention is fallacious. An easement granting the right to install pipe under a property owner’s land is an intangible asset when obtained. The fact that subsequently that right is exercised does not alter the intangible character of the right-of-way. An easement is similar in nature to a license or a franchise. As such, it is an intangible asset regardless of the use to which it is put. Kennecott Copper Corp. v. United States, 171 Ct. Cl. 580, 613-14, 347 F. 2d 275, 294 (1965).

For the reasons hereinafter stated, we concur in and adopt that portion of the trial commissioner’s opinion and hold that the assets in issue are intangible assets and that plaintiff’s depreciation deductions for 1954,1955, and 1956, are not entitled to be computed by use of the double declining balance method.

The typical right-of-way agreement obtained by plaintiff provided as follows:

* * * in consideration of One ($1.00) Dollar, to them in hand paid, receipt of which is hereby acknowledged, and the farther consideration of $_per linear rod, to be paid when the pipe lines hereinafter specified are laid, do hereby grant__and convey__ unto panhandle eastern pepe line compant, a Delaware Corporation of Kansas City, Missouri, its successors and assigns, a Right-of-Way to lay, construct, maintain, alter, repair, replace, change the size of, operate, and remove pipe lines and from time to time parallel pipe lines, drips, gates, telegraph and telephone lines, and all appurtenances convenient for the maintenance and operation of said lines and for the transportation of oil, gas, or other substances therein, and the Grantee is granted the right of ingress and egress, to and from the following described land for the purpose of constructing, inspecting, repairing, operating, changing the size of, or removing at will, in whole or in part, said property, from, on, over, and through the following premises * * *.

It is apparent that this agreement is an easement and that it contains provisions that are generally found in right-of-way easements obtained by public utility companies and governmental bodies. As previously stated, the nominal consideration of $1 is paid by plaintiff when the agreement is executed, while the roddage fee, which varies from 25 cents bo $5 per linear rod crossed over the land in constructing the pipeline, is usually paid when the line is laid. That fact, however, in nowise alters the character or legal effect of the agreement. The roddage fee appears to be merely a practical way of determining the consideration to be paid the landowner for the easement, depending upon the extent of the area to be crossed and prices paid at the time by other pipeline companies.

Since the rights obtained by plaintiff under the above-described agreements are right-of-way easements, they are, by the great weight of authority, intangible assets and are to be so classified for income tax purposes. Union Elec. Co. v. Comm'r, 177 F. 2d 269, 275 (8th Cir. 1949); Shell Pipe Line Corp. v. United, States, 267 F. Supp. 1014, 1018 (S.D. Tex. 1967); Commonwealth Gas Distrib. Corp. v. United States, 395 F. 2d 493 (4th Cir. 1968) ; Badger Pipe Line Co. v. United States, supra; Texas-New Mexico Pipe Line Co. v. United States, 185 Ct. Cl. 570, 401 F. 2d 796 (1968); Rev. Rul. 65-264,1965-2 Cum. Bull. 53.

While the legislative history of section 167 (c) is not conclusive, the light it sheds on the question before us supports a decision contrary to plaintiff’s contentions. When it considered the bill which was enacted as the Internal Kevenue Code of 1954, the Senate Finance Committee included the following in its report with respect to section 167 (c) :

Your committee has completely rewritten subsection (c). Subsection (c) defines the property with respect to which subsection (b) applies. Subsection (b) does not apply to intangible property such as patents, copyrights, and leases, etc. Your committee has eliminated the word “personal” as leases are meant to be excluded for allowances provided for by methods allowed in subsection (b). [S. Kep. No. 1622, 83d Cong., 2d Sess., p. 26, (3 U.S.C. Cong. & Adm. News (1954) 4837)]

The abbreviation “etc.”, following the word “leases”, shows a congressional intent to exclude from the depreciation allowance permitted by section 167(b), leases and other property in the same general category. A right-of-way easement is in many respects similar to a lease, and we think it is included in the kind of property which Congress intended to classify as an intangible for the purposes of sections 167 (b) and 167(c).

Plaintiff does not contend that the easement rights are tangible property. In its brief to the trial commissioner, plaintiff argued that if the costs of the intangible property are reasonably associated with the tangible property, such costs “lose their intangible character and become merged into the tangible property as a part of the cost thereof.” In its brief to the court, plaintiff contends that since the rigbts-of-way have no value except for the construction of the pipelines, the acquisition costs are so intimately related to the pipelines that plaintiff is entitled to depreciate the costs on the same basis as construction costs. While these arguments and the facts upon which they are based are useful in determining whether the intangible property has an ascertainable useful life, as well as the extent of the useful life, plaintiff’s contentions are directly contrary to the specific language of section 167(c), which limits the allowance for rapid depreciation to tangible property. We find no indication in section 167, or in the legislative history of that statute, that Congress intended to authorize a deduction for the depreciation of the cost of an intangible asset at the accelerated rate, in circumstances where the intangible asset is directly related to tangible property and has no value separately and apart therefrom.

We think the fallacy of plaintiff’s theory may be demonstrated by a hypothetical situation in which the taxpayer leases a tract of land for a term of years for the express purpose of constructing thereon a temporary building for the operation of a stated business. The taxpayer argues that the lease, an intangible asset, has no value apart from the building he has constructed on the land. In view of the legislative history of section 167 (c), quoted above, we think he would be denied the right to depreciate the cost of the lease on the double declining balance method.

For the taxable years 1954 through 1956, plaintiff is entitled to recover on the ground that the useful lives of its right-of-way are coextensive with the useful lives of the pipelines for which the rights were acquired. The amount of the recovery is to be measured by depreciating plaintiff’s investment in the rights-of-way by use of the straight line method, which plaintiff used for depreciating the pipelines prior to January 1, 1954. Plaintiff’s right to amortize its investment in transmission systems’ right-of-way covered by certificates of necessity for the taxable years in suit is not now disputed by defendant. Plaintiff amortized its investment in such facilities over a period of 60 months and is entitled to recover on that basis.

II

DEPLETION ISSUE — HUGOTON EMBATMENT

This issue arises out of plaintiff’s claim for additional depletion allowance with respect to its production of natural gas, under leases in which it had an economic interest, from wells in scattered areas throughout the Hugoton Embayment during each of the years 1952 through 1956. The production in question was gathered, processed, and transported by plaintiff away from the wellhead before sale and delivery to its customers.

Under §§ 23 (m) and 114(b) (3) of the Internal Eevenue Code of 1939, and the corresponding and similar provisions of the 1954 Code, §§ 611 and 613, a taxpayer holding an economic interest in oil or gas wells is permitted to take as a deduction from income 271/2 percent of the taxpayer’s “gross income from the property.” Outwardly, this would appear to be quite a simple determination. One could say just determine the total value of the taxpayer’s sales of gas to consumers and use the resulting amount as the basis to compute the depletion allowance. However, this amount could differ radically depending upon whether a company is an integrated processor as opposed to a nonintegrated producer. If it is integrated, with production facilities and a distribution system, its gross income, all other things being-equal, would be considerably higher than the nonintegrated producer. Seen at its essence, the integrated processor’s expenses are higher, due to the processing and distribution facilities it maintains, and these expenses are passed on to the consumer in the form of higher prices. It would, therefore, enjoy an allowance for depletion on its distributing system which is already subject to depreciation. Since it already produces and distributes gas at retail, it would enjoy an unusual advantage over the mere producer of gas in the field.

The Supreme Court determined that the Congressional objective in allowing depletion deductions was not to give the integrated processor a preference resulting in a competitive advantage over the nonintegrated producer. Accordingly, the Court held that depletion allowance is intended to be based on the “constructive moome” from the raw product, if marketable in that form, and not on the finished article’s value. United States v. Cannelton Sewer Pife Co., 364 U.S. 76 (1960). See also, this court’s second decision in Hugoton Production Co. v. United States, 172 Ct. Cl. 444, 849 F. 2d 418 (1965); Greensboro Gas Co. v. Commissioner, 79 F. 2d 701 (3rdCir. 1935).

As this court stated in its first decision in the case of Hugoton Production Co. v. United States, 161 Ct. Cl. 274, 315 F. 2d 868 (1963) :

* * !|! From the outset, the producer [integrated] has been held entitled to include in gross income for purposes'of the percentage depletion allowance only so much of the proceeds from the sale of the gas as he would have received had he sold the gas at the wellhead. [161 Ct. Cl. at 277, 315 F. 2d at 869.]

The first regulations bearing on the problem were adopted by the Internal Eevenue Service (IKS) in 1929. There were slight amendments in 1933 and 1936, the amended regulations under the 1939 Code providing as follows:

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

Treas. Keg. 118, § 39.23 (m)-1(e), as amended October 31, 1944. See also, Treas. Keg. 118, § 39.23(m)-1(e) (1). The provisions remain substantially unchanged under the 1954 Code, except that the phrase “(as of the date of sale)” has been deleted. Eor gas not sold on the property, the applicable regulations equate “gross income from property” with “the representative market or field price * * * of the * * * gas before conversion or transportation.” The difficulty with the applicable regulations, supra, is that they do not define the term “representative market of field price” nor explain how gross income is to be determined in the absence of á representative market or field price.

As a preface to any discussion on this subject matter, it is essential to examine and analyze the two decisions handed down by this court in Hugoton Production Co., supra. That case involved a taxpayer which produced, transported,. and processed natural gas from a portion of the Hugoton, Field located in the State of Kansas. The plaintiff there held an economic interest in gas wells and therefore took as a deduction from income 27(4 percent of its “gross income from the property.” Section 114(b) (3) of the 1939 Code. The Commissioner disallowed the depreciation deduction on the ground that taxpayer’s gross income was erroneously computed.

In the first proceeding in the Hugoton case, supra, the taxpayer argued that the interpretation of Treas. Keg. 118, § 39.23 (m)-'l(e) (1), essentially the same as Treas. Reg. l.'613-3'(a) under the 1954 Code, supra, called for gross income to be determined by multiplying the amount of gas processed and sold each year by an amount determined to be the “representative market or field price” for its gas at the wellhead, less royalty payments. This is called the “market comparison” method. Such method would naturally entail a study of sales of similar gas at the wellhead by other producers comparably situated. The Government took the position that no comparable sales existed and that in such circumstances “a proportionate profits” or “roll back” formula should be utilized. This would have required taking the gross proceeds from the sale of plaintiff’s processed gas and by-products, and subtracting from them the costs attributable to gathering and processing, a 10 percent return on the capital invested in these nonproducing functions, and the royalty payments. Under the Government’s proposal, the difference would be treated as gross income from the property.

In the first Hugoton decision, the court rejected the formula proposed by the Government and held that under the applicable regulations, supra,

* * * the representative price for each tax year [should be] calculated as the average price, weighted by quantity, of comparable gas sold in the locality under a fair selection of contracts in effect during each year * * * [161 Ct. Cl. at 289, 315 F. 2d at 877.]

The regulations were held to be pointed toward the determination of the taxpayer’s “constructive income” from the wellhead. The phrase “representative market or field price” was viewed as not the current market price, but the price which is in fact being obtained under all existing comparable contracts. The court further held that the representative market or field price had to be determined by computing the weighted-average price of all contracts in effect each year under which comparable gas was sold, rather than merely considering the contracts entered into during a specific tax year. Accordingly, the case was remanded for such a determination.

On remand, the Government located what it felt to be producers of natural gas operating under essentially the same conditions as the plaintiff in that case. Thereafter, the weighted-average prices for each taxable year in question were computed on the basis of wellhead sales made by these producers. The trial commissioner of this court found the resulting prices to be conclusive evidence of the value of plaintiff’s gas at the wellhead. To this finding the plaintiff excepted. In deciding this matter, the court stated in its second decision in Hugoton:

Although the weighted averages are undoubtedly derived from contracts made by producers whose physical characteristics of production are comparable with those which the plaintiff deemed important during the earlier stages of this litigation, it is urged that the representative prices derived therefrom must be rejected since they only take into consideration sales made in interstate commerce. Plaintiff contends that such sales are not comparable due to the fact that during the period in question it was engaged solely in intrastate business. * * * plaintiff adopts the position first taken by the Government, i.e., that in the absence of comparative sales a proportionate profits formula is the only reasonable means of computing gross income for depletion purposes. [172 Ct. Cl. at 451-52, 349 F. 2d at 421-22.]

The court rejected the plaintiff’s argument, reasserting the position that “[t]he ‘representative market or field price’ required by the Kegulation demands the utilization of an accounting system which considers comparative sales.” [172 Ct. Cl. at 459, 349 F. 2d at 427.] It is with this demand that plaintiff here has sought to comply.

To a large extent, the parties in the instant proceeding agree on the method of computing plaintiff’s depletion base in that they (1) both employ the weighted-average price method; (2) agree on the area selected by plaintiff (hereinafter sometimes referred to as “plaintiff’s area” or “plaintiff’s selected area” or “the area”) from which the comparable sales are to be derived; and (3) agree on the sales which are to be used in the computations (with minor exceptions for 1952 and 1953 discussed hereafter). However, starting from this point, the parties travel in different directions. Plaintiff contends that for each year in suit one weighted-average price should be computed for all of its production in the States of Kansas, Oklahoma, and Texas in the Hugoton Embayment. Defendant contends that for each year three weighted-average prices should be computed, one for taxpayer’s Kansas production based on wellhead sales of gas in Kansas (and to a minor extent in Colorado) within 40 miles of taxpayer’s production; one for taxpayer’s Oklahoma production based on wellhead sales of gas in Oklahoma within 40 miles of taxpayer’s production; and a third price for taxpayer’s Texas production again based on wellhead sales of gas in Texas within 40 miles of taxpayer’s production. Consistent with the above contentions made by the parties, they proposed weighted-average prices computed in accordance with the methods respectively advanced by them.

For reasons appearing hereafter, it is concluded that plaintiff’s selected area involved should not be divided along state lines into three segments for pricing purposes, and that for each of the years 1952 through 1956, a single weighted-average price should be computed and used in order to determine plaintiff’s gross income from all of its production in question in the Plugoton Embayment during those years for the purpose of computing plaintiff’s depletion allowance for each year in suit.

Inherent in the issue now under consideration are two fundamental problems: (1) the selection of an area in the Hugoton Embayment from which sales of comparable gas can be selected, and (2) the source or sources of information from which the details of such sales can be determined. As to these problems, it must be kept in mind that, unlike the situation existing in the Hugoton case, supra, plaintiff’s production during the years in question in the instant proceeding did not come from a single compact 96,000 acre block located in two counties of the State of Kansas. As this court found in the second Hugoton decision, acreage lying within 80 miles of the taxpayer’s acreage provided sufficient sales of comparable gas from which to compute a representative market price. See 172 Ct. Cl. 444, 450, n. 9, 349 F. 2d 418,421, n. 9. There is, of course, no magic in the figure of 30 miles for the courts have not hesitated to go many miles further away to find comparable sales.

Thus, in the present case, the selection of the proper area is of vital importance because of the widely separated areas from which plaintiff’s production comes. This court has firmly adopted the concept of computing a weighted-average price from sales of comparable gas. Admittedly, an area in the Embayment must be selected from which wellhead or on-the-lease sales can be ascertained. The area also should be broad enough to include sales of gas comparable to plaintiff’s production. However, this does not mean that once the area is determined it must further be fragmented by artificial political boundaries due to the presence (and disappearance) of one of the many economic factors at work. This is especially important because of the wide variations in plaintiff’s own production in the very years in issue from the States of Kansas, Oklahoma, and Texas, which will continue to occur, and the even wider variations that occur throughout plaintiff’s selected area. Because of the foregoing, there can never be a perfect balance between plaintiff’s production broken down by states and comparable sales also broken down by states. Even if such an area has been determined for 1 year, variations in production will inevitably occur in subsequent years, thereby raising questions as to further fragmentation of the area horizontally, vertically or by state, or even county, lines, depending upon whose advantage it is to further fragment a competitive purchase area.

Plaintiff’s selected area was chosen by the company’s manager of proration and reservoir engineering, Mr. Clifford R. Horn, a petroleum engineer, pursuant to instructions to study the areas in the Hugoton Embayment in which plaintiff had production of natural gas in the years 1952 through 1956, with a view to determining a reasonable area from which to compute weighted-average prices applicable to plaintiff’s production of gas in the three above-mentioned states. Mr. Horn recognized at the outset that wide variations in producing conditions, quality of the gas, and other factors affecting the value of gas existed not only in the Hugoton Embayment as a whole, but also with respect to plaintiff’s own production. Accordingly, he attempted to determine an area within which the gas would be comparable to plaintiff’s, and variations in the composition, quality and other factors relating to the gas would even themselves out due to the broad character of the area chosen. After examining plaintiff’s producing 'acreage, Mr. Horn drew arcs with radii of from 30 to 40 miles around that acreage, which he determined provided an area that met his above-stated objectives. There were several hundred separate fields or gas reservoirs in the area selected.

The radii crossed the state lines of Kansas, Oklahoma, and Texas, as well as many of the county borders. According to Mr. Horn, it was found impractical to divide counties, and if the arc of the radius covered a substantial part of a county the entire county was included in the area. The area so selected extended from north to south about 200 miles and from east to west about 160 to 170 miles. The 12 Texas counties included in plaintiff’s area for 1955 and 1956 form a rectangle. Plaintiff’s southernmost production was about 18 miles north of the southern border of said area and about 182 miles south of the northern border thereof. Plaintiff’s production in Oklahoma and Kansas was centrally located in relation to the eastern and western borders of plaintiff’s area. Plaintiff’s northernmost production was about 42 miles south of the northern border of said area and about 150 miles north of the southern border thereof. With respect to Oklahoma and Kansas, it was not centrally located to the north and south, nor were the sales included in the sample for Texas centrally located.

Mr. Horn testified that in determining the area in question, he took into account that there were no practical differences in the proration laws of the States of Kansas, Oklahoma, and Texas. He further stated that he was aware that natural gas migrates across state lines. It is found, as a factual matter, that such is the case and that the migration does not pay any attention to political boundaries and subdivisions.

The procedure followed by plaintiff in computing its proposed weighted-average prices; the practical difficulties involved in selecting proper sample purchase contracts relating to wellhead sales used in determining such prices; the limitations on the availability and accuracy of sources of relevant information concerning these sales; and the facts concerning a dispute existing between the parties arising out of plaintiff’s refusal to make adjustments in its proposed prices for the tax years 1952 and 1953, called for by reason of certain reporting errors known to plaintiff, are fully set forth in the findings of fact, infra. (See findings 105 (a) and (b),190 (a) and (b), and 107 and n. 12 thereto.) Because of the lengthy and involved nature of these findings, they will not be repeated in detail here. It is sufficient to say at this point that in computing its proposed weighted-average prices, plaintiff Used sales contracts under which natural gas was purchased by interstate pipeline companies operating in plaintiff’s selected area; tbat only contracts covering sales on the property (wellhead and separator), as stated in the gas purchase sections of the Forms 2 on file with the FPC, were used; and that plaintiff relied entirely on the information contained in the said gas purchase sections and did not go behind the Forms 2.

Although defendant also generally relied upon the information contained in these forms, it, for varying reasons, went back thereof in a number of instances and examined certain gas purchase contracts on file with the FPC to determine whether they involved wellhead or non-wellhead sales. As a result of such check, defendant discovered that gas purchased by plaintiff at the wellhead in the Texas portion of its selected area in 1952 and 1953, under two Texas contracts were erroneously listed as non-wellhead sales in the gas purchase sections of plaintiff’s Forms 2. Naturally, this affected the weighted-average prices computed by plaintiff for those 2 years. Accordingly, defendant used corrected figures in computing its proposed weighted-average prices for plaintiff’s production of natural gas in question during the years in suit.

Despite the fact that plaintiff does not deny the afore-stated situation and acknowledges that “[t]he occasional obvious error should be corrected,” it inconsistently refused to make adjustments in its proposed weighted-average prices. Plaintiff contends that it was justified in disregarding the two known errors simply because the purchases involved were not listed in the Forms 2, it being plaintiff’s position that the information therein should control regardless of the fact certain of such information is known to be erroneous, since other improper omissions or even inclusions may have occurred and it is impractical to go behind the forms for the purpose of making a determination with respect to the accuracy of the data shown thereon. This position must be rejected.

It cannot be seriously disputed that it is impractical to go behind the Forms 2 in a comprehensive manner because this would require an unduly time-consuming and burdensome examination of all purchase contracts listed in the gas purchase sections of the forms. In this connection, it should, be noted that during the trial the attorneys for both parties stated that if they had gone behind the forms to any greater extent than this had been done by defendant, “[w]e would never have tried this case.” Moreover, the sample of contracts used in making the weighted-average computations involved herein was sufficiently large and diverse enough to discount variations and offset errors in the gas purchase sections of the Forms 2, at least to a satisfactory degree. It would be better, in any future litigation of this same kind, if the parties relied solely upon information contained in said forms. However, at no point in this proceeding did the parties ever agree to be limited to, or bound by, the information in the forms, and no commitment was made by either party that it would be unnecessary to correct any errors which actually turned up therein. Under the circumstances existing in this case, obvious errors in the information shown in the forms, as established by actual reference to the contracts involved, must be corrected. To disregard such errors and fail to reflect them in the computation of the weighted-average prices determined here would be unjustified and improper.

Mr. Oliver W. Jones, a petroleum engineer employed as a valuation engineer in the Natural Resources Section of the Depreciation, Depletion, and Valuation Branch of the Internal Revenue Service, was assigned the task of- computing the weighted-average prices for the years 1952 through 1956, proposed by defendant. As previously indicated, defendant accepted, with one exception, the area selected by plaintiff. This exception was Baca County, Colorado. (See findings 114 (a) and (b),and 115 (a), (b),and (c),infra.) However, defendant divided plaintiff’s area into three parts as follows: (1) the counties in Texas, (2) the counties in Oklahoma, and (3) the remaining counties which were in Kansas (plus one county in Colorado, i.e., Baca County). Defendant then computed a weighted-average price for each of the three areas for each of the years in question, using the same sales used by plaintiff in its computations, plus the sales for 1952 and 1953 under the two Texas contracts mentioned earlier.

Both parties admit that plaintiff’s area is a common competitive purchase area in the Hugoton Embayment, “in the sense tbat tliere were botb buyers and sellers dealing at arm’s length who bought and sold gas.” It is undisputed that there was a great deal of competition. In general, the sellers were seeking the best price they could get for their gas, while the buyers sought to buy at the lowest possible prices.

The main thrust of defendant’s objection to plaintiff’s method of computing the representative market or field price is based upon the following language of the second Hugoton decision:

The plaintiff argues that the competitive purchase area to be considered was the entire Hugoton Embayment and that the Commissioner committed error by considering only comparative contracts selected from part of the Kansas Hugoton Field and the nearby Greenwood Field. We disagree. Although in our first opinion there is language referring to the larger Embayment area, this was placed in a contest of deciding, in accordance with the evidence then presented by the plaintiff, that there were indeed comparative sales which could be utilized in finding the representative market or field price via the market comparison method. Our remand, however, called for comparable sales in the “locality,” and cited with approval Phillips Pet. Co. v. Bynum,. 155 F. 2d 196, (5th Cir. 1946) and Shamrock Oil & Gas Corp., supra. [35 T.C. 979 (1961), aff'd 346 F. 2d 377 (5th Cir. 1965).] Phillips held that the market price should be based on sales similar in “availability to market.” Shamrock essentially is in accord for there the representative price for the taxpayer’s gas produced in the West Panhandle Field of Texas and the Texas portion of the Hugoton Field was computed on the basis of purchases of gas produced in the same two areas.
The Hugoton Embayment consists of approximately 25 million acres. The contracts considered related to companies which were within thirty miles of the plaintiff’s block. As reasons for using this limited area the Government’s witness testified:
Well, I felt that to get gas comparable to that of the taxpayer I should use gas in the same local geographical area and, also, the reservoirs from which this gas is produced are identical in all respects to that of the taxpayer.
As of this time there has been no attempt to define definitively the total area to be considered in computing a representative “market” or “field” price. We believe that such an all-inclusive rule cannot 'be laid down due to the fact that each case arises in its own particular context depending upon the surroundings in which the individual taxpayer finds himself. However, common sense dictates that when there are comparative sales within the immediate area practicalities should limit the weighted averages to their use. Not only is this conducive to an easier administration of the Regulation but further tends to equalize the taxpayer to his surroundings, i.e., the physical area in which his immediate competitors find themselves. Moreover, this method would be in accord with the general theory of Cannelton * * *. [172 Ct. Cl. at 463-65, 349 F. 2d at 430-31.]

Defendant points out that plaintiff’s proposed weighted-average prices would apply to its Texas production which is based 70 to 80 percent on Kansas sales as far as 182 miles away. Defendant contends that the Kansas sales are not “similar in availability to market” to plaintiff’s Texas production and, also, the Texas sales used in the computations are not similar in availability to market to plaintiff’s Kansas production. The defendant urges, therefore, that the Government’s method is preferable because it will permit the weighted-averages to be based “on sales similar in availability to market” and, much more than plaintiff’s method, “tends to equalize the taxpayer to his surroundings, i.e., the physical area in which his immediate competitors find themselves,” a situation found desirable by this court in its second Hugoton decision. [172 Ct. Cl. at 465, 349 F. 2d at 431.] This, defendant states, results from the simple fact that the three areas urged by the Government are much smaller than the one area urged by the taxpayer. Defendant contends that the most important factor which favors the Government’s method is the avoidance of geographical disparity inherent in plaintiff’s method. Finally, defendant argues that its method more nearly puts plaintiff in the position it would be in if it were not an integrated producer because if plaintiff sold its gas at the wellhead in a particular state, the price would be determined primarily on the basis of local conditions and relatively little by conditions existing many miles away in some other state.

It is true that in its two decisions in the Hugoton case, this court referred to “locality,” and that the compact, centrally-located area of the production of the taxpayer in that case did permit the ascertainment of comparable gas within a 30-mile radius of its production. There was, also, detailed evidence that the sample used in each year was comparable to the taxpayer’s production. However, there is no such evidence in the record of the present proceeding if the common competitive-purchase area is divided along state lines. Moreover, the amount of comparable gas included in the sample used in the Hugoton case greatly exceeded that of the taxpayer’s production in each of the 3 years in suit there. The desirability of an adequate sample so as to minimize the effect of reporting errors and to make more certain that any price computed is representative in the instant case is admitted by both parties. Furthermore, it does not seem reasonable to read this court’s use of the word “locality” in the Hugoton case as establishing a rigid, fixed size for any area determined. In the second Hugoton decision the court expressly disinclined any such intention by using the words contained in the first two sentences of the last paragraph quoted, m/m, from that decision. [172 Ct. Cl. at 464, 349 F. 2d at 430-31.]

There are only two things required under the Hugoton case: (1) the area should be representative of the taxpayer’s production, and (2) comparable gas should be used. It is concluded that both factors are satisfied within the area selected by plaintiff.

Defendant’s expert witness, Mr. Jones, stated that to divide the area along state lines permits “the sales to be closer to the taxpayer’s production.” In this regard, it is important to realize that closeness is not the test, without evidence that closeness also assures comparability and a representative sample. The evidence in this proceeding has established that there are several common producing formations which cross state lines. To assign different prices to the same gas produced on either side of a state line not only is inconsistent with the “locality” argument, but also ignores the obvious comparability factor stressed by this court in the Hugoton case. This was the precise reason why plaintiff’s expert testified he chose this specified area for computing the weighted-average price.

The defendant is in apparent agreement tbat during the years 1952 through 1956, plaintiff’s natural gas from its producing acreage was comparable gas to that produced throughout plaintiff’s selected area in that — (a) its acreage was in convenient blocks from the standpoint of gathering costs and delivery and was well above the average for said area; (b) the volumes of gas available to plaintiff were much above average; (c) the heating value of its gas ranged from a low of 800 BTU to a high of 1,190 BTU and the 'average heating value of plaintiff’s gas was above that for the area; (d) all of its gas was sweet gas, i.e., gas not containing hydrogen sulphide in excess of 1 grain per 100 cubic feet of gas (Some very small accumulations of sour gas occur in the Kansas portion of the area, though most of the sour gas is found in the northern part of the Texas Panhandle field.) ; (e) the pressures of its gas ranged about the same as that from the other wells in the area; and (f) the deliverability of its wells was better than average.

It is fair to conclude from the above that, if anything, plaintiff’s production, on analysis, was more valuable than the production throughout its selected area. Thus, plaintiff has complied with the requirement under the Hugoton case of using comparable gas from one common competitive-purchase area. Plaintiff’s area is interlaced with competing pipelines, almost all of which are interconnected with many other lines so that there is much flexibility in buying, gathering, exchanging, processing, and transporting gas throughout the area. Within the area, gas may be produced in Texas, processed in Oklahoma, and exchanged in Kansas. Competitive forces for natural gas, like the geology of gas-bearing formations,-is not attuned to the incidence of state lines.

The evidence shows that by 1955, the interstate pipeline companies were taking approximately 90 percent of the total gas produced in the Hu'goton Embayment. Furthermore, adequate supplies of natural gas in the Hugoton Embayment became increasingly more difficult to obtain. The development of gas supplies in the Hugoton Embayment was not a uniform thing. In the early 1920’s, it became known that there were very large reserves in the Texas Panhandle area and it became evident that there was possibly a large reserve in the Iiugoton Field portion of the Embayment. These areas were developed early in the gas market under the depressed prices then prevailing. By 1948 through 1949, some 90 percent of the Kansas portion of the Hugoton Field was covered by gas purchase contracts. The evidence also discloses that approximately 80 percent of the old Panhandle Field of Texas was controlled by the gas producers who do not sell at the wellhead.

The determination of a representative market or field price does not call for the fencing in of a taxpayer to an old area dominated by archaic contract prices. This, of course, does not mean that such prices are to be excluded from the computation. Pertinent to the foregoing, this court said in its first Hugoton decision:

Plaintiff points out that contracts for the sale of gas now generally include escalator clauses, providing for price increases to correspond with current market price increases. But the existence of these clauses does not indicate that the Government’s averaging method saddles plaintiff with archaic contract prices which no longer govern. The effect of. the escalator clauses will be taken into account in computing the price obtained under the particular contract for the tax year in question. Contracts entered far in the past and without such clauses will of course tend to reduce the representative price; but we see no basis for concluding that because particular contracts were unfavorable to the seller they Should not be included in the computations.
Finally, it may be observed that the weighted average method increases the number of contracts which bear on the market price of the plaintiff’s gas. Hence it will not be necessary to rely on six or less contracts for each year in question, and the larger sampling should provide greater assurance that the price derived is in fact representative. [161 Ct. Cl. at 289, 315 F. 2d at 876-77]

Thus, in a given competitive-purchase area all the economic factors at work reflected in old, as well as new, contracts should be allowed full play. This tends to achieve a balance between old gas and new gas, thereby making the price more representative by avoiding a balance of either type of gas. But this can only be done if the atea is large enough.

Defendant maintains that the gas in the Texas portion of plaintiff’s area is cheaper than in Kansas and Oklahoma, and that if taxpayer sells its gas at the wellhead, the price would be determined primarily on the basis of local conditions and relatively little by conditions 180 miles away in Kansas. This simply is not so if, as has been established, plaintiff’s area is one competitive-purchase area. True, parts of the area may reflect varying weighted-average prices, especially if most of the gas was sold in a buyer’s market under what this court referred to as “archaic contract prices which no longer govern.” Such prices account for the lower weighted-average prices prevailing in Texas. As indicated earlier, this is not to suggest that these old low-price contracts, many of which are still in effect, should be ignored, but at the same time they should not be unduly emphasized by artificial divisions of one competitive-purchase area.

In support of its last above-outlined contention, defendant points out that for the period 1952 through 1956, a portion of the production of natural gas in the State of Kansas was affected by certain State minimum-price orders which were declared invalid in January 1958. In like manner, a portion of the production in the State of Oklahoma was affected until April 11, 1955, by State minimum-price orders. It is known that these minimum-price orders represented attempts by the two said states to correct inequities and to prevent waste in the Kansas and in the Oklahoma portions of the Hugoton Field. These orders established floors, not ceilings, on the prices paid for natural gas. As defendant’s expert admitted, the orders were but one of the economic factors affecting wellhead prices of gas in plaintiff’s area. To the extent these orders affected existing prices for gas, it cannot be denied that those were the prices at which gas was sold, and any weighted-average price computation must include those prices, as well as those prevailing under “archaic contract prices which no longer govern.”

While the minimum price orders in question obviously resulted in floor prices for gas of an artificial nature which could not be lowered by competition, it is important to note that in the Hugoton case this court considered it immaterial that the weighted-average prices developed by the Government apparently were based on some factors which produced unrealistic results not economically representative of the taxpayer’s integrated business. [172 Ct. Cl. at 455, 349 F. 2d at 424-25.] So here, tbe presence of an economic factor that affected a part of the Kansas and Oklahoma gas included in the sample of contract sales used in computing weighted-average prices in this proceeding, is not a sound reason for dividing an otherwise acceptable competitive area into three segments, especially absent any proof that each of the subdivided parts involves “comparable gas.”

Finally, as mentioned before, under the defendant’s method the selected area would have been determined for only 1 year. If the determination of an area is to be subject to revision year after year, depending upon how many variables in an actual gas production happened to fall in place in a given year, then this litigation will have resolved relatively little. It is only reasonable that the plaintiff have some assurance that it can file annual tax returns without having to periodically relitigate the size, shape, and depth of the area from which its gross income from the property is to be ascertained.

On the basis of the evidence in the entire record considered as a whole, it is concluded and held that the representative market or field price for all of plaintiff’s production of natural gas in the Hugoton Embayment in the States of Kansas, Oklahoma, and Texas, for each of the years 1952 through 1956, must be derived from, and computed on the basis of, one weighted-average price for all of the production in question in the Embayment during each of said years.

There is no real evidence in the record that state lines or other political boundaries, or minimum price orders in effect in the States of Kansas and Oklahoma with respect to the Permian production from the Hugoton Field during the years in suit, had any significant effect on competitive prices that were being paid for natural gas in any of said years; therefore, these factors need not be considered in computing the weighted-average prices to be used in determining plaintiff’s gross income for depletion allowance purposes.

It is further held that the representative market or field price for all of plaintiff’s production of natural gas in question in the Hugoton Embayment in the States of Kansas? Oklahoma, and Texas, during each of the years in suit, is the same as the weighted-average price computed for the natural gas produced by plaintiff in its selected area in those years, and that such price applicable to each year is as follows:

Price
Year per MGF
1952 _ 7.53$
1953 - 8.23 (i
1951 -10. 74(i
1955 - 10. 95$
1956 - 11.23(i

The prices shown above are the proper ones to be used in determining, for the purpose of computing deductions for percentage allowance, plaintiff’s gross income, in each of the years at issue, from the production of natural gas from properties in which it had an economic interest located in the Embayment in the three above-mentioned states in those years.

Ill

DEPLETION ISSTJE — -HOWELL EIELD

This issue involves the determination of plaintiff’s gross income from the production of natural gas during the year 1952, from properties in which it had an economic interest located in the Howell Field, Michigan, for the purpose of computing its percentage depletion allowance in said year. The basic question presented here is whether the Commissioner of Internal Eevenue (Commissioner) made an improper determination as to plaintiff’s gross income, with the result that it is entitled to a depletion allowance under sections. 23 (m) and 114(b) (3) of the Internal Eevenue Code of. 1939, over and above that allowed plaintiff by the Commissioner.

• The Howell Field situation is unique in that one on-the-lease property or wellhead sale of gas by plaintiff is involved, and the consideration given to this sale is crucial to the decision reached herein. Plaintiff contends that this wellhead sale was the only one in its area involving comparable gas, and that the contract price at which the gas was purchased is determinative of the representative market or field price for plaintiff’s entire production from the Howell Field during the year in issue. Defendant disagrees and contends that plaintiff has failed to sustain its burden of proving a representative market or field price for its Plowell Field production that may be utilized in computing its gross income therefrom, and that plaintiff is entitled to additional depletion allowance only with respect to the one above-mentioned sale.

The earlier portion of this opinion relating to the Hugo-ton Embayment depletion issue, which discusses the statutes under which plaintiff’s claims are asserted, the interpretative Treasury Regulations, and the controlling decisions of this court in Hugoton Production Co., supra, as well as the cases cited with approval therein, particularly Cannelton Sewer Pipe Co. supra, and Shamrock Oil & Gas Corp., supra, must be kept in mind because they, collectively, serve both as background and guidelines in resolving the issue now before us.

At this point certain preliminary facts are set forth in the following summary which will be supplemented later on in the course of discussing the issue at hand. Plaintiff owned, as lessee, an economic interest in oil and gas leases on land located approximately 50 miles northwest of Detroit, Michigan, in what is called the Howell Field. During the year 1952, plaintiff produced 2,625,508 MCF of natural gas, at a stated pressure base of 15.025 p.s.i.a., from its 14 producing wells in said field. A portion of plaintiff’s gas from the field was passed through a field separator owned by plaintiff, for the purpose of recovering a portion of liquefiable hydrocarbons therein, and plaintiff realized $4,150 in 1952, from the .sale of hydrocarbons so recovered. Plaintiff had no other production in the State of Michigan, and made no purchases of gas from wells located in that State in said year. Plaintiff was the sole operator in, and producer of natural gas from, the Howell Field in the year at issue.

Under date of April 21,1950, plaintiff entered into a written contract with Consumers Power Company (hereinafter referred to as “Consumers”), a Maine corporation, for the sale of natural gas from the Howell Field wells and delivery thereof by plaintiff to Consumers at certain specified points. This contract remained in full force and effect throughout 1952. The contract price for all the deliveries of natural gas by plaintiff to Consumers was 32*4$ per MCF. All of plaintiff’s production from the Howell Field in 1952 was sold and delivered to Consumers under said contract. Pursuant to the contract, gas in the volume of 215,909 MCF produced from plaintiff’s McPherson No. 1-35 well located in the Howell Field was delivered to Consumers in the Town of Howell at 32)4$ per MCF. The delivery point in said Town was on the above-mentioned McPherson lease near the wellhead. The balance of the production from this well and the production from plaintiff’s 13 other wells in the Howell Field, totaling 2,413,619 MCF of natural gas, was sold off the leases at 3214$ per MCF and transported from the leases by plaintiff, for delivery to Consumers at what is called the Salem Measuring Station, located some 30 to 40 miles away. The parties stipulated that plaintiff’s cost of gathering the gas from its wells in the Howell Field and in moving it to the points of delivery to Consumers, including depreciation, was, during the year 1952, not in excess of 314$ per MCF at a pressure base of 15.025 p.s.i.a.

In its 1952 tax return, plaintiff claimed a deduction for percentage depletion under sections 23(m) and 114(b) (3) of the 1939 Code, as amended, supra, with respect to its production of natural gas from its Howell Field wells in that year. Plaintiff computed the gross income from its properties at the rate of 26140 Per MCF of gas for the 2,625,508 MCF of gas produced amounting to $695,759.61. The Commissioner determined that plaintiff had overstated its gross income by the sum of $166,643.29. In making such determination, the Commissioner nsed as the representative market or field price of plaintiff’s produced gas, an amount which was the equivalent of the rate per MCF at which plaintiff paid royalties to its lessors in the Howell Field. The Commissioner, therefore, computed and allowed a deduction for percentage depletion in the amount of $95,750.21. No deduction for percentage depletion with respect to the $4,150 realized by plaintiff from the sale of hydrocarbons recovered was allowed.

As to the 215,909 MCF of gas produced from McPherson No. 1-35 well and delivered to Consumers on the lease property near the wellhead, it is defendant’s position that plaintiff’s “gross income from the property” was equal to seven-eighths of 215,909 (stating that one-eighth belonged to the royalty owners) times 32y2$, amounting to $61,399.12, since the price of 32y2f was, in the words of the applicable regulation, infra, “the amount for which the taxpayer sells the * * * gas in the immediate vicinity of the well.” However, this does not mean defendant concedes that plaintiff has proved a representative market or field price of 32for its entire production of natural gas from the Howell Field. As indicated earlier in this opinion, the applicable Treasury Eegulations pertaining to the depletion of gas (as well as oil) wells, Treas. Eeg. 118 (1939 Code), § 39.23(m)-l(e) (1), sufra, (see Appendix), provides that the words “gross income from the property,” as used in the depletion provision of the 1939 Code, means: As pointed out by defendant, the regulation states, and the cases so hold, that in the case of an integrated producer it is the “representative market or field price” at the wellhead which governs. (See the decisions of this court in Hugoton Production Co., supra.)

* * * [T]he amount for which the taxpayer sells the * * * gas in the immediate vicinity of the well. If the * * * gas * * * [is] not sold on the property but * * * [is] manufactured or converted into a refined product prior to sale, or * * * [is] 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 * * * gas before conversion or transportation.

Defendant’s position as to the balance of plaintiff’s production from the above-mentioned McPherson No. 1-35 well and its 13 other wells in the Howell Field, amounting to 2,413,619 MCF, which was transported off the leases prior to sale and delivery to Consumers, is that under the decisions of this court in the Rugoton case, plaintiff’s “gross income from the property” for its Howell Field production must be computed on the basis of comparable sales; that plaintiff has failed to sustain its burden of proving comparable sales upon which a representative market price for plaintiff’s gas production in question can be computed; that, similarly, plaintiff has failed to prove the absence of comparable sales; and that, therefore, plaintiff is not entitled to any depletion on the Howell Field gas sold off the lease property, or for the sale of hydrocarbons recovered in the field separator, beyond that previously allowed by the Commissioner.

We turn now to the subject of comparable wellhead sales, and it must be kept in mind that under the two Rugoton decisions such sales are not comparable unless they involve “comparable gas.” The evidence shows that the gas produced from the Howell Field had a heating value of 1,080 BTXJ and was unique in that it had a much lower water content than was normal. This was advantageous to plaintiff because it permitted the gathering and delivery of the gas without the necessity of installing dehydration facilities. The record discloses evidence of only one wellhead sale of comparable gas, to-wit, the previously-mentioned sale from plaintiff’s McPherson No. 1-35 well. In the second Rugoton decision, supra, this court noted that in the proceedings underlying the court’s first decision in Rugoton, the Commissioner of this court found that for the tax years in question there (1952 to 1957, inclusive) certain factors influenced the price a seller of natural gas could command for his product in the Iiugoton Embayment. The Commissioner’s findings were approved by the court in its first decision.

During 1952, production of natural gas in the State of Michigan amounted to approximately 5.1 billion cubic feet of which about one-half was from the Howell Field. Some of the gas produced outside of said Field was produced at the wellhead. Plaintiff’s engineering expert, Mr. C. H. Hinton, an experienced oil and gas engineer who developed the Howell Field for plaintiff and was acquainted with the natural gas situation in Michigan, made a study and investigation in an effort to find wellhead sales of gas comparable to plaintiff’s Howell Field production. While his investigation covered only a small percentage of the gas production outside of the Howell Field, it included not only areas in Michigan within the immediate locality of said Field and gas fields and wells located about 175 miles therefrom, but also, to a limited extent, in adjoining states.

Plaintiff’s expert presented credible testimony to the effect that he was unable to find comparable wellhead sales of comparable gas in the locality of plaintiff’s Howell Field production; that while he found a number of wellhead sales, he determined that none of them involved gas comparable to plaintiff’s production in question because they involved small volumes and much lower pressure, stating this was so “particularly with respect to the reserve back of these sales”; and that on the basis of his entire investigation he concluded that during 1952, there were no wellhead sales by other producers in the immediate vicinity of the Howell Field, or elsewhere in Michigan, or in adjoining states, within a reasonable distance of said Field of natural gas which he considered comparable to plaintiff’s Howell Field production. Considering Mr. Hinton’s testimony as a whole, it may be reasonably inferred and concluded that in making the aforesaid determination he considered all of the factors which the court found in the Hugoton case, supra, influenced the price of natural gas in the Hugoton Embayment. There seems to 'be no sound reason why such factors should not be equally relevant to the instant proceeding.

It is true that another reason given by plaintiff’s expert for not considering the above-mentioned wellhead sales for comparative purposes was that the wells involved were more than 30 or 40 miles from the Howell Field and therefore were entirely outside of the competitive market area of plaintiff’s production (as he understood the meaning of the term “comparative gas,” as used by this court in its decisions in the Hugotmi case, supra); however, it is clear that Mr. Hinton did not disregard the sales in question simply because of the distances the wells were located from the Howell Field.

It may be reasonably inferred from the record that defendant made at least a limited investigation of Michigan gas sales during the course of which it must have examined some purchase contracts covering wellhead sales of gas in that state during 1952. In any event, whether this be so or not, it had equal access to the same contracts and information as plaintiff. Despite this fact, defendant did not offer in evidence any of these or other gas contracts. It made no attempt to prove that there were, in fact, comparable wellhead sales of gas comparable to that produced by plaintiff from the Howell Field.

Instead of producing evidence on this point, defendant simply suggests that Mr. Hinton’s determination that there were no comparable sales in the locality be rejected on the grounds that he had not made a sufficiently exhaustive study of either the production of the gas in question from the Howell Field or elsewhere in Michigan, and had a misconception as to what constitutes “comparable gas.” The reasons and arguments advanced by defendant in support of its position are unpersuasive.

It is true that some relatively small sales were used in computing the prices proposed by the parties both in the Eugo-ton ease, supra, and in the instant proceeding. And defendant correctly points out, as contended by plaintiff and discussed later, that small sales are evidence of market value where larger sales did not occur. However, the foregoing must be considered in light of the objectives sought, the point in controversy, and the entire factual situation presented. Although plaintiff’s expert could not recall the exact pressure of the Howell Field gas, it is undisputed that prior to the delivery of gas from McPherson No. 1-35 well in that Field to the Town of Howell, the pressure of such gas was lowered by a regulator through a mechanical separator at the wellhead. Since the Howell Field gas had to be decompressed before being injected into the gathering lines, the well pressures must have been substantial. Finally, as mentioned earlier, plaintiff’s expert determined that there were no comparable sales for several other reasons than the fact the wellhead sales found by him occurred more than 30 or 40 miles away from the Howell Field.

A thorough examination of the record and the testimony of plaintiff’s expert in regard to the Howell Field can only lead to the conclusion that there were no comparable wellhead sales of “comparable gas,” within any reasonable area of said Field, other than the one sale of gas from plaintiff’s McPherson No. 1-35 well therein. Mr. Hinton showed that he made a reasonable investigation and study of the Michigan area. His determination that, due to factors such as lack of volume or pressure or reserves or the quality of the gas involved in the wellhead sales he found outside the Howell Field, there were no sales at the wellhead of comparable gas within the “vicinity” of that Field, is found to be reasonable and accepted by the court.

If the court had not made the foregoing finding, the road ahead would be smooth and short, but lead to a result generally favorable to defendant. As it is, we face more difficult questions. Even if plaintiff bad produced evidence which convinced defendant there were no comparable wellhead sales of gas in the area, other than the one mentioned above, this would not have resolved the dispute between the parties. This is so because defendant contends that the one wellhead sale at 32y2$ per MCF of gas from plaintiff’s McPherson No. 1-35 well should not be deemed to establish the representative market price for the remainder of plaintiff’s Howell Field production.

In support of its contention that one sale does not make a representative market price, defendant points to the following language of this court in its first decision in the Hugoton case, swpra.:

Finally, it may be observed that the weighted average method increases the number of contracts which bear on the market price of the plaintiff’s gas. Hence it will not be necessary to rely on six or less contracts for each year in question, and the larger sampling should provide greater assurance that the price derived is in fact representative. [161 Ct. Cl. at 289, 315 F. 2d at 811.]

However, it should be noted that in the second Hugoton decision the court also said:

As of this time there has been no attempt to define definitively the total area to be considered in computing a representative “market” or “field” price. We believe that such an all-inchiswe rule cannot he laid down due to the fact that each case arises in its own particular context depending upon the surroundings in which the individual taxpayer finds himself. * * * [Emphasis supplied.] [172 Ct. Cl. at 464, 349 F. 2d at 431.]

Admittedly, it would make our task easier if there was evidence of other comparable wellhead sales of gas. But we must consider the problem in light of the situation that actually existed with respect to the issue at hand as shown by the record before us. Absent any other comparable wellhead sales of comparable gas, the one such sale in question certainly constitutes evidence indicative of the market price of plaintiff’s production in the Howell Field. This is not to say, however, that such evidence is completely controlling with respect to our resolution of the question as to whether the price paid for the gas involved in that one sale is an acceptable representative market or field price which should be applied to all of plaintiff’s Howell Field production.

Defendant suggests an inconsistency on the part of plaintiff in first criticizing as too small the volumes of gas involved in the samples used by the G-overnment in computing its representative prices for plaintiff’s Texas production in the years 1952 and 1953, and then seeking to have the court determine a representative price for plaintiff’s Howell Field gas production of 2,413,619 MCF based on the one wellhead sale of 215,-909 MOF. There is. no validity to defendant’s suggestion.

In the first place, many contracts were available for use by the parties in computing representative prices for plaintiff’s production in the Hugoton Embayment. The factual situation with respect to the Hugoton Embayment issue does not remotely compare with the one relating to the present issue. Furthermore, the one sale in question involved approximately eight percent of plaintiff’s entire Howell Field production in 1952, which in turn amounted to about one-half of the gas production in Michigan in said year. Under the circumstances of this case, it cannot be said that such sale is so small that it is not a factor deserving of consideration, If the one sale had involved a substantially larger volume of gas, it would have had greater significance. However, here too, we must proceed on the basis of facts established by the evidence and not on those we would like to have before us.

Moreover, that small sales are evidence of market price where larger sales did not occur is shown by Greensboro Gas Co., 30 BTA 1362 (1934), aff'd 79 F. 2d 701 (3d Cir. 1935), which case was cited by this court with approval in its second decision in Hugoton, supra. [172 Ot. Cl. 444, 455-56, n. 18, 349 F. 2d 418, 425, n. 18.] The taxpayer in Greensboro produced and sold gas from its own wells, but after transportation from the individual leases. The end sales price was approximately 400 per MCF. Production amounted to 1,164,328 MCF. The taxpayer also purchased 52,344 MCF of raw gas in its natural state at about 210 per MCF which it likewise transported, before resale. The Commissioner of Internal Revenue determined, the representative market or field price at 23$ per MCF. With reference to the purchased gas, the Board of Tax Appeals said:

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 BTA 1362, 1369.]

See also Riverton Lime and Stone Company, 28 T.C. 446, 454 (1957), where the Tax Court used small sales of taxpayer’s lime to represent the market price for the “much greater” sales of lime in another form. The situation in the instant case is closely akin to that in Riverton. There the taxpayer was, so to speak, the industry. Similarly, the plaintiff here, as the sole producer in the Howell Field, was the industry, and the absence of comparable sales by other producers does not forbid resort to a wellhead sale of identical gas.

As this court said in the second Hugoton decision, “the representative market or field price required by the Regulation [] demands the utilization of an accounting system which considers comparative sales.” [172 Ct. Cl. at 459, 349 F. 2d at 427] We have found that a comparative sale has been proven. Furthermore, since plaintiff had no competitors in the Howell Field or Michigan locale, no question is raised with respect to plaintiff obtaining some unfair advantage or preference over competitors which was the subject of concern and consideration by the court in the Hugoton case, supra.

The aforestated facts and discussion show that, literally and technically, a market price at the wellhead for plaintiff’s production from the Howell Field has been proven in strict compliance with the doctrine of the Eugoton and Shamrock cases, supra. Therefore, it could be argued that a good case has been made for the court to determine that the representative market or field price of plaintiff’s entire production from the Howell Field in 1952 was 32*40 per MCF. Despite the foregoing, it is concluded that using the market comparison method and making such a determination on the basis of the unusual facts existing with respect to the issue at hand would stretch to the breaking point the doctrine of the Eugo-ton and Shamrock cases, supra, and conflict with the basic objectives underlying the decisions therein; defeat the purposes which led to judicial approval of the market comparison method including the use of weighted-average prices; and produce a price that could not be reasonably and realistically considered representative, of plaintiff’s economic situation or a “representative market or field price” in any real sense of such term.

The above-mentioned consequences of establishing 32*40 per MCF of gas for all of plaintiff’s Howell Field production add up to an end result essentially parallel in effect to the one that, among other factors, led the court, on appeal, in United States v. Henderson Clay Prod., 324 F. 2d 7 (5th Cir. 1963), to reject the use of the market comparison method because it found such method to be “highly indigestible” [324 F. 2d at 12] . We, too, find that a determination by us here that a B2*40 price was the representative market or field price for plaintiff’s production of gas sold at said price after it was transported and delivered away from the lease property would produce an indigestible result which we decline to swallow.

Such a price would entitle plaintiff to a depletion allowance on the amount it received for the gas after transportation and delivery to the purchaser, a result that conflicts with the applicable Treasury Regulations. As previously stated in discussing the Hugoton Embayment depletion issue, this court said in the first Hugoton decision:

* * * From the outset, the producer [of gas] has been held entitled to include in gross income for purposes of the percentage depletion allowance only so much of the proceeds from the sale of the gas as he would have received had he sold the gas at the wellhead. [161 Ct. Cl. at 277, 315 F. 2d at 869.]

Certainly, 32%$ per MCF was not the amount that plaintiff under normal circumstances “would have received had he sold the gas at the wellhead.” Plaintiff received said price for the gas after it was gathered, transported, and delivered some distance away from the lease property. It is fair to assume that prior to the time plaintiff entered into the aforementioned contract with Consumers, a study and determination was made as to the costs involved in transporting the gas to the delivery points designated in the contract, and that these costs were taken into account in fixing the contract price. Obviously, the gas was worth less than 32%$ per MCF at the wellhead. That an identical price was fixed for both the gas to be sold and delivered on the lease property near the wellhead of plaintiff’s McPherson No. 1-35 well and the gas to be sold after transportation and delivery to points some distance away from the property, is not strange. It may be reasonably inferred that the parties agreed upon a single price for all the gas to be purchased under the contract because of sound business considerations. It is not inconceivable that the gas might have been priced at a higher figure if none of it was to be sold and delivered near the wellhead on the lease property.

We want .to emphasize that the court is not turning its back on the “market comparison” method used by the court in the Hugoton case. We have simply concluded that in the circumstances of this particular case, such method is not acceptable and proper.

Plaintiff recognizes that the court might have reasons for rejecting 32%$ per MCF as the representative market or field price of plaintiff’s entire production of gas from the Howell Field in 1952, and want to consider the 3%0 per MCF stipulated cost to plaintiff of gathering and transporting its gas away from the wellheads before sale. Accordingly, plaintiff makes the alternative suggestion that the court determine and allow plaintiff a price of 290 per MCF (321/20 less 3%0 cost of transportation) for the gas transported off the leases before sale.

Defendant contends that adoption of plaintiff’s proposal is barred by reason of the fact that in the second Hugoton decision, this court rejected the so-called “roll back” or “proportionate profits” method of determining gross income from the production of natural gas for percentage depletion purposes. Defendant advances some formidable argumente in support of its position, but they are not entirely valid or sufficiently persuasive to cause us to reject plaintiff’s solution to this perplexing problem.

In the first place, plaintiff’s alternative proposal does not contemplate the use of factors essential to qualify it as a true “proportionate profits” method or formula. Such method is briefly described earlier in this opinion in connection with our discussion of the Hugoton Embayment depletion issue and will not be repeated here.

Defendant concedes that in the following sentence quoted from the first Hugoton decision “there is perhaps a negative inference that under certain circumstances some other method might be acceptable”:

* * * On the basis of the record compiled in this case, we are convinced that the problem of determining a representative market or field price for this taxpayer’s gas is not Of such unusual or inordinate difficulty as to preclude use of the method prescribed as the norm by the applicable regulations. [161 Ct. Cl. at 283, 315 F. 2d at 873.]

Defendant then hastens to say that the second Hugoton decision is “much more emphatic and appears to hold that comparable sales constitute the only permissible method of arriving at ‘gross income’ where gas is sold away from the wellhead.” In support of the foregoing, defendant quotes language from said decision showing that the court interpreted the applicable Treasury Regulation as embodying in it “only one concept — ‘representative market or field price’ ”; determined that said “Regulation is of unquestioned validity,” and concluded that a literal reading thereof “forecloses any consideration of a proportionate profits formula.” [172 Ct. Cl. at 459, 349 F. 2d at 427.]

As to the language last quoted from the court’s first Hugo-ton decision, we cannot say here that on the basis of the record compiled in the instant proceeding, the problem of determining a representative market or field price for plaintiff’s gas production 'in question presents such little difficulty that we are precluded from using “the method prescribed as the norm by the applicable regulations.” 'On the contrary, we find that such method produces such an unrealistic result that another formula must be used.

With respect to the statements and conclusions of the court in the second Hugoton decision referred to above, we read the language in question to mean that the applicable regulation requires the use of a “representative market or field price,” if an acceptable price of such nature can be established. Neither the court’s decision in that case nor the regulation requires the impossible, i.e., the use of a price that cannot be determined representative, or as precluding us from applying some other formula that produces a fair result. To hold otherwise would mean that in the instant proceeding the Government has successfully presented to plaintiff a “heads I win, tails you lose” proposition.

Furthermore, it must be kept in mind that in determining plaintiff’s gross income from its Howell Field properties in 1952, the Commissioner used as a representative market or field price of plaintiff’s produced gas, an amount which was equivalent of the rate per MCF at which plaintiff paid royalties to its lessors in said Field. In Shamrock Oil & Gas Corp., supra, the court expressly rejected resort to royalty prices paid by tbe taxpayer there. In the Hugoton case, the court’s rejection of the use of such prices was more by implication. Thus, if we reject the alternative formula that plaintiff proposed be used in establishing a price for its transported gas and determining plaintiff’s gross income therefrom, it will be unfairly left with a depletion allowance based on a royalty pricing approach which the courts have determined to be unacceptable.

Considering all the facts and circumstances present here in light of the applicable statutes, regulations, and legal precedents, it is concluded, on balance, that in determining plaintiff’s 'gross income from the property for its Howell Field production in 1952, for percentage depletion purposes, the price of 321,40 per MCF should be used with respect to the 215,909 MCF of gas sold in that year near the wellhead of plaintiff’s McPherson No. 1-35 well.

As to the remainder of plaintiff’s production of gas from the Howell Field which was sold in 1952, after the gas was transported off the leases, there should be deducted from the 32140 per MCF sales price of such gas, the stipulated cost of 31,40 per MCF to plaintiff of gathering the gas from its wells and transporting it off the leases to the delivery points designated in the contract between plaintiff and Consumers, resulting in a price of 290 per MCF which shall be used with respect to this production.

Defendant has made no argument, nor does there seem to be any reason why there should not be added to plaintiff’s gross income, the $4,150 it realized from the sale of hydrocarbons obtained by passing a portion of the Howell Field production through a field separator. That these hydrocarbon sales resulted in depletable income should not be open to serious question. They are so included in plaintiff’s de-pletable income in the Hugoton Embayment. Accordingly, said amount should be included in plaintiff’s gross income.

IV

defendant’s claimed setope

For the years 1954 through. 1956, plaintiff claimed and was allowed to depreciate its post-1953 investment in gathering line rights-of-way on the double declining balance method. In its exceptions to the trial commissioner’s report and brief, the defendant claims the right to set off against any recovery by plaintiff, the amount that would be due defendant if such depreciation allowances had been computed under the straight line method.

The record shows that the right to the setoff was not pleaded either as an affirmative defense or as a counterclaim; that it was not mentioned during the pretrial conference; that defendant submitted no evidence in behalf of the claim, and that it requested no findings of fact with respect thereto.

It is apparent that defendant failed to comply with the rules of the court with respect to its setoff and that the claim is untimely. Eastern School v. United States, 180 Ct. Cl. 676, 381 F. 2d 421 (1967) ; GMO. Niehaus & Co. v. United States, 179 Ct. Cl. 232, 253, 373 F. 2d 944 (1967); Missouri-Pac. R.R. Co. v. United States, 168 Ct. Cl. 86, 338 F. 2d 668 (1964).

In the light of the record and for the reasons stated in the cases cited, defendant’s setoff is denied.

FINDINGS OP PACT

The court having considered the evidence, the report of Trial Commissioner Franklin M. Stone, and the briefs and arguments of counsel, makes findings of fact as follows:

Jwrisdictional and general facts

1 (a). The petitions in these three actions were filed against the defendant pursuant to the provisions of 28 U.S.C. § 1491, for the recovery of income taxes for the calendar years 1952 to 1956, inclusive.

(b) Case No. 547-58 relates to the calendar years 1952 and 1953; case No. 166-60 to the calendar years 1954 and 1955; and case No. 400-61 to the calendar year 1956.

(c) These cases were consolidated for trial since they involve common questions of law and essentially the same type of factual matters.

(d) During pretrial proceedings, the commissioner approved the agreement reached by the parties and set forth in a written stipulation filed by them with the court, that the trial of these consolidated actions be limited to issues of law and fact relating to the right of plaintiff to recover, reserving the determination of the amount of recovery and the amount of any offsets, if any, for further proceedings under Eule 47(c).

2. Plaintiff is a Delaware corporation having been incorporated on December 23, 1929. Its principal office is located at 3444 Broadway (P.O. Box 1348), Kansas City, Missouri. The corporation is principally engaged in the business of producing, purchasing, transporting by pipeline, and selling natural gas to utility companies for resale and directly to industries for their own use. It also operates a natural gasoline plant and other facilities for the separation of heavier hydrocarbons from the raw natural gas both at central points and on the producing properties. In addition, it derives revenue from other companies for the separation by them of heavier hydrocarbons from plaintiff’s raw natural gas stream. It is also engaged in the production and sale of oil. Plaintiff’s books of account were maintained and its tax returns filed on the accrual basis for taxable years ending on December 31. Plaintiff at all times material herein was a natural gas company under the Act of Congress of June 21,1938, 15 U.S.C. § 717 el seq., known as the “Natural Gas Act” and hereinafter cited as “Natural Gas Act.” As such, a substantial portion of plaintiff’s operations was subject to the jurisdiction of the Federal Power Commission (hereinafter sometimes referred to as the EPC).

3 (a). Plaintiff’s income tax returns for the calendar years 1952 through 1956 were filed with the District Director of Internal Eevenue at Kansas City, Missouri. Said returns disclosed income tax liabilities, all of which were paid to said District Director, as follows:

Tear Taa liability
1952 _$14,900,167. 72
1953 _ 15, 036, 880.21
1954 _ 863, 256.00
1955 _ 1, 050,534. 00
1956 _ 6, 056,022. 00

(b) Thereafter, on audit of these returns by the Commissioner of Internal Revenue, additional income taxes were determined to be due from plaintiff. The said additional taxes (exclusive of interest) were paid by plaintiff to the District Director in the following amounts:

Tear Deficiency
1952 _$118,088. 84
1953 _ 601,172.64
1954 _ 530,931.00
1955 _ 255,798.00
1956 _624,765. 00

In addition, plaintiff paid interest on these deficiencies.

(c) Within the times prescribed by law, plaintiff filed with the District Director its claims for refund covering the issues raised in its petitions. Thereafter, all of said claims were disallowed on the following dates:

Tear Date of disallowance
1952 August 19,1958.
1953 August 19,1958.
1954 July 7,1959.
1955 July 7,1959.
1956 July 21,1961.

4. Plaintiff is the owner of the claims herein asserted and no assignment or transfer of the same or any part thereof has heretofore been made.

Depreciation and Amortization of Rights-of-way Acquisition Costs Issue

5. Natural gas is transported cross-country through underground pipelines called transmission lines. These pipelines have a diameter as large as 42 inches and consist of sections of steel pipe averaging in length from 20 feet for older style pipe to 40 feet for newer pipe. The pipe sections are joined together by couplings or by welding. The transmission lines are a part of a system for the movement of natural gas from the gathering lines to industrial customers and utility or distribution companies. The gas is transported in the pipeline by compression which causes it to move from the point of high pressure to a lower pressure area. Friction slows movement and causes the pressure of the gas to decrease which in turn requires the recompression of the gas at periodic distances in compressor stations. Natural gas transmission systems have a design pressure r!ange of from approximately 400 to 1,000 pounds per square inch. The higher the line pressure, the greater the amount of gas that can be transported. Gathering lines are pipelines which connect the natural gas wells with the transmission system and which are operated at pressures below that of the transmission lines. Natural gas is normally measured in cubic feet, related to a specific pressure base. The expression MCF means 1,000' cubic feet. The term MMCF means a thousand, thousand cubic feet of gas or 1 million cubic feet. The pressure base is the amount of pressure per square inch exerted on the gas occupying a square foot of space.

6. An integrated natural gas transmission system consists of rights-of-way across the land in which the pipe is laid, the pipe, valves, gas-conditioning equipment, concrete supports, land, buildings in which are housed the engines and turbines making up the compressor stations, hardware to control the through-put of gas and/or engine control, safety equipment, usually some type of communication equipment such as telephone, microwave or radio, regulating stations, measuring stations, and a wide assortment of miscellaneous property.

7. Plaintiff’s principal natural gas transmission system as of December 31, 1956, extended a distance of approximately 1,200 miles in and from the Hugoton Embayment through the States of Texas, Oklahoma, Kansas, Missouri, Illinois, Indiana, and Ohio into the State of Michigan. This principal transmission system consisted of three parallel lines, two of which extended along the entireT,200 miles, and a third line from plaintiff’s Liberal, Kansas, compressor station to a point 78 miles from Detroit, Michigan. The three lines are not always in the same relative position; on occasion they cross one another and are in every conceivable combination of relative position. A substantial portion of the third line was constructed during the years 1952 and 1955. As of December 81, 1956, plaintiff’s natural gas transmission system also included three single lateral lines in Illinois, Indiana, and Michigan.

8. Plaintiff’s original pipeline, designated as line 100, was constructed in 1929 and 1930. It was designed to operate at a pressure of 450 pounds per square inch. Following extensive testing and changing of valves in 1953 and 1954, plaintiff increased the operating pressure to 625 pounds. Prior to the increase in pressure, plaintiff removed 100 sections of pipe from various points in the line; each section was capped and pressured to destruction to determine its strength. Then the entire 1,200 miles of the line were filled with water at a pressure of 781 pounds per square inch. As a result, there were approximately 800 breaks in the line, each of which was repaired by taking out a piece of the pipeline and replacing it with a new piece. In 1965, the line was still safely operated at 625 pounds pressure. In 1937, plaintiff, in order to increase its capacity, began the construction of a loop or parallel line to its line 100. This line, known as line 200, was finished in 1944, and was designed to operate at 800 pounds pressure. Plaintiff’s third pipeline, known as line 300, was begun in the late 1940’s and completed in 1955. It was designed to operate at 900 pounds pressure. In 1962, plaintiff began the construction of its fourth pipeline, known as line 400. It is still under construction at the present time. The latter line was also designed to operate at 900 pounds pressure. In line 100, the pipe sizes used were 20, 22 and 24 inch; in line 200, the sizes were 24- and 26-inch pipe; in lines 300 and 400, 30- and 36-inch pipe were used.

9. Trunkline Gas Company, a Delaware corporation (hereinafter referred to as “Trunkline”), is a wholly-owned subsidiary of plaintiff. Plaintiff acquired 96.8 percent of the common stock of Trunkline between May 1950 and October 1951, and obtained full ownership in 1958. In these consolidated actions, plaintiff is not claiming depreciation with respect to Trunkline’s property, and plaintiff is not seeking the recovery of any tax paid by or on behalf of Trunkline. In other words, Trunkline is not a party to this consolidated proceeding.

10. As a result of an. expansion program commenced in 1950, plaintiff has increased the designed capacity of its pipeline system from 500,000 MCF per day to approximately 1,250,000 MCF per day as of April 1956. About one-half of such increase was the result of the installation of Trunkline facilities at a cost of approximately $1 million, and the construction of additional capacity on the plaintiff’s system to receive such gas and deliver same to its markets. The remaining increase in designed capacity resulted from an expansion of plaintiff’s main-line system, consisting of the construction of plaintiff’s third-loop line, the installation of additional compressor facilities and operating improvements in the system, at a cost of approximately $65 million. In addition to these expenditures approximately $35 million has been expended for production and gathering-line facilities which had been added during this period.

11. Plaintiff’s transmission lines were connected to gathering systems in the following gas fields in the Hugoton Em-bayment at December 31,1956:

Texas: Panhandle and Hugoton Fields.
Oklahoma: Hugoton, Liberal Light, Keys, Enns or Camrick, North Richland Center and North Hardesty Fields.
Kansas: Hugoton, Shuck, Greenwood, Elkhart, Taloga, Pleasant Valley, Wide-Awake, Interstate and Richfield Fields

The plaintiff also received a portion of its gas supply from the Howell Field in Michigan, and from its subsidiary, Trunkline, in Illinois.

12. Plaintiff’s transmission system consisted of 4,757.5 miles of main-line pipe of various sizes as of December 31, 1951, and 4,961.1 miles of main-line pipe of various sizes as of December 31, 1956. Plaintiff’s gathering systems, which extended out from the main line into the various producing fields and moved the gas to the main line, consisted of 508.7 miles of pipe of various sizes as of December 31, 1951, and 1,173.8 miles as of December 31, 1956. The pipe sizes of the gathering systems ranged from 8 inches in diameter up to 20 inches.

13.The major part of the gas transported by plaintiff was sold to gas distribution companies for resale. Plaintiff’s types of sale and sales areas were as follows:

Gas utilities for resale: Texas, Kansas, Missouri, Illinois, Indiana, Michigan, Ohio, and Canada.

Industrial: Kansas, Missouri, Illinois, Indiana, Michigan, and Ohio.

Field: Texas, Oklahoma, and Kansas.

Commercial: Texas, Kansas, Missouri, and Illinois.

Residential: Texas, Oklahoma, Kansas, Missouri, Illinois, and Indiana.

Plaintiff, as of December 31, 1956, produced approximately one-fourth of its gas requirements and purchased approximately three-fourths from others, including Trunkline.

14.The annual volumes of gas sold by Trunkline and the amounts thereof purchased by plaintiff, stated on a 14.65 pounds per square inch absolute (p.s.i.a.), are shown by the following tabulation:

Year ended December 31 Sales in MCF Purchases by plaintiff— MCF
1951-21,759,260 21,758,652
1952. 1953-1954-1955-1956-92,037,603 95,721,895 97,468,504 100,778,824 129,959,799 91,867,179 95,480,037 96,615,084 99,884,920 128,716,015

15.In order to construct its pipeline systems, over the years plaintiff has obtained from the owners of the land through which the pipelines are to be laid, right-of-way grants or agreements. In most instances, it has been able to reach an agreement with the landowners involved. However, under the Natural Gas Act, as a holder of a certificate of convenience and necessity, plaintiff does have the power of condemnation which permits the laying of a single pipeline for the transportation of natural gas through an owner’s land. Plaintiff has had to resort to condemnation in a few instances in order to lay its lines. It tries to avoid condemnation wherever possible because such proceedings are time-consuming and expensive.

16. Plaintiff’s procedure in obtaining right-of-way agreements may be summarized as follows:

Plaintiff’s engineering department gives the right-of-way division of the corporation a map or sketch indicating the route of the pipeline. The right-of-way division then prepares a certificate of title on which is described each of the tracts of land to be traversed. These are sent to outside ab-stractors who supply the name of the latest record owner and how he obtained title. From this information, the right-of-way division prepares the right-of-way agreements and related papers which are sent to agents who negotiate with the landowners. If an agreement is secured, as it is in most instances, it is acknowledged, checked for accuracy and recorded in the local county. The agreements are recorded in order to give notice of plaintiff’s right to cross the tracts involved.

17 (a). A typical right-of-way agreement obtained by plaintiff states as follows:

* * * in consideration of One ($1.00) Dollar, to them in hand paid, receipt of which is hereby acknowledged, and the further consideration of $1.00 per linear rod, to be paid when the pipe lines hereinafter specified are laid, do hereby grant- and convey- unto Panhandle Eastern Plpe Line Company, a Delaware Corporation of Kansas City, Missouri, its successors and assigns, a Night-of-Way to lay, construct, maintain, alter, repair, replace, change the size of, operate, and remove pipe lines and from time to time parallel pipe lines, drips, gates, telegraph and telephone lines, and all appurtenances convenient for the maintenance and operation of said lines and for the transportation of oil, gas, or other substances therein, and the Grantee is granted the right of ingress and egress, to and from the following described land for the purpose of constructing, inspecting, repairing, operating, changing the size of, or removing at will, in whole or in part, said property, from, on, over, and through the following premises in the County of Texas in the State of Oklahoma, to-wit:
iji
_ To Have and To Hold said easement, rights, and right of way unto the said Panhandle Eastern Pide Line Company, its successors and assigns.
Said sum is acknowledged as full consideration for the Right-of-Way. Should additional or parallel pipe line or lines be laid at any time, $1.00 per linear rod shall be paid for each such line so laid. All damage to growing crops occasioned by the installation of the first line or by making future repairs or in removing said property, or by laying, repairing, or removing other lines, drips, and gates, shall be paid by grantee after the damage is done; said damages, if not mutually agreed upon, to be ascertained and determined by three disinterested persons, one to be appointed by the grantor, one to be appointed by the grantee; and the third to be chosen by the two so appointed. The written award of such three persons shall be final and conclusive.

In some instances, the right-of-way agreement obtained by plaintiff contains the following language:

This Agreement is binding upon the heirs, executors, administrators, successors, and assigns of the parties hereto, and it is understood that this Agreement cannot be changed in any way except in writing, signed by the grantor_, and a duly authorized agent of the grantee.

(b). In the States of Texas, Oklahoma, Kansas, Missouri, and Illinois, the right-of-way agreements permit the “transportation of oil, gas, or other substances.” In the States of Ohio and Michigan, such agreements provide only for the “transportation of natural gas.” In the State of Indiana, certain of these agreements are the same as those made in the last two mentioned States, while other agreements obtained or owned by plaintiff for the State of Indiana do not specify the materials which may be transported or limit them to “oil, gas or other substances.” Plaintiff used the same form of agreements in connection with the acquisition of rights-of-way for its transmission systems and its gathering systems.

18 (a). Except in a relatively few cases, the right-of-way agreements originally entered into in 1930-1931 and throughout the following years specified no width and permitted the laying of more than one pipe across the landowner’s land. Less than 10 percent of the agreements which plaintiff had during the period 1952 through 1956 specified the width of the right-of-way. Some of plaintiff’s right-of-way agreements limit plaintiff to the construction or replacement of no more than two pipelines. Agreements which do not specify the width of the right-of-way or limit plaintiff to laying but one pipeline are known as “multiple line” right-of-way agreements. Despite the lack of width designation in such agreements, plaintiff, as a matter of practice, confines its operations to the route of the pipeline and within a specified width of its own determination. Plaintiff’s standard right-of-way agreement form provides for multiple line rights. Plaintiff prefers a multiple line agreement over a single line agreement and attempts to obtain the first-mentioned type of agreement, not only because it has certain advantages, but also because plaintiff’s deletion of the provision in the form agreement for multiple lines constitutes a concession which is helpful to plaintiff in its negotiations with a landowner for a right-of-way agreement.

(b). The principal advantage of a multiple line agreement is that it eliminates the need for instituting a condemnation action, if plaintiff desires to lay additional pipelines and the landowner refuses to enter into a new agreement. Other advantages of such an agreement are that plaintiff may lay additional lines without having to pay the $1 consideration stated in each agreement or incurring other incidental expenses, such as notary, recording and legal fees.

19. Plaintiff acquired some of its right-of-way agreements not from the landowners, but by agreement from predecessor corporations which were named as the grantees in the agreements and were the parties that obtained the agreements from the landowners. All of plaintiff’s right-of-way agreements are transferable. The only other evidence in the record with respect to the actual transfer of right-of-way agreements involved the Transcontinental Gas Pipe Line Company which acquired certain rights-of-way for a pipeline to be constructed in New York and Connecticut; thereafter, Transcontinental decided not to build the line and sold the rights-of-way to another gas company. This was a jurisdictional matter and the transaction was approved by the FPC. The above-mentioned inter-corporation assignments and isolated sale do not refute uncontradicted testimony to the effect that there is no market for an old used right-of-way. On the basis of the evidence of record considered as a whole, it cannot be found that there is a real market for right-of-way agreements either with or without a pipeline laid on the lands subject to such agreements.

20. In its negotiations with landowners, it is plaintiff’s practice to pay the $1 consideration mentioned in its right-of-way agreements. In addition, plaintiff pays to the landowner a fixed amount per linear rod crossed in the pipeline construction. This latter payment is known as a roddage fee and has been paid by plaintiff in all of its right-of-way acquisitions since 1929 or 1930. Plaintiff’s right-of-way agreements usually specify a rate at which the roddage fees are to be paid. The rate will vary from 25 cents per rod in the older agreements up to $5 per rod currently, depending upon the area to be crossed. Plaintiff usually pays the going price in a given area as set up by other pipeline companies.

21. In addition to right-of-way agreements, plaintiff has to obtain highway and railroad licenses or permits when its pipelines cross a highway or a railroad. These are obtained from the governing body or the railroad company involved. On county roads, plaintiff obtains a blanket permit for each pipeline to cross all roads in the county. The charges for highway crossings will vary from state to state. On railroad crossings plaintiff generally pays an annual rental. The costs incurred by plaintiff in obtaining highway, road, and railroad permits are not a major factor in relation to its overall right-of-way costs. For crossing rivers designated as navigable by the United States Government, plaintiff has to obtain a permit from the United States Army Corps of Engineers.

22. In the acquisition of its right-of-way agreements, plaintiff incurs or pays, in addition to the stated consideration and roddage fees, various other costs such as clerical expenses, secretarial expenses, abstract fees, legal fees, recording fees of from $1 to $2, office expenses, notary fees, expenses of obtaining road, highway, railroad and navigable stream crossing permits and the like, the expenses of negotiating right-of-way agreements, and legal expenditures and other expenses relating to condemnation proceedings.

23. The construction of a pipeline is let on contracts to a contractor after competitive bidding. The actual construction is performed by what is known as a “spread.” A spread is the total complement of men and equipment used on a specific project. This may involve on the average a million and a half dollars in equipment and from 200 to 400 men. The pipeline contractor’s first operation in laying the line is to clear sufficient width on the right-of-way to permit the men and equipment access to the pipeline route. This is usually about 25 feet. Clearing entails the cutting of any fences across the right-of-way, and removal of any timber, brush and vegetation 'thereon. The contractor clears just a sufficient area so that liis men and equipment can get through the route. Clearing for any given line is not done with a view to laying a possible second pipeline in the future. The cleared right-of-way is then graded so that the necessary equipment and material can be brought in. Following the grading operation, the pipe and other construction material are brought onto the right-of-way and laid along the cleared and graded route. A ditch is then dug by equipment to provide a trench in wMch the pipe will be placed.

24. The pipe joints, which today average about 40 feet in length, are straight as they come from the mill and must be bent by the contractor to conform to the bottom of the trench or to follow changes in horizontal direction. After any necessary bending operation, the contractor aligns the pipe joints end to end beside the trench. The joints are subjected to a preliminary welding to hold them together. Then the joints are finally welded together, and cleaned and coated over their entire length. Next, the pipe is lowered into the trench and the trench is covered and backfilled. The pipeline is tested by hydrostatic pressure. On stream or river crossings, the banks are graded to accommodate the bend of the pipe and ditches are dug across the rivers to hold the pipe. Major river crossings are usually a specialized operation. As to highway and railroad crossings, the pipe is usually inserted in a joint of larger-sized pipe, called a casing, which has been driven under the highway or railroad. The final construction operation involves the cleaning up or regrading of the right-of-way in order to return it as nearly as possible to its original condition.

25. The construction of a pipeline occasions damage to the landowner’s properties such as the destruction of growing crops, trees and shrubbery, the cutting of fences, and the like. Even though plaintiff’s right-of-way agreements speak only of damage to growing crops, it has been plaintiff’s policy to pay for all actual damages caused. In about 20 percent of the cases these damages are estimated in advance of construction and paid to the landowner or his tenant. In such instances, no further payments are made after construction. In the remaining oases, plaintiff settles damage claims after the construction of the line is completed.

26. A loop line is an additional pipeline laid adjacent to or parallel to an existing pipeline. The purpose of the construction of a loop line is to increase the capacity of the system to transport gas. It has been plaintiff’s practice that where possible its loop or parallel lines are laid a minimum of 50 to 60 feet from an existing line. The loop line is connected to an existing line at one point and reconnected at another. It operates on the same pressures as the original line. At the time that the loop line becomes a complete and separate line, its pressure is increased to its approximate designed amount. For instance, plaintiff’s line 200 was originally a loop line to line 100 and operated at the operating pressure of line 100, or 625 pounds. It now operates at a pressure of 800 pounds. Higher pressures permit the transportation of more gas. If the plaintiff should desire to increase capacity in the future, it most likely would loop the line which has the highest pressure. It would be economically and practically infeasible to loop a lower pressure line.

27. The building of a parallel or loop adjacent to an existing line involves substantially the same steps by plaintiff’s right-of-way division as were taken in the construction of the original line. (See finding 16.) The landowners are approached and if a new right-of-way is needed, an agreement is reached with the landowners just as in the case of the original line. If existing right-of-way agreements are sufficient, plaintiff will pay roddage fees but will not in such instances again pay the $1 consideration stated in the agreements. In that event, it will not record a new agreement. With the relatively minor exception of such consideration and the recording fees, plaintiff reincurs practically the same costs it incurred in connection with the original line. This has been plaintiff’s experience on all three of its parallel or loop lines. In situations where a new right-of-way agreement is needed, the stated consideration is paid and the agreement recorded. In the case of parallel or loop lines constructed under an existing multiple-line right-of-way agreement, plaintiff’s general practice is to pay the “going rate” of roddage fees in a given area even though a lower rate is specified in the earlier agreement. Such action is taken by plaintiff in order to avoid dissatisfaction on the part of the landowner which might lead to costly litigation and/or delay in construction. Furthermore, common sense dictates the necessity of being on good terms with the landowner due to the fact that the line must be maintained. This entails entering on the landowner’s property from time to time and it is helpful if he is on good terms with plaintiff. Eoddage fees and other costs of rights-of-way, except the stated $1 consideration and possibly recording fees, have gone up over the years and it may be reasonably assumed that roddage fees, as well as other costs, except the stated consideration, will increase in the future. During the years 1952 through 1956, plaintiff had a total of approximately 6,000 separate right-of-way agreements.

28. The construction of a parallel or loop line involves the same operations as were carried out on the original line. (See findings 23 and 24.) The new line has to be surveyed in order to show the contractor and landowner just where the line will go. The contractor obtains no benefit from the prior construction and the presence of the existing line will increase costs because of the need for additional precautions to avoid injury to the old line. The clearing and grading operations performed on the prior line do not benefit the new line. The location of the existing line some 50 or 60 feet away could increase the contractor’s costs as much as 10 cents per foot or 3 to 5 percent of the total cost.

29. Plaintiff used the same right-of-way agreement forms in connection with the acquisition of rights-of-way for its gathering systems as were used in obtaining such rights for construction of its main transmission lines. Plaintiff incurs roddage fees and substantially the same other types of costs it incurs in obtaining its main line transmission rights-of-way as it does in acquiring right-of-way agreements for its gathering lines, and such expenses are reincurred if parallel or loop gathering lines are laid; however, such costs are not incurred for laying main, parallel or loop gathering lines on a particular tract of land under an oil and gas lease, since leases of this kind give plaintiff the right to construct such lines on the leased land for the purpose of taking gas from a well thereon across the lease property.

30. A natural gas pipeline is subject to corrosion. Plaintiff’s transmission system is unlikely to corrode in a uniform maimer because some areas have more corrosive soil than others. The normal maintenance of a natural gas pipeline involves the use of cathodic protection to reduce corrosion of the pipe, the periodic patrol of the line for the detection of leaks and their repair. Plaintiff has experienced gas leakage, particularly on line 100 where the gaskets on the dresser couplings dried out. Plaintiff has also made repairs and replacements of its lines on account of excessive corrosion. In about 1956, two 5-mile sections of line 100 adjacent to the Missouri Eiver were taken out of service and repaired or replaced. The pipe was lifted out of the trench; the dresser couplings were taken off; the pipe was cleaned; wherever the pipe was deteriorated beyond use, it was replaced with a new joint or pipe; wherever the pipe could stand patching, it was patched; and the pipe was welded, painted and laid in the old trench. In the future, it is likely that additional portions of this line will have leaks and require similar action by plaintiff. In the 1952-1956 period, line 100 consisted of over 99 percent of the original pipe, the small balance being new pipe installed as a repair or replacement. Such repairs do not increase the capacity of the old line. Plaintiff expects that it will need increased capacity for the transportation of natural gas. Such increased capacity cannot be obtained by partial replacements of line 100. The increased capacity could most economically be obtained by constructing a new line adjacent to the highest pressure line.

31. After the construction of a line, plaintiff permits the landowner to grow crops oyer the buried pipe and on occasion has allowed trees to grow on the right-of-way if not too close to the pipeline. It does not permit houses or other structures to be built over the line since they would interfere with maintenance work.

32 (a). It is physically possible to lift an old pipeline out of the ground, provided the line or the section thereof to be removed can be taken out of service. The lifting operation entails locating the old line, then carefully digging down to the top of the line and lifting out the pipe. If the line is to be repaired or reconditioned, the pipe is cut up into sections, cleaned, the old welds and corroded sections cut out, revalved, coated and wrapped. The old trench or ditch would have to be cleaned out, backfilled and reditched. Such work may slightly improve the safety of the line, but the pipeline company would still have a secondhand pipeline with no increase in capacity. If the old pipe is not to be reused, the company must straighten it, clean it, remove it to a central yard, inspect it, and attempt to sell it. The lifting operation probably would cause some damage to the land which would have to be paid to the landowner.

(b) It is apparent from the foregoing and the record that while isolated sales of old pipe have been made, there is no real market for large quantities thereof for use in pipeline transmission systems. The testimony discloses that in 1964, a group purchased about 200 miles of 20- and 22-inch transmission line abandoned by Colorado Interstate Gas Co. in the ground, with the hntenit to reclaim the pipe and sell it. The pipe was laid in 1928 and 1929 and was virtually the same as is in plaintiff’s line 100, that is, lap-welded pipe. The group sold 7 miles of the pipe to the City of Colorado Springs, Colorado. This 7 miles was lifted from the ground, cleaned, and then relaid in the immediate vicinity for the purchaser. It took sorting through 11 miles of old pipe to find 7 miles of usable pipe. The pipe was thereafter satisfactorily operated at the same pressure at which it had been originally operated. The group also sold BO miles of the pipe to the Kansas Power and Light Company which relaid the pipe. The pipe has not been put into service due to numerous breaks at a test pressure of 700 pound's. At the time of the trial, the testing of this 30 miles of pipe had been going on for some 3 months, the pipeline was not yet in service, and there was some considerable doubt as to when the pipeline would be ready for use. There is no evidence that sales of old pipe for junk would be profitable or that there is a market for junk pipe.

(c) In some instances, old pipe has been used as casings where pipelines pass under highway and railroads, but pipeline companies usually use mill reject pipe for such purposes. The use of old pipe for these purposes is generally impracticable because highway authorities often refuse to approve the use of such pipe for one reason or another. Old pipe must be straightened before it can be used for casing and has to be sufficiently large in diameter to accommodate the pipe to be placed through it. There is no evidence that there is a market for old pipe to be used as casings.

33. The technology of pipe used in the construction of pipelines has greatly changed over the years. The plaintiff’s original line 100 was constructed with lap-welded pipe. Lap-welded pipe was steel plate formed into a cylinder with the two edges of the plate brought together and fused. For many years lap-welded pipe has been recognized as being somewhat inferior. The Code for Pressure Piping requires lap-welded pipelines to be operated at pressures of only 80 percent of that at which a modern-day welded pipeline can be operated. Pipe installed in line 100 was single random length, approximately 20 feet long, 20, 22 and 24- inches in diameter, thick-walled, joined together by dresser couplings, and originally designed to operate at only 450 pounds pressure. The pipe being installed in plaintiff’s line 400 is approximately 40 feet long, 30 and 36 inches in diameter, thin-walled, all welded and designed to operate at a pressure of 900 pounds. Because of these changes in technology, it may be reasonably concluded that in order to increase capacity, which it is anticipated will be necessary in light of expected expansion of the gas business, plaintiff will, in all probability, consider it economically and practically feasible to lay a loop line connected with, the newer high-pressure portion of its system.

34 (a). A whole transmission line does not suddenly go bad all at once. Faults such as leakage due to defective valves, corrosion of pipe and other factors occur periodically in different places throughout any gas transmission system. Sometimes necessary repairs can be made without extensive digging or removal of large segments of the line. In some iiistances segments of pipe of varying lengths must be removed in order for repairs to be made or the pipe reconditioned. In many cases relatively small segments of a line are removed from the ground and repaired and/or reconditioned, however, uncontroverted and credible testimony was presented at the trial that where more than 1,000 feet of line has to be repaired, reconditioned or replaced, it is more economically feasible to lay a parallel line by looping the old line and to abandon the defective portion thereof in place. Witnesses who testified to that effect stated that in reaching such conclusion, they considered the costs of acquiring new rights-of-way, paying additional roddage fees, the construction costs, the preliminary fees of the attorney and architectural-type 'fees, and clerical office expenses.

(b). The cost of acquiring rights-of-way is a relatively incidental part of the overall expense incurred in the construction of a pipeline system. The income, if any, that would be realized from the salvaging of old pipe, and the reduced costs that would result from not having to pay new roddage fees if the old trench or ditch was reused, are not sufficient to justify the lifting of an old pipeline and the laying of a new line in the old trench or ditch.

35 (a). One of the most important reasons that plaintiff undoubtedly would take into consideration in reaching a decision in regard to removing a segment of the line for purposes of repair, reconditioning or replacement is the effect such action would have upon the company’s deliveries during the time the line was out of service. The curtailment of deliveries is a great economic factor. Moreover, in this connection, plaintiff necessarily would have to consider the requirements of the FPC. There is little doubt that to replace all of plaintiff’s oldest line 100 at one time wonld require taking tlie line out of service and that the company would not be able to operate with, that much curtailment in its gas deliveries. The practice of the natural gas industry, including plaintiff, is not to lay a completely new line. Instead, expansion begins by the construction of loops tied into the highest pressure existing line, and plaintiff’s own experience shows that it takes many years before the loop line becomes a complete line in itself.

(b). If plaintiff’s line 100 should have to be taken out of service, plaintiff could maintain the same capacity by looping from between 30 to 40 percent of its highest pressure existing line. It is reasonable to conclude that plaintiff also would consider the effect of having a lower pressure system reconditioned, as opposed to gradually building up to increased production by building a new loop line which, due to advanced technology in pipe construction, is able to carry gas at a higher pressure and might eventually become an independent parallel line. The partial replacement of plaintiff’s line 100 would not give the company the increase in capacity which it anticipates will be needed in the future.

36. The superintendent of plaintiff’s right-of-way division testified that he could recall only one instance where plaintiff abandoned any rights-of-way. This involved a lateral line some 30 miles in length located in Indiana that was built under agreements some of which permitted plaintiff to build only one line while others allowed it to lay two or more lines. After constructing the original line, plaintiff, in 1958, built a second line and at that time it abandoned the first line, leaving the pipe in place, apparently for the reason that there was no market for old pipe at that time. To the extent the original grants permitted plaintiff to lay at least one additional line, the rights-of-way were retained and the second line was constructed under the original agreements. The rights-of-way acquired under the original grants which did not provide for multiple lines were abandoned and the second line was constructed under new right-of-way agreements.

37. Under the Natural Gas Act, supra (finding 2), the FPC has certain regulatory jurisdiction oyer plaintiff as an interstate natural gas pipeline company. In general, the FPC regulates the prices plaintiff can pay for purchased gas and prices at which it can sell gas to customers for resale. The major part of plaintiff’s gas sales are subject to regulation. Plaintiff’s industrial and field sales are not subject to regulation as to price.

38. The FPC also prescribes the accounting procedures to be followed by plaintiff to the extent it is subject to regulation. Eights-of-way acquisition costs are not included in the account for intangibles included in the FPC’s Uniform System of Accounts. Such costs are required to be kept in an account separate from the transmission lines, and are properly includable as a part of the “Transmission Plant.”

39 (a). Under the FPC regulatory practices, plaintiff determines its cost of revenue which is composed of its cost of doing business, i.e., cost of gas purchased, depreciation, salaries, expenses, taxes, etc., plus a rate of return on its investment. The cost of service and rate of return determine the charges that plaintiff may make to its gas customers on regelated sales. Under the FPC’s Uniform System of Accounts, plaintiff capitalizes all plant costs that have a continuing benefit for more than 1 year and recovers those costs through annual depreciation charges.

(b). On its books of account, plaintiff capitalizes its rights-of-way acquisition costs as a part of its overall transmission plant account (account number 365.2 of the Uniform Systems of Accounts). For FPC and financial reporting purposes, plaintiff and its subsidiary, Trunkline, have compiled depreciation on such costs at the rate of 3y2 percent per annum. Although the FPC’s Uniform System of Accounts does not specifically atithorize depreciation of transmission line rights-of-way acquisition costs, it may be reasonably assumed that for many years the FPC has been aware of plaintiff’s practice of depreciating such costs and at least tacitly approved such practice. On the basis of this record, it is found that for rate and accounting purposes the FPC considers transmission line rights-of-way a part of plaintiff’s transmission plant and that rights-of-way acquisition costs are properly depreciable.

(c). All of plaintiff’s depreciation charges are credited to a reserve for depreciation and become a part of its cost of service with the effect that on its regulated sales, plaintiff’s customers are paying these charges. These charges and payments thereof in turn reduce plaintiff’s rate base or net depreciated cost of its investments in its properties for future years to which the allowable rate of return is applied, thereby reducing plaintiff’s income.

(d). Plaintiff accords like treatment to its costs of surveying, clearing and grading its rights-of-way used in pipeline construction.

(e). For federal income tax purposes, plaintiff includes as taxable income, book depreciation charges (including those on its investments in main line rights-of-way), which have been included as part of its cost of service and repaid by its customers.

40. On the basis of unrebutted and credible expert testimony presented by Mr. Carman G. Blough, a well-known certified accountant, it is found as a statement of generally accepted commercial accounting principles and practices that in order to properly compute depreciation charges, two main factors must be known, i.e., the cost of the asset and the best available estimate of its useful life; that because of difficulties in estimating useful lives of most assets, depreciation computations do not lend themselves to precise determinations ; that if there is a reasonable expectation that an asset will have a limited life, depreciation is appropriate, and the best estimate possible should be made of the useful life based upon facts reasonably known to exist as of the end of the year; that if at a later date the estimate appears to be wrong, it can be changed; and that if the asset is going to be as valuable or more valuable than the original cost in perpetuity, only then is depreciation inappropriate. Ibid.

41. There are several accepted ways of depreciating assets. Among these are the straight-line method and the unit-of - production method. Under the straight-line method, an equal amount of depreciation is allocated ratably on a time basis over the estimated useful life of the asset. The unit-of-production method employs the best reasonable estimate possible, on the basis of current information available, of the total units the asset will produce or transport. These total units are divided into the cost of the asset, thus giving the portion of the cost that will be used up every time a unit is produced or transported. The depreciation charges will fluctuate from year to year, depending upon the number of units produced or transported and the current estimate of the total units to be produced or transported in the future. The unit-of-production method of depreciation is most often employed with respect to assets that are used in the exploitation of natural resources such as in the timber business, the mining, and the oil and gas industries. The method also has a built-in adjustment factor which automatically takes into account any changes in the estimate of the units to be produced or transported thereafter. An increase or decrease in the number of units to be produced or transported is accorded recognition in the annual depreciation computation. Because of this there will always be a part of the cost of the asset remaining to be depreciated so long as there continue to be units remaining to be produced or transported.

42. With respect to the transportation of natural gas, the information needed to employ the unit-of-production method for depreciation is (a) the undepreciated costs of the assets or facilities to be depreciated, (b) the number of units of gas available to the company at the end of each year under lease or contract to be transported, and (c) the number of units actually transported during the year. No assumption would be made with respect to the possibility of additional reserves being acquired at some future time. Subsequently acquired gas reserves would be taken into account only when actually obtained and necessary adjustments made in the next annual depreciation charge.

43. Natural gas is a wasting asset, and there is no evidence today that more gas is being created or made underground. No one knows how much gas is in place in the United States or how much gas will be recovered from wells in the United States. Similarly, nobody know with certainty how much gas will be moved through plaintiff’s transmission system before it is abandoned. The amount of gas which will be discovered and recovered in the United States depends in large part on the amount of money invested in exploration. There are many other factors which will affect the amount of economically recoverable reserves of gas in the United States in 1980. One factor is oil imports. For many years, the natural gas industry relied to a large extent on gas produced in conjunction with the production of oil. Oil imports tend to discourage oil production in the United States and with it the production of oil well gas. Other factors are technological developments, the price paid to producers of natural gas, the prices charged for competing fuels, the size of our population, and importation of natural gas. All of these factors are considered by engineers or economic experts in making their gas reserve estimates.

44. The American Gas Association (AGA) was organized by the gas industry, and its membership is made up of the distributing companies, the pipeline transmission companies, and, to some extent, producing companies. Since 1946, the AGA has been publishing estimated proved recoverable reserves of natural gas in the United States. These reserves represent estimates of natural gas producible from tested reservoirs under present technology, including gas in underground storage reservoirs and gas in those undrilled portions of proven fields where its producibility is considered assured by the known field geology. The AGA reserve figures are adjusted from year to year for new discoveries, for wells drilled to deeper depths in old pools, and for extensions and revisions. While the AGA has not published any information or standards on when discoveries should be included in reserve figures, they are included when the information and data are felt adequate and dependable. A new recovery technique is reflected in AGA reserve figures when it has been tried and a proper period for determining the value thereof has been established, but the AGA has no published standards on what is a sufficient period.

45. The AGA reserve figures are the only published figures on natural gas reserves. They are relied upon a great deal by many people in the natural gas industry. They are found in the libraries and offices of the FPC. They are used by state agencies and in testimony before state regulatory bodies, the FPC, the Tax Court, and various federal courts.

46. A statistical form in which estimated reserves are normally used in the industry is the “reserve life index.” This index is a computation which shows, as of the end of a given year, how long a company’s proven and controlled gas reserves will last, assuming the current reserves are used at a rate equal to current production. It is divided by dividing the MCF of gas reserves as of the end of the year by the MCF of gas produced during that year.

47. The AGA figures indicate that the total reserves for the United States, excluding Alaska, as of the end of the year have increased each year from 1945 through 1964. However, the supply of natural gas in relationship to demand has been on a downward trend over the period 1955-1964. Increases in reserves during this period were not enough to keep the industry’s reserve life index from steadily declining. Thus, although new discoveries have exceeded production, the significant point is that the ratio of reserves to production has not been maintained.

48. The following tabulation sets forth the annual reserve life indices for the United States and for the States of Texas, Oklahoma, and Kansas, based upon the published statistics referred to in finding 44, which reflect the shortening life of reserves available for marketing:

Keserve life index
United States Texas Oklahoma Kansas Year ended December 31
32.49 41.18 16.37 66.24 1946-
29.47 36.95 18.18 60.80 1947-
28.94 35.31 16.81 52.02 1948-
28.88 32.80 20.49 43.58 1949-
26.92 30.29 19.14 35.00 1950-
24.33 26.97 16.23 29.72 1951-
23.12 24.42 14.69 31.23 1952..
22.89 22.82 14.13 33.75 1953-
22.46 22.07 14.45 34.80 1954-
22.11 21.74 15.03 31.57 1955..
21.80 21.13 15.03 30.40 1956-
21.44 20.49 15.10 30.84 1957-
22.13 21.12 16.83 34.77 1958-
21.11 21.17 17.42 31.27 1959-
20.14 20.24 17.42 29.44 1960-
19.84 20.21 17.07 27.54 1961-
19.85 20.04 17.73 25.23 1962-
18.87 19.22 16.97 22.94 1963-
18.21 18.47 16.36 21.12 1964-

49. During the period 1946 to 1956, inclusive, there was a gradual upward, trend in the number of well completions for the United States as a whole, with 26,992 in 1946, and 57,111 in 1956. Since 1956, there has been a gradual dowmma/rd trend in the number of completions in the United States, as well as in the States of Texas, Oklahoma and Kansas, as evidenced by the following tabulation (which is based upon published statistics referred to in finding 44 and set forth in plaintiff’s exhibits 8-11, inclusive):

Number of well completions
December 31 of year United States Texas Oklahoma Kansas
1955. 1956. 1957. 1958. 1959. 1960. 1961. 1962. 1963. 1964. 55,922 57, 111 63,615 48,424 50,094 44,018 43,871 43,779 41,386 42,963 23,644 24,527 22,566 17,961 17,560 14,903 14,681 12,184 13,081 3,010 8,363 6,471 6,512 5,114 4,262 4,063 4,139 3,490 4,006 4.870 5,030 4,652 3,751 3,369 3,312 3,079 3,165 2.871 2,903

50. Plaintiff regularly estimated its natural gas reserves during the years in question. Plaintiff, like other members of the natural gas industry, uses such reserve estimates in the ordinary course of its business for purposes of capacity increase applications to the FPC, for security listings with the Securities and Exchange Commission, and to secure public financing. Of course, when one is dealing with natural resources, the quantity of which at a given point in time can only be estimated, changes in this quantity are to be expected by revisions of prior estimates and by new discoveries. This in no way negates the reserve life index as an acceptable guide. While a single year’s reserve life index may prove little, a 10-year span may have significance.

51. The estimation of proven recoverable natural gas reserves is not an exact science. However, with information dependable on new data, gas fields estimates can usually be made within about 10 percent accuracy. On recently discovered fields, the figures published by the AGA represent only the minimum reserves recoverable under present economic and operating conditions. After about 25 or 30 percent of the initial reserves have been produced, more accurate estimates can be made. It is a common practice in the natural gas industry to make upward or downward revisions in estimated gas reserves on the basis of subsequently acquired data and information. During the years 1952 through 1956, plaintiff made such upward or downward revisions in its estimated gas reserves. During these same years it was reasonable to assume that plaintiff in the future would acquire, as it did, additional reserves of gas.

52. It is physically possible to convert a natural gas pipeline to the transportation of oil or some other substance. The pumping facilities and other parts of the system would have to be changed. Whether it would be economical to convert a natural gas pipeline to the transportation of a substance other than natural gas would depend upon the costs of conversion, the availability of the raw material to the line, the size and availability of a market close to the line, the quantity of the product, and the size of the line to be converted. During the years in question it was not economically practical for the plaintiff to convert any of its lines to the carrying of other substances, and it was not a reasonably foreseeable possibility.

53. As previously indicated (finding 17(b)), plaintiff is limited under the terms of many of its right-of-way agreements to the transportation only of natural gas. In case plaintiff has to resort to condemnation in order to secure a right-of-way, the only right obtained is to lay one pipeline for the transportation of natural gas. No other product may be transported.

54. The following schedule sets forth the estimated recoverable reserves of natural gas owned or controlled by plaintiff under gas purchase contracts as of the end of each of the years 1951 through 1956, based upon the facts reasonably known to the plaintiff at such times. No reserves have been attributed to undeveloped acreage owned or controlled by plaintiff except to the extent deemed reasonably proven by plaintiff. Said schedule also sets forth the purchases and production of natural gas made by plaintiff from such reserves for each of the same years:

December 31 Reserves in MMCF Purchases and production in MMCF
1951-6,577,751 253,485
1952-1963-1954-6,451,089 8,048,970 7,356,705 247,395 241,388 247,924
1955-7,271,325 276,815
1956-7,250,200 295,167

All reserves, purchases and production are stated at a pressure base of 14.65 p.s.i.a. The above data does not include Trunkline reserves or plaintiff’s purchase from Trunkline.

55.The following schedule sets forth all of Trunkline’s reserves owned or controlled by gas purchase contracts for each year since it started transmission of gas and the volumes purchased by Trunkline thereunder:

December 31 1951-1952.. 1953-1954-1955-1956-Reserves 14.65 p.s.i.a. in MMCF 2,001,759 1,988,248 1,839,857 1,940,354 2,093,946 2,095,049 Purchases by Trunkline in MMCF 22,482 93,536 97,314 99,553 103,342 136,609

56.The following schedule sets forth the amount and approximate location of plaintiff’s undeveloped acreage controlled by leases at December 31 for the years 1951 through 1956:

Location Acreage 12/31/51 12/31/52 12/31/53 12/31/54 12/31/55 12/31/56
Hugoton Embayment* Texas. Oklahoma. Kansas. Colorado. 6,314 131,819 255,723 7,307 6,442 112,525 297,534 7,467 6,377 109,694 296,280 25,842 6,057 102,461 283,774 32,206 5r774 104,763 265,442 40,374 5,774 112,032 382,707 57,520
Total Hugoton Embayment. 401,163 423,968 438,193 424,4 416,353 558,033
Other areas:
Nebraska.. 11,259 11,419 11,419 11,419 10,899 10,1
Indiana... 177
Michigan.. Total other areas. 40,211 51,647 83,468 109,446 106,697 100,380 94,887 120,865 118,116 111,279 97,371 108,230
Total. 452,810 518,855 559,058 542,614 527,632 666,263

57.The following schedule sets forth the amount and approximate location of Trunkline’s undeveloped acreage controlled by leases at December SI for the years 1951 through 1956:

Location Acreage
12/31/51 12/31/52 12/31/53 12/31/54 12/31/55 12/31/56
Gulf Coast area: Texas_ Louisiana_ 667 667 281 1,729 1,729 1,503 1,061

58.Competitors of plaintiff for the purchase of available gas supplies in the Hugoton Embayment include El Paso Natural Gas Co., Cities Service Gas Co., Natural Gas Pipeline Co. of America, Colorado Interstate Gas Co., Northern Natural Gas Co., Permian Basin Pipeline Co., Kansas-Nebraska Natural Gas Co., Michigan-Wisconsin Pipeline Co. and Transwestem Pipeline Company. Competitors of Trunkline for the purchase of gas supplies in the Gulf Coast area include Texas Eastern Transmission Corp., Transcontinental Gas Pipe Line Corp., Tennessee Gas Transmission Co., United Gas Pipe Line Co., Texas Gas Transmission Corp., and American Louisiana Pipe Line Co.

59. In its federal income tax returns for each of the years 1931 (plaintiff’s first year of operation) through. 1956, plaintiff included as a part of its depreciation (or emergency amortization) base, for the purpose of computing deductions for the allowance of depreciation (or emergency amortization) , amount’s representing the costs of other tax basis for the acquisition of rights-of-way with respect to plaintiff’s transmission systems or lines. The Commissioner of Internal Revenue excluded said amounts from plaintiff’s depreciation (and emergency amortization) base and disallowed the deductions for depreciation (and emergency amortization) thereon for all years, beginning with the year 1942. The cost or other tax basis and the reserve for depreciation of plaintiff’s investment in rights-of-way (exclusive of gathering lines rights-of-wáy) at the close of each year are as follows:

December 31 of year Rights-of-way tax' basis Reserve for depreciation
19Í2 1943 1944 1945 1946 1947 1948 1949 1950 1951 1952 1953 1954 1955 1956 $747,220.67 1,250,185.22 1,267,481.07 1,278,502.68 1,298,134.96 1,335,311.16 1,377,146.12 1,503,885.92 1,524,658.89 1,914,490.11 2,028,012.00 2,031,530.00 2,253,553.00 2,365,698.00 2,365,744.00 $177,250 286,082 286,082 286,082 286,029 285,475 283,431 283,439 266,221 258,467 254,497 254,497 254,526 255,025 256,377

Such costs were capitalized on the books of plaintiff and also for federal income tax purposes.

60. The following tabulation reflects the cost or other tax basis as of December 31 of each year of plaintiff’s investment in transmission system rights-of-way covered by necessity certificates issued to plaintiff under sections 124A of the ,1939 Internal [Revenue Code and 168 of the 1954 Code, all of which are included in the preceding tabulation;

As of December- SI of each year Amount
1951__$21, 900
1952 ___181,198
1953 -T_;_i_141,857
1954 _L_ 142, 790
1955 _ 198,550
1956 -:_ 207,932

Pursuant to the aforementioned sections of the Internal Revenue Codes, and regulations promulgated thereunder, plaintiff made timely elections to amortize the basis of the facilities, including rights-of-way, referred to in said certificates over a period of 60 months. Plaintiff did not at any time elect to terminate said elections.

61. Under the 1939 Code, the necessity certificates issued to plaintiff under section 124A provided with respect to plaintiff’s transmission system rights-of-way as follows:

The rights-of-way described in the attached Appendix A, are certified only to the extent that the Bureau of Internal Revenue determines that they are depreciable in accordance with Section 29.23(1) -3 of the Internal Revenue Code.

With respect to the certificates issued under section 168 of the 1954 Code, the applicable provision reads:

The rights-of-way described in the attached Appendix A are certified only to the extent that they may be determined to be depreciable under Section 167. of the Internal Revenue Code of 1954, and applicable regulations.

62. For tax purposes, plaintiff’s investment made prior to January 1, 1954 in its transmission systems was depreciated at a net straight-line rate (after salvage) of 3.5017 percent; the investment made after January 1, 1954, was depreciated at 200 percent of tbe straigbt-line rate of 3.61 percent under section 167 (b) (2) of tbe 1954 Code. In tbe case of Trunkline, tbe investment made prior to January 1, 1954, in its transmission systems was depreciated at a Sy2 percent straigbt-line rate and at 200 percent of sucb straigbt-line rate for tbe investment made after January 1, 1954. The investment in transmission systems covered by necessity certificates were amortized under section 168 of the 1954 Code over 60 months commencing with tbe beginning of the succeeding taxable year in which tbe investment was placed in service.

63. Prior to tbe year 1942, for federal income tax purposes, plaintiff was allowed depreciation on its transmission system rights-of-way. In a prior proceeding between plaintiff and defendant it was agreed, as a part of tbe settlement thereof, that no depreciation would be allowed or allowable to plaintiff with respect to its transmission system rights-of-way for tbe calendar years 1946 to 1949, inclusive.

64. For federal income tax purposes, plaintiff has capitalized tbe costs of acquiring rights-of-way for its gathering systems. Such systems are composed of four items of property : rights-of-way; field lines which are the lines from the producing wells to the transmission system; the field line housing structures; and the equipment included therein. As of December 31,1956, plaintiff’s investment in gathering system rights-of-way, exclusive of its investment in such rights-of-way covered by necessity certificates, exceeded $300,000. As of the same time, the investment in rights-of-way covered by necessity certificates exceeded $15,000.

65. For the years 1942 through 1956, plaintiff’s investment in its gathering system rights-of-way were depreciated for federal income tax purposes with the knowledge of the Internal Revenue Service as follows:

(a) Under the 1939 Code, the investment in gathering system rights-of-way acquired prior to January 1, 1954, was depreciated as an integral part of the other gathering system items of property. For the years 1942 to 1956, inclusive, a net composite rate of 3.8 percent was allowed.
(b) As to the investment in gathering system rights-of-way covered by necessity certificates under section 124A of the 1939 Code, it was amortized over a 60-month period.
(c) The investment in gathering system rights-of-way acquired after January 1,1954, was depreciated under section 167(b) of the 1954 Code on the declining balance method at 200 percent of the straight-line rate as an integral part of the tangible physical property in the gathering systems.
(d) The investment in gathering system rights-of-way covered by necessity certificates under section 168 of the 1954 Code was amortized over a 60-month period.

All of said depreciation deductions were allowed by the Internal Revenue Service and are not challenged in this proceeding, except the deductions referred to in subparagraph (c) of this finding.

Ultimate Finding and Conclusions

66. Plaintiff’s rights under right-of-way agreements in and of themselves constitute intangible assets, and they are not subject to wear and tear or physical exhaustion; however, the only reason plaintiff obtains these agreements is to construct its pipelines. By such agreements, plaintiff did not acquire any interest in the lands over which rights-of-way were granted other than to construct, operate, maintain, repair, replace and supplement its pipelines. On the basis of the credible testimony and other evidence in the record considered as a whole, it is concluded and found that as a practical matter such agreements-rights, i.e., intangible assets, have no value separate and distinct from, or independent of, the pipelines which have been, or may be, laid in rights-of-way granted. A right-of-way agreement without accompanying pipeline construction to serve is valueless (except in the unusual situation outlined in finding 18). Plaintiff’s right-of-way costs are directly associated with the individual pipelines to which they actually relate and have no value apart from such lines. Such costs as to each line do not contribute to the production of income independently of their association with the line. The useful lives of such rights-of-way are coterminous with, the pipelines for which they were acquired. Since the rights-of-way are intangible assets, plaintiff is entitled for the years in suit to compute its depreciation on its investment in the transmission line rights-of-way by the straight line method. For the years in suit, plaintiff is entitled to amortize its investment in transmission system rights-of-way covered by certificates of necessity on the basis and for the period of time described in finding 60.

Deletion Issue — Hugoton Embayment.

67 (a). During the years 1952 through 1956, plaintiff owned as lessee an economic interest in oil and/or gas leases on lands located in the Hugoton Embayment of the Anadarko Basin in the States of Texas, Kansas, and Oklahoma. The Plugoton Embayment of the Anadarko Basin is the shallow portion of the old Anadarko Sea. It covers areas of northwest Texas, western Oklahoma, eastern Colorado, and western Kansas. The following tabulations set forth the approximate number of wells, as reflected on the depletion schedules of plaintiff’s tax returns, capable of production of natural gas on plaintiff’s leases in the Hugoton Embayment in said states during each of the years here in issue, together with the approximate acreage covered by said leases:

Texas Kansas Oklahoma
Year
Wells Acreage Wells Acreage Wells Acreage
1952_. 1953_. 1954.. 43,721 43,781 43,780 236 244 256 142,396 148,772 155,891 96 107 124 58,566 65,759 72,549
1955-, 1956.. 44,283 44,443 300 336 182,388 201,664 137 151 76,694 78,288

(b). The following schedule sets forth the estimated recoverable reserves of natural gas stated in MMCF underlying the foregoing acreage located in the Hugoton Em-bayment in the States of Texas, Kansas, and Oklahoma, on a pressure base of 14.65 p.si.a., as of the end of each of the years 1951 through 1956:

December 31 Texas Kansas Oklahoma Total
1951. 1952. 1953. 1954. 1955. 1956. 624,412 582,900 590,665 632,705 611,086 586,428 1,169,511 1,160,140 1,184,030 1,238,603 1,489,919 1,565,580 210,594 299,964 330,329 282,944 265,773 437,568 2,004,517 2,043,004 2,105,024 2,154,252 2,366,778 2,589,576

68. The following tabulation sets forth for the years 1952 through 1956, the volumes of plaintiff’s natural gas stated in MCF produced from wells in which plaintiff had an economic interest located in the Hugoton Embayment in the States of Texas, Kansas, and Oklahoma, on a pressure base of 14.65 p.s.ia.:

Year Texas Kansas Oklahoma
1952. 1953. 1954. 1955. 1956. 41,593,198 37,014,102 30,069,788 29,933,210 24,617,337 28,864,062 22,722,102 32,003,414 45,285,409 40,260,278 10,180,951 11,602,577 18,259,396 16,223,482 42,751,946

69. Under date of May 25, 1943, plaintiff and Phillips Petroleum Corporation, a Delaware corporation (hereinafter referred to as “Phillips”), entered into a contract under which Phillips agreed to process natural gas produced and purchased by plaintiff in the Texas portion of the Hugoton Embayment. Pursuant to said contract, Phillips constructed near plaintiff’s compressor station at the Sneed Kanch, Texas, a processing plant. During the years 1952 through 1956, Phillips processed raw natural gas produced and purchased by plaintiff and extracted therefrom raw natural gasoline. All such natural gasoline was purchased by Phillips, and such company accounted to plaintiff for 58.8 percent of the value thereof. In the following tabulation there are set forth for each of the years 1952 through 1956, the volumes of plaintiff’s gas (produced and purchased) processed by Phillips at its Sneed plant, the total revenues received by plaintiff and the .gross income per MCF stated on a pressure basis of 14.65 p.s.i.a. attributable to plaintiff’s share of raw natural gasoline extracted therefrom:

Year MCF processed at Phillips plant Revenues received by plaintiff Gross income per MCF
1952. 1953. 1954. 1955. 1956. 50,740,975 49,692,749 46,215,270 48,912,349 44,767,484 $807,634 762,319 698,114 767,964 698,828 $0.0159 .0153 .0129 .0157 .0134

70. At all times during the years 1052 through 1956, plaintiff owned and operated a plant at Liberal, Kansas, for the processing of raw natural gas by the use of absorption and fractionation facilities. Plaintiff extracted natural gasoline, propanes and butanes from the raw natural gas processed in said plant. During the years 1952 through 1956, plaintiff processed the 'following volumes of raw natural gas, stated in MCF on a pressure base of 14.65 p.s.i.a., produced and purchased by plaintiff, and received from the sale of the natural gasoline, propanes and butanes the following gross revenues:

Year MCF volumes processed Gross revenues Value per MCF
1952. 1953. 1954. 1955. 1956. 61,152,777 56,201,100 72,912,292 83,795,640 81,421,128 $1,418,227 1,167,806 1,046,863 1,435,822 1,793,278 $0.0232 .0208 .0144 .0171 .0220

71. During the years here in issue, plaintiff under its oil and gas leases had varying obligations to account to its lessors for royalties on natural gas produced from plaintiff’s wells. In general, such royalty provisions fell into three broad categories: market value, market price, and proceeds. The following provisions are typical of each of the foregoing categories of royalty provisions:

Market Value:

The lessee shall monthly pay lessor as royalty on gas marketed from each well where gas only is found, one-eighth (%) of the proceeds if sold at the well, or if marketed by lessee off the leased premises, then one-eighth (y8) of its market value at the well. The lessee shall pay the lessor: (a) one-eighth (%), of the proceeds received by the lessee from the sale of casinghead gas, produced from any oil well; (b) one-eighth (%) of the value, at the mouth of the well, computed at the prevailing market price, of the casinghead gas, produced from any oil well and used by lessee off the leased premises for any purpose or used on the leased premises by the lessee for purposes other than the development and operation thereof. Lessor shall have the privilege at his own risk and expense of using gas from any gas well on said land for stoves and inside lights in the principal dwelling located on the leased premises by making his own connections thereto.

Market Price:

To pay the lessor the equal of one-eighth part at market price for the gas from each well where gas only is found, while the same is being used off the premises, and lessor to have gas free of cost from any such well for all stoves and all inside lights in the principal dwelling house on said land during the same time by making his own connections with the wells at his own risk and expense.

Proceeds:

The lessee shall pay lessor, as royalty, one-eighth of the proceeds from the sale of the gas, as such, for gas from wells where gas only is found, and where not sold shall pay Fifty ($50.00) Dollars per annum as royalty from each such well, and while such royalty is so paid such well shall be held to be a producing well under paragraph numbered two hereof. The lessor to have gas free of charge from any gas well on the leased premises for stoves and inside lights in the principal dwelling house on said land by making his own connections with the well, the use of said gas to be at the lessor’s sole risk and expense. The lessee shall pay to lessor for gas produced from any oil well and used by the lessee for the manufacture of gasoline or any other product, as royalty, one-eighth of the market value of such gas. If said gas is sold by the lessee, then as royalty one-eighth of the proceeds of the sale thereof.

72.For the years 1952 through 1956, plaintiff paid royalties to its lessors in the State of Texas at the following approximate rates per MCF on a pressure base of 14.65 p.s.i.a.:

Years Royalty rate
1/1/52- 6/30/52_ 6.2530
7/1/52-12/31/53___ 7.1463 0
1/1/54-12/31/55_ 9^
1/1/56-12/31/56_ 100

73.For the years 1952 through 1956, plaintiff paid royalties to its lessors in the State of Kansas at varying rates. The following tabulation sets forth the various fields in the State of Kansas from which plaintiff produced natural gas, and the approximate rates per MCF on a pressure base of 14.65 p.s.i.a. ait which plaintiff paid royalties to its lessors:

Field Rate
Hugoton Field
1/1/52- 6/30/53_ 8.03960
7/1/53-12/31/53_ 90
1/1/54-12/31/56_ 110
Hugoton Field-Quinque Wells
1/1/52-12/31/56_ 11. 7986580
Hugoton Field-Boles Wells
1/1/52-12/31/53_ 7.1463420
1/1/54- 2/28/54_ 110
3/1/54-12/31/56_ 11.80
Wide Awake Field
11/9/50-12/31/56_ 11.80
Shuck Field
4/25/55-12/31/56_ 130
Greenwood Field
7/20/55-12/31/56_ 120
Taloga Field
11/15/55-12/31/56_ 130
Elkhart Field
7/1/55-12/31/56_ 130
Pleasant Valley Field
10/11/54-12/31/56_ 120
Interstate Field
8/23/56-12/31/56_ 130
Richfield Field-Going Wells
9/6/56-12/31/56_ 13. 91422360

74.For the years 1952 through 1956, plaintiff paid royalties to its lessors in the State of Oklahoma at varying rates. The following tabulation sets forth the various fields in the State of Oklahoma from which plaintiff produced natural gas, and the approximate rates per MCF on a pressure base of 14.65 p.s.i.a. at which plaintiff paid royalties to its lessors:

Field Rate
Iiugoton Field
1/1/52- 7/31/52_ 80
8/1/52-12/31/56_ 9. 82620
Light Field
Zielke #1-28 Well
11/9/54-11/8/56_ 11. 3894820
11/9/56-12/31/56_ 12. 2827750
All other wells
5/18/54-12/31/56_ 11. 3890
Keyes Field
Ferguson #1-2
2/ /55 — 12/31/56_ 11.940
Goddard #1-19
10/ /55 — 12/31/56_12.1050
North Richland Center
2/13/56-12/31/56_130
North Hardesty Field
7/16/56-12/31/56_130
Camriek Field
3/21/56-12/31/56_ 14. 50 to 6/1/59 or
130 to 12/31/58 plus 160 from 1/1/59 to 6/1/59

75. The royalty rates set forth in findings 72, 73, and 74 accord recognition to any retroactive royalty payments made in subsequent years.

76. During the years 1952 through 1956, plaintiff made sales of natural gas at retail and at wholesale for resale. In addition, plaintiff made certain miscellaneous field sales. Its retail sales were for residential, commercial and industrial use. Its wholesale sales were to gas utility companies for resale. With the exception of a few wellhead sales, classified as a part of field sales, all sales of natural gas were made after the gas had been transported away from the individual wellheads.

77. The following tabulation sets forth for the calendar years 1952 'through 1956, the total dollar sales of produced and purchased natural gas by plaintiff by classification, the total volumes stated in MMCF on a pressure base of 14.66 p.s.i.a., and the average price per MCF:

1956 1955 fS6T 1953 1952 Classification
Retail sales:
$54,010 16,824 12,694,287 150,898 $73,783 8,516 11,119,884 98,601 $81,173 5,416 9,516,910 311,861 $68,681 3,892 6,288,196 1,041,262 $61,714 4,416 5,355,358 1,854,726 Residential.. Commercial. Industrial_ Field..
$12,816,019 S $11,300,784 $9,915,360 $7,402,031 $7,276,214 Total retail..
Wholesale sales:
94,182,365 ' 2,478,947 ' 83,070,210 1,963,146 73,501,692 1,884,025 83,486,343 2,105,275 79,601,606 2,621,540 Sales to other gas utilities: Regulated. Nonregulated.
$96,661,312 ; $85,033,356 $75,385,717 $85,690,618 $82,223,146 Total wholesale.
$109,477,331 $96,334,140 $85,301,077 $92,992, 649 $89,499,360 Total sales..
396,371 348,297 315,087 311,272 317,909 Total sales in MMCF at 14.65 p.s.i.a..
27.69(5 27.66$ 27.07$ 29.83$ 28.15$ Average sales price per M.C.F-.

78.Of the sales set forth in finding 77, the following tabulation reflects for each of the years 1952 through 1956, the volumes of produced gas sold by plaintiff at the wellhead at a pressure base of 14.65 p.s.i.a., the amount received therefor, and the average price per MCF:

Year Volumes MCF Amount Average per MCF
Oklahoma. 1952 53,324 $4,764 8.93
1953 1954 61,636 39,773 6,046 4,199 9.81 10.56
Kansas. 1955 1956 1952 170,110 166,920 40,852 19,020 18,994 3,989 11.18 11.38 9.76
1953 1954 1955 1956 39,648 23,141 27,334 92,573 3,896 2,709 3,009 10,185 9.83 11.71 11.01 11.00

79.During the years 1952 through 1956, plaintiff purchased in the Hugoton Embayment in the States of Texas, OMahoma, and Kansas, and from Trunkline Gas Company in Illinois, the following volumes of natural gas stated in MCF at a pressure base of 14.65 p.s.ia.:

Year Hugoton Embayment From Trunkline Total gas purchased
1952. 1953. 1954. 1955. 1956. 164,130,198 169,019,325 167,262,709 184,782,409 186,003,496 91,867,179 95,480,037 96,615,084 99,884,920 128,716,015 256,997,377 264,499,362 263,877,793 284,667,329 314,719,611

80.During the years 1952 through 1956, plaintiff used away from the various leases and consumed in its operations the following volumes of its natural gas (produced or purchased) stated in MCF at a pressure base of 14.65 p.s.i.a.:

Year MOJ?
1952 _20, 545, 201
1953 _ 22,156, 706
1954 _ 24,498, 502
1955 _ 22, 718, 694
1956 _ 22,804,110

81.Any variation between purchases and production of natural gas by plaintiff during the years 1952 through 1956, and its dispositions as set forth in these findings, are probably due to variations in temperature where the gas was metered and normal unaccounted-for shortages.

82. In its tax returns for the years 1952 through 1956, plaintiff claimed deductions from gross income for percentage depletion with respect to natural gas, oil, and condensate produced from wells in which it had an economic interest, pursuant to the provisions of sections 28 (m) and 114 of the 1939 Code for the years 1952 and 1953, and sections 611 and 613 of the 1954 Code for the years 1954,1955, and 1956. Upon final audit of said returns, the Commissioner of Internal Eevenue determined that the gross income from such wells upon the basis of which plaintiff was entitled to deductions for percentage depletion was as follows:

Year Gross income
1952 _j_$6, 536, 738
1953 _ 6,240,109
1954 _ 8,374,667
1955 _ 9,725,843
1956 _ 13,304, 643

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

Deduction
Year allowed
1952_ $1,493,913
1953_ 1, 410, 223
1954_ 1, 965, 993
1955_ 2,141,745
1956_ 3,043,488

In making said determinations, the Commissioner used as the representative market or field price of plaintiff’s produced natural gas per MCF, an amount which was the equivalent of the rate at which plaintiff paid royalties to its lessors as set forth in findings 72, 73 and 74. The allowance of the deductions for percentage depletion with respect to oil and condensate is not an issue in this proceeding.

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

84. In the 1930’s, the supply of natural gas in the Hugoton Embayment greatly exceeded the demand, and there was a market only for a very small percent of the reserves. In 1935, the pipeline companies took approximately 18 percent of the natural gas produced in the Texas portion of the Hugoton Embayment, and more than 50 percent was vented into the air. This excess of supply over demand depressed the prices paid for natural gas to very low levels. Some prices paid by plaintiff in the Hugoton Embayment ranged from 2per MCF .to a high of 40, all on a 16.4 p.si.a. pressure base. Most contracts entered into during this period provided for a flat price for the life of commercial production. In general, the purchaser got the liquefiable hydrocarbons hi the raw gas. A BTU (British thermal unit) value of 1,000 was the minimum acceptable heat value of the gas. Many low-price contracts executed during this period are still in effect.

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

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

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

88. During the years 1952 through 1956, the following factors influenced the price that a seller of natural gas could command for his product in the Hugoton Embayment:

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

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

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

(d) Delivery point.

(e) Heating value of the gas.

(f) Deliverability of the wells; the larger the volume that could be delivered from a reserve, the greater the price the seller could command.

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

89. At all times during the years 1952 through 1956, there existed a market for natural gas in the Hugoton Embayment, in the sense that there were both buyers and sellers dealing at arm’s length who bought and sold gas. There was a great deal of competition. In general, the sellers were seeking the best price they could get for their gas, while the buyers sought to buy at the lowest possible prices.

90. Adjacent to the Anadarko Basin, but as separate and distinct geological systems, are the Palo Duro Basin to the south and the Dalharit Basin to the west. All of plaintiff’s production of natural gas (other than from the Howell Field of Michigan) was from the Hugoton Embayment of the Anadarko Basin.

91. From a geological standpoint, oil and gas in the Hugo-ton Embayment is found in structures or traps in rock formations of varying geological ages. These rock formations are divided into several classifications of rocks called systems. The youngest system in point of time and generally the shallowest in depth are the rocks of Permian age. The Permian system in turn is divided into series which in turn are divided into groups, the more important of which are the Clear Fork, the Wichita, the Chase, and the Council Grove. Each group in turn has various named producing formations. The rock formations below the Permian are referred to as systems of pre-Permian age. The two most important systems in the Hugoton Embayment below the Permian are the Pennsylvanian and the Mississippian. These are also divided into various series and groups which in turn have producing formations therein. In all, there are between 25 and 30 identifiable formations in the Hugoton Embayment known to be productive of oil and gas. Production of oil and gas from the same formation occurs at varying depths. The top of the Pennsylvanian formation ranges from 3,000 to 3,600 feet below sea level, while the top of Mississippian formation ranges from 5,000 to 9,500 feet below sea level. Quite a wide range of variations are also found in the depths of the producing zones. The presence of productive oil and gas formations in the Hugoton Embayment is without regard to the boundaries of states, counties, or other political subdivsions.

92. By reason of the two decisions rendered by this court in the case of Hugoton Production Co. v. United States, plaintiff requested its manager of proration and reservoir engineering, Clifford K. Horn, a petroleum engineer, to study the areas in the Hugoton Embayment in which plaintiff had production of natural gas in the years 1952 through 1956, with a view of determining a reasonable area from which to compute weighted-average prices. After examining plaintiff’s producing acreage, Mr. Horn determined that a radius of 30 or 40 miles from plaintiff’s acreage would provide an area within which the gas would be comparable to plaintiff’s, and variations in the composition, quality and other factors relating to gas .would tend to even themselves out. Such radii crossed the state lines of Kansas, Oklahoma, and Texas, as well as many county borders. During the years 1952 through 1956, plaintiff’s production was from wells in Grant, Morton, Stevens, and Seward Counties in Kansas; Cimarron, Texas, and Beaver Counties in Oklahoma; and Hutchinson, Carson, Moore, and Potter Counties in Texas.

93. The area so determined by Mr. Horn included the Counties of Hamilton, Kearny, Finney, Stanton, Grant, Haskell, Morton, Stevens, Seward, and Meade in the State of Kansas; the Counties of Cimarron, Texas, and Beaver in the State of Oklahoma; and Baca County in the State of Colorado. For the years 1952 through 1956, the area in the State of Texas included Sherman, Hansford, Hartley, Moore, Hutchinson, [Roberts, Oldham, Potter, Carson, and Gray Counties. By reason of additional development of plaintiff’s acreage for 1954 on, there was included in the area Dallam County, Texas, and from 1955 on Ochiltree County, Texas. It was found impractical to divide counties and if the arc of the radius covered a substantial part of a county, the entire county was included in the area. The area so selected (hereinafter sometimes referred to as “plaintiff’s area”) extended from north to south about 200 miles and from east to west about 160 to 170 miles. The 12 Texas counties included in plaintiff’s area for 1955 and 1956, form a rectangle. Plaintiff’s southernmost production was about 18 miles north of the southern border of said area and about 182 miles south of the northern border thereof. Plaintiff’s production in Oklahoma and Kansas was centrally located in relation to the eastern and western borders of plaintiff’s area. Plaintiff’s northernmost production was about 42 miles south of the northern border of said area and about 158 miles north of tbe soutliern border thereof. With respect to Oklahoma and Kansas, plaintiff’s production was not centrally located to the north and south; nor were the sales included in the sample for Texas centrally located.

94. Not only with respect to plaintiff’s production acreage, but also to all production within the area determined by Mr. Horn, wide variations existed in producing conditions, quality of the gas, and the other factors affecting the value of gas. The depth of the reservoirs varies from approximately 2,500 feet to 8,50o feet. Pressures vary from a low of 250 to 300 pounds to a high of 2,000 pounds. The heating value of the gas ranges from 700 BTU to nearly 1,200 BTU per cubic foot. There were also wide variations in the sizes of the producing acreages. In all, there are several hundred separate fields or gas reservoirs in the area.

95. Under normal conditions the pressure at which natural gas is found will increase with the depth of the formation below the surface. The rate of increase is about 430 pounds per thousand feet of depth. However, in the area selected by plaintiff the pressures are from 800 to 825 pounds subnormal, though pressures do increase with depth. During the last 10 years, over 10,000 wells have been drilled in this area to formations below the Permian systems. No 'big producing fields of gas have been discovered below the Permian system and it is doubtful at present if any large fields of high pressure gas will be discovered in the area. The pipelines and gathering systems existing in plaintiff’s area were designed to handle low pressures. Since it is uneconomic to construct high pressure lines to handle the comparatively small volumes of high pressure gas produced in the area, the high pressure gas has to be decompressed to lower pressures in order to be introduced into the low pressure lines. This makes that type of gas more expensive to handle. The pressure of the gas in the formation does not determine the volume that can be produced.

A high pressure well may become exhausted within a short period of time because it does not have a large reservoir of gas behind it. On the other hand, high pressure wells are valuable to pipeline companies, especially if they are good producers. All factors (including the volume of gas availaMe, the permeability and thickness of the rock formation, and the size of the pipe through the rock) being equal — the higher the pressure — the greater the production. In various prospeoti filed with the Securities and Exchange Commission, plaintiff stated that the higher pressures encountered in the deeper producing formations and the large deliverability of many of its wells will increase the availability of gas to plaintiff and supplement declining deliverabilities in the Panhandle and Hugoton Fields.

96. During the years 1952 through 1956, plaintiff’s natural gas from its producing acreage was comparable gas to that produced through plaintiff’s area in that (a) plaintiff’s acreage was in convenient blocks from the standpoint of gathering costs and delivery and was well above average for the area; (b) the volumes of gas available to plaintiff were much above average; (c) the heating value of plaintiff’s gas ranged from a low of 800 BTU to a high of 1,190 BTU (the average heating value of its gas was above that for the area); (d) all of plaintiff’s gas was sweet gas, that is, not containing hydrogen sulphide in excess of 1 grain per 100 cubic feet of gas (some very small accumulations of sour gas occur in the Kansas portion of the area though most of the sour gas is found in the northern part of the Texas Panhandle Field); (e) the pressures of plaintiff’s gas ranged about the same as that from other wells in the area; and (f) the deliver-ability of plaintiff’s wells was better than average.

97. Each of the States of Kansas, Oklahoma, and Texas have enacted proration laws designed to allocate the market demand from a gas field among the individual wells in the field, in order that each lease will have the opportunity of producing its fair share and ultimately to produce the gas reserves underlying the lease. The State Commissions administering these laws set an allowable for each well, which is the volume of gas that well is permitted to produce in a specific time, usually 1 month. Variations in production of these al-lowables are permitted provided they balance out over a period of time. There is no practical difference between the proration laws of the three above-mentioned states. The market requirements for a gas field crossing a state line are not always the same in each state and the allowables set by the states may therefore vary. The State of Colorado had no pro-ration laws during the 1952-1956 period. During these years, most of plaintiff’s production of gas was subject to the pro-ration laws as was most of the production throughout plaintiff’s area. Nonprorated fields were subject to a limitation not to produce in excess of 24 percent of open-flow potential.

98. By reason of variations in allowables and its own market requirements, plaintiff’s production of natural gas from its wells in the States of Texas, Kansas, and Oklahoma varies from year to year. In plaintiff’s area there are also wide variations in the production of natural gas from the individual leases and wells ranging from 30 to 50 percent from year to year.

99. Natural gas as it is produced is called raw gas. This raw gas contains liquefiable hydrocarbons and the heavier hydrocarbons include propane, butane, pentane, and hexane. These can be extracted in gasoline plants away from the wellheads and when extracted have a value of their own. The remaining natural gas is called residue gas. When these lique-fiable hydrocarbons are present in sufficient quantity, the sellers of natural gas will extract them in gasoline plants and sell residue gas. Today, because of the separate value of these liquefiable hydrocarbons, it is almost impossible in plaintiff’s area to purchase substantial quantities of raw gas. Even smaller producers make reservations in their contracts permitting them to join with other producers and jointly process their gas.

100. Plaintiff has producing wells in the old Panhandle Field of Texas, which is located in Wheeler, Gray, Carson, Hutchinson, Moore, Potter, and Hartley Counties. Approximately 80 percent of the field is controlled by producers who do not sell at the wellhead. Phillips Petroleum Company controls- about 25 percent of the field; Colorado Interstate Gas Company 22 to 23 percent; 'Shamrock Oil and Gas Company about 11 percent; Natural Gas Pipeline Company about 10 percent; 'and Cities Service Gas Company about 8 percent. Plaintiff’s own production in the field is about a 4 percent participation.

101 (a). Natural gas is a true gas and as such is subject to the physical laws of all gases. If there is a connection, gas under a higher pressure will move toward the area of lower pressure. There are several common gas producing formations or reservoirs in plaintiff’s area that cross state lines. The prime example is the Hugoton Field which extends from Texas through the Oklahoma Panhandle into southwestern Kansas. Other examples of common reservoirs crossing state lines are the Greenwood Field in Kansas, which extends into Oklahoma where it is called the Carthage Field; the Boaldin Field which extends from Oklahoma into Kansas; the Liberal Southeast and Liberal Light Fields which extend from Oklahoma into Kansas; and the Camrick Field which extends from Oklahoma slightly into Texas.

(b). There are also several common gas producing formations or reservoirs which cross county lines and as a result are located partly within and partly without plaintiff’s area. Specifically, producing formations extend across the following portions of the perimeter of plaintiff’s area: the eastern border of Gray County, Texas (the East Panhandle Field); the eastern border of Roberts County, Texas; the southern, western, and northern borders of Ochiltree County, Texas, which are included in the perimeter of plaintiff’s selected area for 1952, 1953, and 1954; the southern and eastern borders of Beaver County, Oklahoma; and the eastern border of Meade County, Kansas. This is true because in the selection of plaintiff’s area, it was found impractical to divide counties. Defendant agreed that such division was impractical and in turn followed the county lines selected by plaintiff. It should be made clear that in its computations, plaintiff used only gas purchases in the counties within its selected area. There were no producing gas fields located partly within- and partly without plaintiff’s area from which plaintiff had production. This would not be true if the area should be segmented by state lines as proposed by defendant.

' 102. There is considerable evidence that because of pressure differences between producing wells in the same reservoir and differences in the time of development of the reservoir, some natural gas has been and is migrating in the reservoirs across state lines. A few pounds difference in pressure over a large area can. cause the migration of considerable volumes of natural gas, and a large difference in pressure over a small area can move large volumes of gas, depending on the permeability of the reservoir. Yariations in pressure exist throughout plaintiff’s area, but it should be made clear that mere differences in pressure do not indicate any migration; the differential must exist between wells producing from the same reservoir. In the middle to the late 1930’s, natural gas in the Hugoton Field was migrating from Oklahoma into Kansas. However, with the development of the Oklahoma side of the field and because of the greater rates of take there, natural gas through the 19á0’s and 1950’s has migrated from Kansas into Oklahoma. There is likewise considerable migration of natural gas from the Oklahoma portion of the Plugoton Field into Texas occasioned by the greater rates, of take in Texas. The differences in rates of take are the result of differences in allowables set by the various states stated under the proration laws as described in finding 97.

103. In the Greenwood (Kansas), Carthage (Oklahoma) Field, the earlier development of the Kansas portion of the common reservoir occasioned the migration of natural gas from Oklahoma into Kansas. In the Boaldin Field, the migration was from Kansas into Oklahoma. Also in the Liberal Southeast and the Liberal Light Fields, the migration was from Kansas into Oklahoma; while in the Oamrick Field there probably has been some migration from Texas into Oklahoma.

104. Once its area had been determined, plaintiff ascertained which interstate pipeline companies were competing therein in 1952 through 1956 for the purchase of gas. These companies were: Cities Service Gas Company, Colorado Interstate Gas Company, Kansas-Colorado Utilities, Inc., Kansas-Nebraska Natural Gas Company, Natural Gas Pipe Line Co. of America, Northern Natural Gas Company, and Panhandle Eastern Pipeline Company. Each of these companies was subject to the jurisdiction of the FPC, and each is required to file under oath an annual report with the FPC known as Form 2. There is included in the Form 2, among other information, a section which reflects, by contract, all gas purchases made by the reporting company.

105 (a). In computing weighted-average prices, plaintiff proceeded as follows: (a) the contracts used were those under which natural gas was purchased by the interstate pipeline companies operating in the area described in finding 93; (b) the volumes of natural gas purchased and the amounts paid for the gas were the same as reported in the gas purchase sections of the FPC Forms 2 for the year for which the average was computed; (c) all volumes of natural gas were converted to a uniform pressure base of 14.65 p.s.i.a.; (d) only contracts which were sales on the property (wellhead and separator) as stated in the gas purchase section of the FPC Forms 2 were used; and (e) purchases of natural gas from affiliated companies were not included.

The resulting weighted-average prices were a simple arithmetic average computed by dividing the total dollars paid for natural gas purchased by the corresponding total volumes purchased (in thousands of cubic feet) as shown in the gas purchase section of the Forms 2 for each of the years in issue.

(b). Plaintiff computed one weighted-average price for its selected area for each of the years in issue. The volumes used, the amounts paid, and the weighted-average prices, as computed by plaintiff, are as follows:

Year MCF (14.65 p.s.i.a.) Amount Average price per MOF
1952. 1953. 1954. 1955. 1956. 231,766,104 274,180,050 313,524,271 351,651,634 341,093,755 $17,509,501.46 22,614,926.25 33,657,882.37 38,518,335.65 38,302,806.54 7.55¿ 8.25 10.74 10.95 11.23

106 (a). The field names in the gas purchase section of the Forms 2 on file with the FPC are not completely reliable and more than one field is sometimes included in a single entry, such as, for example, “Hugoton Field and others.” There is no way of ascertaining the actual identity of the field, except to the extent this po'ssibly can be disclosed by reference to the sales contracts, which may or may not be practical and burdensome depending upon the number of such single entries open to question.

(b). In computing weighted-average prices, it is possible to go behind the information contained in the gas purchase sections of the Forms 2; however, it is not practical to do so in a 'comprehensive maimer because this would require examination Of all purchase contracts of the pipeline companies included in said sections in order to determine the propriety Of the inclusion or exclusion of the contracts in the computation. Such examination would not only be unduly tune-consuming and burdensome, but it is unnecessary, provided the sample of contracts used in mailing the computation is sufficiently large and diverse enough to discount variations and errors, since it may be reasonably concluded, 'and stated as a general rule, that errors in the gas purchase sections of the Forms 2 are offset, or at least minimized, by the use of a big enough sample. The smaller the sample of contracts used, the more such errors are magnified. Despite the foregoing, it is found that obvious errors in the information shown in said purchase sections, as may be established by reference to the contracts involved, should be corrected. To disregard such errors and fail to reflect them in the computation of the weighted-average prices involved here is unjustified and improper under the circumstances existing in this case.

107. During the years in question, plaintiff purchased gas at the wellhead in the Texas portion of its selected area (see findings 92 and 93) under a number of different contracts. The purchases made by plaintiff under two of these contracts (one of which was executed in 1950 and the other in 1951) were correctly shown as wellhead sales in the gas purchase sections of plaintiff’s Forms 2 for the years 1954 through 1956, but were erroneously listed as non-wellhead sales on its said forms for 1952 and 1953. The delivery points in the contracts themselves are specified as being at the wellhead. In computing the weighted-average prices listed in the table set forth in finding 105 (b), sufra, plaintiff took the purchases under these two contracts in question into account in computing the prices listed for 1954 through 1956, but knowingly and improperly disregarded them in computing the stated prices for 1952 and 1953. Naturally this affected tiie weighted-average prices shown in plaintiff’s computations for the two last-mentioned years. When these purchases are taken into account, the weighted-average price per MCF under plaintiff’s method is 7.53$ (as opposed to 7.55$) for 1952, and 8.23$ ('as opposed to 8.25$) for 1953.

108. Under date of December 9, 1946, but effective as of January 1, 1947, the Corporation Commission of Oklahoma entered two orders setting a minimum price of 7$ per MCF at the wellhead on a 14.65 pound pressure base for all gas produced from the Guymon-Hugoton Field in Texas County, Oklahoma. The cause for such orders was a dispute between the Peerless Oil & Gas Company and Cities Service Gas Company over the latter’s refusal to purchase gas from the former except on certain specified conditions. The Commission stated the basis for such orders as being:

For the purpose of preventing waste, economic and physical, of natural gas, for the purpose of protecting correlative rights, and to insure the greatest ultimate recovery of natural gas from the common reservoir involved * * *.

The validity of these orders was upheld in 1950 by the Oklahoma Supreme Court, and affirmed by the United States Supreme Court. It is undisputed that in approving these orders, the United States Supreme Court did not pass on the question of whether the orders conflicted with the Natural Gas Act, supra.

109. Subsequent to the foregoing decisions, the Corporation Commission of Oklahoma, under date of July 29,1952, set a minimum price for all gas produced from the Guymon-Hugoton Field, whether sold on the lease or off, or as residue gas, at 9.82620 per MCF on a 14.65 pressure base. On April 11, 1955, the United States Supreme Court held that the State of Oklahoma had no power to set minimum prices for gas transported for resale in interstate commerce since such sales were subject to the exclusive jurisdiction of the FPC.

110. On February 18, 1949, the State Corporation Commission of the State of Kansas entered an interim order with respect to the Kansas portion of the Hugoton Field setting a minimum price of 80 per MCF for gas taken from the field. The order provided in part :

No person, firm or corporation taking gas from the Hugoton Field shall take or cause such gas to be taken out of the producing structures or formations thereof without attributing thereto for purposes of payment to the producers, landowners, leaseowners and royalty owners a fair and reasonable value at the wellhead of not less than eight cents per thousand cubic feet.

The pressure base then prevailing in Kansas was 16.4 p.s.i.a., and was not then changed by the Commission. The basis of the Commission’s order was to prevent waste and to correct inequities in prices prevailing in the field. The validity of this order was upheld by the Kansas Supreme Court. The 80 minimum price was the equivalent of 7.150 on a pressure base of 14.65 p.s.i.a.

111.By order dated December 2, 1953, effective January 1, 1954, the Kansas State Corporation Commission, after public bearings, established a new minimum price for the Kansas-Hugoton Field of 110 per MCF, this time on a pressure base of 14.65 p.si.a. Said order was invalidated by the United States Supreme Court on January 20,1958, on the same ground as the Oklahoma minimum price was invalidated. In summary, the status of the Oklahoma and Kansas minimum price orders was as follows during each of the years in question:

Year Oklahoma Kansas
1952 1953 1954 1955 1956 70 prior to July 29. 9.82620thereafter. 9.82620. 9.82620. 9.82620prior to invalidation on April 11.. No minimum price thereafter. None. 7.150 7.150 110 110 110

112. The Oklahoma and Kansas minimum price orders applied only to the production of natural gas from the formations in the Hugoton Field of Permian age. Neither the pre-Permian formations within those fields, nor other producing formations outside those fields, in the States of Oklahoma and Kansas were subject to those orders. During the years 1952 through 1956, the minimum price orders were a floor, not a ceiling, on prices for natural gas and were just one of the economic factors affecting wellhead prices of gas in plaintiff’s area. Other factors, such as increased competition by pipeline companies, were also at work in the area.

113. During the years 1952 through 1956, plaintiff paid production taxes levied on its own production of natural gas to the States of Oklahoma and Texas on the basis of the royalty prices paid by plaintiff. The State of Kansas levied no production taxes during these years but did levy, for some years, a tax calculated on each MOF of gas produced. The purpose of this tax was to pay the costs of operation of the Kansas Corporation Commission.

114 (a). For purposes of computing its weighted-average prices for 1952 through 1956, defendant accepted, with one exception, the area selected on behalf of plaintiff by Mr. Horn. (See findings 92 and 93.) This exception was Baca County, Colorado, which defendant attempted to exclude from plaintiff’s area (but later found it had been unsuccessful in doing so) for the sole reason that plaintiff had no production in that state during the years in issue. Mr. Oliver W. Jones, a petroleum engineer employed as a valuation engineer in the National Eesources Section of the Depreciation, Depletion, and Valuation Branch of the Internal Kevenue Service, was assigned the task of making these computations for and on behalf of defendant. Mr. Jones had also assisted in selecting contracts and in computing weighted-average prices in the Eugoton Production Go. case sufra. (See finding 92 and footnote 11.) Although defendant accepted the area selected by plaintiff, it divided said area into three parts, as follows: (a) the counties in Texas, (b) the counties in Oklahoma, and (c) the remaining counties which were in Kansas, plus one county in Colorado, i.e., Baca County, mentioned above. Defendant then computed a weighted-average price for each of these three areas for each of the years in question using the same sales used by plaintiff in its computation, plus the sales for 1952 and 1953 under the two contracts described in finding 107.

(b). The volumes used, the amounts paid, and the weighted-average prices as computed by defendant, are set forth in the following table:

Year Area MCF at 14.65 p.s.i.a. Amount paid Weighted-average price
1952 1952 1952 1963 1953 1953 1954 1954 1954 1955 1965 1955 1956 1956 1956 Kansas. Oklahoma. Texas. Kansas.... Oklahoma. Texas.. Kansas.... Oklahoma. Texas. Kansas.... Oklahoma. Texas. Kansas.... Oklahoma. Texas. 185,665,662 12,166,481 35,999,811 203,202,470 39,300,664 33,430,872 237,628,366 43,654,991 32,240,914 253,045,700 52,377,633 46,219,301 255,409,104 50,631,897 35,052,754 $14,208,951.67 1,139,640.30 2,265,966.49 15,815,817.06 4,331,364.96 2,666,724.23 26,478,540.76 4,686,503.93 2,492,837.90 28,194,546.95 6,742,230.07 4,581,558.63 29,096,452.36 5,979,399.18 3,226,955.00 7.65$ 9.37 0 6.290 7.780 11.020 7.650 11.140 10.740 7.730 11.140 10.960 9.910 11.390 11.810 9.210

115 (a). As indicated in finding 114 (a), defendant’s computations of weighted-average prices for the State of Kansas for the years 1954, 1955, and 1956, included volumes of gas produced and sold in Baca County, Colorado. (See (b), infra.) In its computation of the weighted-average price for the State of Oklahoma for the year 1956, defendant included volumes of gas produced and sold in Hansford County, Texas. (See (c),infra.)

(b). While Baca County, Colorado, was included in the area used by both parties, there were no wellhead sales in that county during 1952 or 1953, and only a very few sales therein in 1954 through 1956. Specifically, there were three contracts providing for wellhead sales in Baca County. They were executed in 1954 and 1955. The sellers were Amerada Petroleum Corporation, Skelly Oil Company, and Southwestern Exploration Company. The buyer in all three contracts was Colorado Interstate Gas Company. The sales under these contracts used by the parties in their computations were as follows:

MCE at 14.65 p.s.i.a. Amount paid Average amount paid per MOF Year Seller
158,983 611,732 810,479 698,915 958,607 646,347 $22,782 87,880 120,924 99,932 138,730 92,526 14.330 14.370 14.920 14.300 14.470 14.320 1954 1955 1955 1956 1956 1956 Southwestern.. Southwestern.. Skelly.. Southwestern.. Skelly.. Amerada..

Some portion of the foregoing sales pursuant to the Amerada and Shelly contracts apparently were attributable to production in Kansas because the acreage committed included acreage in Kansas as well as Colorado. All of the acreage committed under the Southwestern contract was in Colorado.

(c). In computing its 1956 weighted-average price for Oklahoma, defendant took into consideration a wellhead purchase reported by Natural Gas Pipeline Co. of America as having the following point of receipt: “Camrick and Blake-more Area, Texas Co., Okla. and Hansford Co., Tex.” The purchase involved 4,251,968 MCF and payment of $681,574 or 16.007$ per MCF. There is no evidence showing the volumes of gas involved in that purchase which are properly attributable to the States of Texas and Oklahoma. Treatment of all this gas as an Oklahoma purchase undoubtedly resulted in defendant computing a somewhat higher weighted-average price for plaintiff’s production in 1956, since its Oklahoma production exceeded its Texas production in that year.

(d). It is reasonable to assume that examination of all of the sales contracts and acreage descriptions appended thereto, used by the parties, probably would have disclosed that other contracts, in addition to those mentioned in (b) and (c) above, covered sales transactions which involved the crossing of state lines; however, if the sample of contracts used is large enough to make discrepancies of this kind insignificant in the final weighted-average prices computed, it is concluded that consideration of such discrepancies is unnecessary.

116. There is no evidence in the record that, after defendant’s division of plaintiff’s area along state lines, the gas purchases used by defendant in computing the weighted-average prices for each of the three states (shown in the table set forth in finding 114(b)) included gas comparable to plaintiff’s production in each of these states. There is also no evidence in the record that each of these three divisions along state lines constituted a separate and distinct common competitive purchase area.

117 (a). Of plaintiff’s total production of natural gas in the States of Kansas, Oklahoma, and Texas, during the years 1952 through 1956, the approximate percentage thereof produced in each of the three states is set forth in the following table:

State 1952 1953 1954 1955 1956
Kansas. Oklahoma... Texas_ 35% 15% 50% 30% 20% 50% 40% 25% 35% 50% 20% 30% 35% 40% 25%
Total-100% 100% 100% 100% 100%

(b). Of the volumes of natural gas used by plaintiff and defendant in their computations of weighted-average prices, the following table sets forth the approximate percentage thereof produced and sold in each of the States of Kansas, Oklahoma, and Texas:

Year Total volume inMCF Kansas Oklahoma Texas
1952.. 1953-1954-1955-1956-231,766,104 274,180,050 313,524,271 *351,651,634 *341,093,755 80% 75% *75% *70% *75% 5% 15% 15% 15% 15% 15% 10% 10% 15% 10%

The fact that a perfect balance between plaintiff’s production and the sales used could not be obtained is not considered strange in the light of the factors present in this case. When about 80 percent of the gas produced in the Texas Panhandle Field, for example, is not sold at the wellhead (see finding 100), this puts a severe limitation on the sample to be used in any weighted-average calculation.

118. The following table sets forth the volumes of plaintiff’s production of natural gas within its area in the State of Texas and the volumes of natural gas used by defendant in computing weighted-average prices for the same area in Texas:

Year Plaintiff's production (MCF) Volumes used for weighted-average computations (MCF)
1952. 1963. 1954. 1955. 1956. 41,593,198 37,014,102 30,069,788 29,933,210 24,617,337 35,999,811 33,430,872 32,240,914 46,219,301 35,052,754

Ultimate Findings and Conclusions

119. On the basis of tile entire record considered as a whole, it is concluded and found that the representative market or field price for the natural gas produced by plaintiff in its selected area during the years 1952 through 1956 was as follows:

Price
Year Per MCF
1952 __ 7.536(i
1953 _ 8.23 <t
1954 _10. 74 4
1955 _10. 95 0
1956 _11.23 4

120. The foregoing prices (set forth in finding 119) are calculated as the average price for each year, weighted by quantity, of comparable gas sold in plaintiff's area on the property (wellhead or separator) under a fair selection of contracts in effect during the year. In each of the years, the volumes of gas used to calculate the price shown were substantially in excess of plaintiff’s total production in the area. Therefore, it is found that the sample was adequate to permit the evening out in the area of various factors such as wide variations in producing conditions, in amounts of production from individual leases, and in the quality of the gas, thus tending to make the price for each year more representative of the value of plaintiff’s production. Although the large volumes of gas used in the sample also minimized the effect of known and unknown reporting errors in the gas purchase sections of the Forms 2 filed with the FPC, obvious errors therein established by the evidence should be corrected in this case since there was no apparent agreement between plaintiff and defendant that they would be limited to, or he hound by, the information in said forms, i.e., that they could not go behind the same. The contracts selected represented sales to actively competing pipeline companies in a common competitive purchase area within the locality of plaintiff’s production. There is no real evidence in the record that state lines or other political bomidaries, or the minimum price orders in effect in the States of Kansas and Oklahoma as to Permian production from the Hugoton Field, had any significant effect on competitive prices being paid for natural gas during the years in issue.

121. It is concluded and found that the representative market.or field price for each of the years 1952 through 1956 for plaintiff’s production of natural gas in the Hugoton Bmbayment in the States of Kansas, Oklahoma, and Texas is the same as the representative market or field price (shown in finding 119) for the natural gas produced by plaintiff in its selected area during each of said years, and that such price is the proper one to use in determining, for the purpose of computing deductions for percentage depletion allowance, plaintiff’s gross income from the production of natural gas from properties in which it had an economic interest located, in said Embayment in the above-mentioned States in those years.

Depletion Issue — Howell Field.

122. At all times material herein, plaintiff owned, as lessee, an economic interest in oil and gas leases on land in what is called the Howell Field located in Livingston County, Michigan, approximately 50 miles northwest of Detroit. Plaintiff was the sole producer of natural gas from said field in 1952. It was stipulated that during said year, plaintiff produced from its 14 producing gas wells in the Howell Field, 2,625,508 MCF of natural gas stated at a pressure base of 15.025 p.s.i.a. All of this gas was sold and delivered to Consumers Power Company in 1952, pursuant to a written contract entered into by plaintiff and Consumers in 1950. (See finding 127 and footnote 25 thereto, infra, for detailed facts concerning this contract, and the sales and deliveries of gas made by plaintiff thereunder.) A portion of plaintiff’s gas from the Howell Field was passed through a field separator owned by plaintiff for the purpose of recovering a portion of liquefiable hydrocarbons therein. During the calendar year 1952, plaintiff realized $4,150 from the sale of the hydrocarbons so recovered.

123. Plaintiff acquired its first oil and gas lease in the Howell Field in about 1943 or 1944. Discovery of natural gas in the Howell Field occurred in 1947. The wells were drilled to an approximate depth of 3,000 to 4,000 feet to the Silurian formation of pre-Permian age. In all, 16 wells were drilled of which 14 were producers of natural gas. All of these wells were drilled by plaintiff, except one known as McPherson No. 1-35 which was purchased by plaintiff prior to 1952. Initially, in 1947, the wellhead pressure of the Howell Field was 1,602 pounds and the reservoir pressure was something over 1,800 pounds. While the evidence does not definitely establish the wellhead pressure of the 14 producing wells in the Howell Field in 1952, the record discloses that during said year the gathering system was being operated at a pressure of 800 pounds per square inch gauge and that the gas from these wells had to be decompressed before being injected into the system; therefore, it is apparent that the pressure at the wells must have been in excess of the above-mentioned amount. Development of the field was completed two or three years after the initial discovery and it continued to produce natural gas until 1962. In all, approximately 23.7 billion cubic feet of gas were produced. The Howell Field was the second largest gas field in the State of Michigan. At the present time, plaintiff uses the Howell Field for underground 'storage. The gas produced from the field had a heating value of 1,080 BTU and had a much lower water content than was normal. This was advantageous to plaintiff in that it permitted the gathering and delivery of the gas without the necessity of installing dehydration facilities. During the year 1952, plaintiff had no other production in the State of Michigan, and made no purchases of gas from wells located in that State.

124 (a). Under plaintiff’s lease agreements with its various lessors in the Howell Field, plaintiff had the following obligation to account to the lessors for the natural gas produced:

To pay to Lessor as royalty for gas from each well where gas only is found, while the same is being sold or used off the premises, one-eighth of the market price at the wells of the amount so sold or used, the Lessor to have gas free of charge from any gas well on the leased premises for all stoves and inside lights in the principal dwelling house on said land by making his own connections with the well at his own risk and expense.

From January 1, 1952 through November 30, 1952, plaintiff paid to its lessors royalties computed at the rate of 150 per MCF at a pressure base of 15.025 p.s.i.a. These royalties were paid pursuant to royalty gas division orders, effective December 1,1947, which were negotiated by and between plaintiff and substantially all of its lessors in the Howell Field during the period 1947 to the latter part of 1950. The division orders were the same form as the one used for McPherson No. 1-35 well which was dated January 1, 1947, effective December 1, 1947, and provided in part:

You [plaintiff] are hereby authorized during the term of the present leasehold thereon, or any renewal thereof, to receive all merchantable gas in its natural state of production from said well or wells and to pay for the one-eighth (%) royalty interest in said gas to the undersigned, severally, in the proportions named, subject to the following conditions:
First: Because of the absence of a determinable market price in the area, it is agreed that, commencing with first production and continuing 'for a period of five (5) years from December 1,1947, settlement for said royalty interest shall be made on the basis of a valuation of fifteen cents (150) per one thousand (1,000) cubic feet of all gas produced and saved on the basis of measurement hereinafter provided for. * * * Upon the termination of said 5-year period, or any agreed extension thereof, the basis for payment of such royalty interest shall be governed by the lease or leases underlying such well or wells.

(b). On December 1, 1952, said royalty rate of 150 was increased to 200 per MCF at same above-mentioned pressure base, and on December 1, 1953, the latter rate was increased to 250 retroactive to December 1, 1952. Thus, it is apparent that plaintiff actually paid said royalties at a rate of 250 per MCF commencing on December 1, 1952, and subsequent thereto. While the 150 royalty price established under the above-mentioned royalty gas division orders and paid to the royalty owners up to December 1,1952, might have had some relationship in 1947 to the going price for gas in Michigan prevailing under old contracts made in the e'arly 1940’s, said price was substantially below the price of 32%0 plaintiff received for its Howell Field gas in 1952 from Consumers Power Company pursuant to the 1950 contract described in finding 127, infra. By 1951, there were several royalty holders in the Howell Field intensely dissatisfied with the 150 price established for payment of royalties 'and there was a great deal of ill feeling before the price was retroactively increased to 250 as stated above.

125. In its tax return for the calendar year 1952, plaintiff claimed a deduction for percentage depletion under sections 23 (m) and 114 of the 1939 Code, as amended, with respect to its production of natural gas from its wells in the Howell Field. The gross income from the properties was computed by plaintiff at the rate of 26140 per MCF of gas for the 2,625,508 MCF of gas so produced in 1952, amounting to $695,759.61. In the final determination of plaintiff’s income tax liability for that year, the Commissioner of Internal Kev-enue determined that plaintiff’s gross income from its properties was $429,116.32. In making said determination, the Commissioner used as the representative market or field price of plaintiff’s produced gas, an amount which was the equivalent of the rate per MCF at which plaintiff paid royalties to its lessors in the Howell Field. Based upon such determination, the Commissioner computed and allowed a deduction for percentage depletion in the amount of $95,750.21. No deduction for percentage depletion with respect to the $4,150 realized by plaintiff from the sale of hydrocarbons recovered was allowed. (See finding 122.)

126. For the calendar year 1952, plaintiff assigned the following values to its owned production from the Howell Field in preparation of severance tax returns filed with the State of Michigan:

Cents per MOP
Working interest Royalty interest
16(5 20(5 16(5 25(5 January 1 to November 30, 1952... December 1 to December 31, 1952..

These values were determined by negotiation between plaintiff and the State of Michigan, and were based upon the price used for payment of royalties. (As noted in finding 124(a), the royalty rate was increased on December 1, 1952, to 200 per MCF; subsequently, on December 1, 1953, the royalty rate was raised to 250 per MCF retroactive to December 1, 1952.) A retroactive tax payment was made with respect to the royalty interest, but not with respect to the working interest.

127. As previously indicated (finding 122), under date of April 21, 1950, plaintiff entered into a written contract with Consumers Power Company, a Maine corporation, for the sale and delivery of natural gas from its Howell Field wells. This contract remained in full force and effect throughout 1952. It specified the following delivery points:

i. At the outlet side of Panhandle’s measuring station located near its McPherson No. 1 well in Livingston County, Michigan;
ii. At the outlet side of Panhandle’s Salem Measuring Station in Oakland County, Michigan; provided, however, that such volumes of gas are thereafter transported by Panhandle for the account of Consumers, to the outlet side of Panhandle’s Plymouth and/or Clawson, Michigan Measuring Stations.

The contract price for all deliveries of natural gas by plaintiff to Consumers Power Company was 321/20 per MCF. The parties stipulated that pursuant to the contract, plaintiff, in 1952, made the following deliveries of its natural gas stated at a pressure base of 15.025 p.s.La. produced from the Howell Field to Consumers Power Company:

Point of delivery Volumes delivered MGF
In Town of Howell- 215,909
At Salem Measuring Station-2,413, 619
“2,629,528

128. In 1952, plaintiff’s McPherson well No. 1-35 produced 270,194 MCF of natural gas of which amount 215,909 MCF were delivered to Consumers Power Company in the Town of Howell at 321^0 per MCF. The delivery point in the Town of Howell was on the McPherson No. 1-35 lease, and was near the wellhead and on the lease property. Prior to the delivery in the Town of Howell, the pressure of the gas from the McPherson No. 1-35 well was lowered by a regulator and the gas was passed through a mechanical separator at the wellhead.

129. The remainder of the production from the McPherson No. 1-35 well, together with the production from plaintiff’s other wells in the Howell Field, was sold off the leases at the Salem Measuring Station. The parties stipulated that plaintiff’s cost of gathering the gas from its wells in the Howell Field and in moving it some 30 to 40 miles to the points of delivery .to Consumers Power Company, including depreciation, was, during the year 1952, not in excess of 3%$ per MCF at a pressure base of 15.025 p.s.i.a. No compressor station was installed in the field until 1955.

130. During 1952, production of natural gas in Michigan amounted to approximately 5.1 billion cubic feet of which about one-half was from the Howell Field. Some of the gas produced outside the Howell Field was sold at the wellhead. Mr. C. H. Hinton, a well-qualified, registered professional engineer, now employed as a consulting petroleum engineer, much of whose work deals with natural gas, presented credible expert testimony at the trial oil behalf of plaintiff. Mr. Hinton commenced working in the oil and gas industry in 1929. He was employed by plaintiff from 1931 to 1953, during which period he served in several capacities, including the positions of Chief Production Engineer, Superintendent of Production Reserves, and Vice President. He was not only familiar with plaintiff’s operations in the Hugoton Embay - ment, but also in the State of Michigan. In 1941, he started exploring the possibilities of expanding plaintiff’s gas operations in Michigan, and studied both past and potential production data involving that state. Under his direction as head of plaintiff’s Michigan operations, plaintiff acquired over 10,000 acres of leases in said state, and the Howell Field was developed under Mr. Hinton’s supervision. Accordingly, he was well acquainted with the natural gas situation that existed in the Michigan area during the period in question.

Mr. Hinton investigated a number of dry gas fields, and wells drilled within the city limits of Big Rapids, Michigan, all located about 125 miles either northeast or northwest of the Howell Field. These fields produced only about 5 percent of Michigan’s total production for 1952. In general, said fields were about 8 years old in 1952, and by that time they had produced more than half of the recoverable reserves. In said fields, plaintiff’s expert found a number of wellhead sales, some at 150 per MCF under contracts made during the early 1940’s, and others at higher prices -under later contracts. None of the contracts covering these sales were introduced in evidence by either plaintiff or defendant. Mr. Hinton testified that he determined said sales did not involve gas comparable to plaintiff’s Howell Field production because they involved small volumes and much lower pressure, adding that this was so “particularly with respect to the reserve back of these sales.” Another reason given by him for not considering these sales for comparative purposes was because the wells involved were located more than 30 or 40 miles from the Howell Field and therefore were entirely outside of the competitive market area of plaintiff’s production (as he understood the meaning of the term “comparative gas” as used by this court in its decisions in Hugoton Production Co. (cited in footnote 11 to finding 92). However, as indicated above, Mr. Hinton did not disregard the sales in question simply because of the distances the wells were located from the Howell Field. It appears from his testimony that there was no commercial gas producing field closer to the Howell Field than the ones mentioned above which he investigated in an effort to find comparable sales. In 1952, Mr. Hinton also investigated some other areas in Michigan (as well as in adjoining states), but his investigation covered only a small percentage of .the gas production in Michigan during that year outside of the Howell Field. On the basis of the entire investigation conducted by Mr. Hinton, he concluded that during 1952 there were no wellhead sales by other producers in the immediate locality of the Howell Field or elsewhere m Miohigcm or in adjoining states, of natural gas which he considered was comparable to the gas produced by plaintiff from the Howell Field.

131. Defendant sharply disputes, for a number of reasons, the acceptability of the conclusions reached by plaintiff’s expert witness, Mr. Hinton (set forth in finding 130), and contends plaintiff did not sustain its burden of proving that there were no comparable sales. In this connection, it is significant to note that neither plaintiff nor defendant introduced in evidence a single contract concerning a wellhead or on the lease property sale of comparable gas by another producer in the immediate locality of the Howell Field or elsewhere, and there is no evidence of any other kind whatsoever in the record specifically relating to a particular sale of such a nature. The evidence shows that the only wellhead sale of comparable gas in the locality during 1952, was plaintiff’s sale to Consumers Power Company of 215,909 MCF of gas which was produced from plaintiff’s McPherson Well No. 1-35 and delivered to the town of Howell. As previously indicated (see finding 127), this sale was made pursuant to one contract which covered other sales in 1952, to Consumers Power of gas produced from the above-mentioned well and other wells in the Howell Field in which plaintiff had an economic interest during that year.

Ultimate Findings and Conclusions

132. Considering all the facts, circumstances, and evidence, as a whole, it is found that plaintiff made a reasonable investigation and evaluation of wellhead or on the lease property sales of natural gas by other producers in Michigan and adjoining states during 1952, in an effort, albeit unsuccessful, to establish the existence of comparable sales of such kind involving gas comparable to that produced by plaintiff from the Howell Field; that plaintiff reasonably discharged its burden of proving that there were no such comparable sales by other producers in areas located within a reasonable distance of the Howell Field; and that the sale of gas made by plaintiff from the wellhead of its McPherson Well No. 1-35 to Consumers Power for delivery to the Town of Howell in 1952, constituted a sale of comparable gas which properly may be considered in resolving the question relating to the determination of a representative market or field price of plaintiff’s natural gas produced from the Howell Field in 1952.

133. It is also found that plaintiff has proved that the market price of its natural gas which was sold and delivered on the lease property near the wellhead in the Howell Field during the year 1952 was 32%0 per MCF; and that said price should be used in determining plaintiff’s gross income from this production in said year for percentage depletion allowance purposes.

134. It is further found that the situation with respect to the Howell Field is of such an unusual nature that a price of per MCF should not be considered the representative marhet or field price of the remainder of plaintiff’s production of gas from said Field that was sold in the year in suit after it was transported off plaintiff’s leases; and that as to the latter production, there should be deducted from the sales price thereof, the stipulated cost of 3y2$ per MCF to plaintiff of gathering the gas from its wells in the Howell Field and transporting the gas off the leases, resulting in a price of 290 per MCF which properly should be used in determining plaintiff’s total gross income from the property for the production for the purpose of computing plaintiff’s percentage depletion for 1952.

135. Finally, it is found that the $4,150 which plaintiff realized from the sale of hydrocarbons obtained by passing a portion of the Howell Field gas through a field separator (see finding 122), should be added to plaintiff’s gross income in computing its percentage depletion allowance.

Conclusion oe Law

Upon the foregoing findings of fact and opinion, which are adopted by the court and made a part of the judgment herein, the court concludes as a matter of law that the plaintiff is entitled to recover with respect to all of the three principal issues involved herein, to the extent and in the manner indicated in the findings and opinion, and judgment is entered to that effect. Defendant’s setoff is denied. The amount of recovery will be determined pursuant to proceedings under Rule 47 (c) which shall be conducted in accordance and consistent with the findings and opinion.

Appendix

INTERNAL REVENUE CODE OE 1939 :

(26U.S.C. §23 (1952).)

§23. Deductions from gross income. [As amended by Sec. 121(c), Revenue Act of 1942, eh. 619,56 Stat. 798, 819.]

In computing net income there shall be allowed as deductions:

* * * * *

(?) Depreciation.

A reasonable allowance for the exhaustion, wear and tear, (including a reasonable allowance for obsolescence)—

(1) of property used in the trade or business, or

(2) of property held for the production of income. * * *

(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. * * *

(n) Basis for depreciation and depletion.

The basis upon wbicb depletion, exhaustion, wear and tear, and obsolescence are to be allowed in respect of any property shall be as provided in section 114.

*****

(26U.S.C. §114 (1952).)

§ 114. Basis for depreciation and depletion—

*****

(b) Basis for depletion—

*****

(3) Percentage depletion for oil and gas wells.

In the case of oil and gas wells the allowance for depletion under section 23 (m) shall be 27% 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.

*****

(26 U.S.C. § 611 (1958).)

§ 611. Allowance of deduction for depletion.

(a) General rule.

In the ease of mines, oil and gas wells, other natural deposits, and timber, there shall be allowed as a deduction in computing taxable income 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 regulations prescribed by the Secretary or his delegate.

(26 U.S.C. § 613 (1964).)

§ 613. Percentage depletion.

(a) General rule.

In the case of the mines, wells, and other natural deposits listed in subsection (b), the allowance for depletion under section 611 shall be the percentage, specified in subsection (b), of the gross income from the property excluding from such gross income an amount equal to any rents or royalties paid or incurred by the taxpayer in respect of the property. Such allowance shall not exceed 50 percent of the taxpayer’s taxable income from the property (computed without allowance for depletion). * * *

(b) Percentage depletion rates.

The mines, wells, and other natural deposits, and the percentages, referred to in subsection (a) are as follows:

(1) 27% percent — oil and gas wells.

TREASURY REGULATIONS 118 (1939 CODE) :

(§§39.23(1)-3, 39.23(m)-l, Fed Tax Beg. 127, 130-31 (1954).) § 39.23 (?)-3. Depreciation of intangible property.

Intangibles, the use of which in the trade or business or in the production of income is definitely limited in duration, may be the subject of a depreciation allowance. Examples are patents and copyrights, licenses, and franchises. Intangibles, the use of which in the business or trade or in the production of income is not so limited, will not usually be a proper subject of such an allowance. If, however, an intangible asset acquired through capital outlay is known from experience to be of value in the business or In the production of income for only a limited period, the length of which can be estimated from experience with reasonable certainty, such intangible asset may be the subject of a depreciation allowance, provided the facts are fully shown in the return or prior thereto to the satisfaction of the Commissioner. No deduction for depreciation, including obsolescence, is allowable in respect of good will.

§ 39.23 (m)-l. Depletion of mines, oil and gas wells, other natural deposits, and timber; depreciation of improvements

* * * # *

(e) As used in sections 114(b) (3) and 114(b) (4) (A) and §§ 39.23 (m)-l to 39.23(m)-19, inclusive, the term “gross income from the property” means the following :

(1) 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.

TREASURY REGULATIONS ON INCOME TAX (1954 CODE) :

(26 C.E.B. § 1.613-3 (1961).)

§ 1.613-3. Cross income from the property

(a) Oil and gas wells. In the case of oil and gas wells, “gross income from the property”, as used in section 613(c) (1), means the amount for which the taxpayer sells the oil or gas in the immediate vicinity of the well. If the oil or gas is not sold on the premises but is manufactured or converted into a refined product prior to sale, or is transported from the premises prior to sale, the gross income from the property shall be assumed to be equivalent to the representative market or field price of the oil or gas before conversion or transportation. ***** 
      
      The court acknowledges tlie assistance it has received from the report of Commissioner Franklin M. Stone. We have adopted his opinion on the second and third issues and most of his findings of fact.
     
      
       It should be made clear that only plaintiff’s investments in the items specifically mentioned as they relate to the acquisition of rights-of-way are involved in this case. While the record is not entirely clear, it appears that plaintiff has been permitted, for federal income tax purposes, to depreciate certain expenditures which plaintiff treated as a part of the cost of constructing its pipelines apparently on the theory that they were of such a nature that similar expenditures would recur with each reconstruction of the pipelines, such as, for example, engineering and office salaries and expenses, legal fees, and expenditures, surveying and. mapping costs¡, andi costs of clearing and grading the rights-of-way and damages attributable thereto. Items of this nature are not in controversy.
     
      
       The stipulated cost or other tax basis and the reserve for depreciation of plaintiff’s investment in rights-of-way (exclusive of gathering lines’ rights-of-way) as of December 31 of each of the years 1942 through 1956 are tabulated in finding 59. The figures in said finding include the costs or other tax basis as of December 31 of each year' of plaintiff’s investment in transmission system' rights-of-way relating to emergency facilities, and the amounts of such investment .as of the close of each .year in suit are set forth in finding 60, infra. See findings 60, 61, 62 and 65 (b) and (d), infra, for detailed facts concerning the depreciation treatment accorded plaintiff’s investment in rights-of-way relating to emergency facilities.
     
      
       Plaintiff produced gas from its properties in the Howell Meld during the other years in suit, but this production is not in controversy.
     
      
      
         Insofar as pertinent, Section 167 of the Internal Revenue Code provides:
      “SEC. 107. DEPRECIATION.
      “(a) G-eneral Rule. — There shall be allowed as a depreciation deduction a reasonable allowance for the exhaustion, wear and tear (including a reasonable allowance for obsolescence)—
      “(1) of property used in the trade or business, or
      “(2) of property held for the production of income.
      “(b) Use of Certain Methods and Rates. — For taxable years ending after December 31, 1953, the term ‘reasonable allowance’ as used in subsection (a) shall include (but shall not be limited to) an allowance computed in accordance with regulations prescribed by the Secretary or his delegate, under any of the following methods :
      “(1) the straight line method,
      “(2) the declining balance method, using a rate not exceeding twice the rate which would have been used had the annual allowance been computed under the method described in paragraph (1),
      ' “(c) Limitations on Use of Certain Methods and Rates. — Paragraphs (2), (3), and (4) of subsection (b) shall apply only in the case of property (other than intangible property) described in subsection (a) with a useful life of 3 years or more * *
     
      
       In Connecticut Light mid Power Co. v. United States, 177 Ct. Cl. 395, 368 F. 2d 233 (1966), relied upon by plaintiff, the principal issue was whether the cost of a flowage easement acquired in connection with the operation of a hydroelectric plant was a capital expenditure, as defendant claimed, or an ordinary business expense, as plaintiff claimed. We held that the costs were capital expenses and that the flowage rights had a useful life equal to the life of the power plant. For depreciation purposes, the power company used the composite account method in which all assets of the business were included in a single account pursuant to Treas. Reg. sec. 1.167(a) — 7(a) (1956). The flowage rights were acquired in 1955. After audit of the company’s tax returns for 1954 and 1955, the Internal Revenue Service approved plaintiff’s practice of depreciating the assets listed in the composite account by the double declining balance method. Finding that the addition of the costs of the easement to the company’s depreciable base would have an inconsequential effect, we held the company was entitled to include such acquisition costs in the composite account. However, the decision did not refer in any way to the limitation which section 167 (c) imposes on the use of accelerated methods of depreciation, and no mention was made of the distinction between tangible and intangible property for tax purposes. Because of these and other material differences, we do not  adopt the method approved under the facts of that case as a basis for deciding the depreciation issue in these cases.
     
      
       Plaintiff’s claims giving rise to this second issue, as well as the third issue (discussed later in this opinion) are basically governed by the provisions of §§23(m) and 114(b)(3) of the Internal Revenue Code of 1939, as amended, supra, 26 U.S.C. §§23(m), 114(b)(3) (1952 ed.), and §§ 611 and 613 of the Internal Revenue Code of 1954, 26 U.S.C. §§ 611, 613 (1958 ed.). The aforesaid sections of the 1939 Code are applicable to the years 1952 and 1953, and the said sections of the 1954 Code are applicable to the years 1954, 1955, and 1956. All of said Code sections are quoted in pertinent part in the Appendix, infra.
      
     
      
       Treas. Reg. 1.613-3(a). See Appendix, infra.
      
     
      
       For example, in the landmark decision rendered by the Supreme Court in Cannetton Sewer Pipe Co., supra, the Court pointed to sales of raw fire clay in Indiana “about 140 miles” from taxpayer’s mines as indicating the existence of a substantial market for the raw material. Reference was also made to sales in another state, Kansas. [364 U.S. at 76, 8D, 86.]
     
      
       The prices determined for the years 1952 and 1953 vary from the weighted-average prices proposed by plaintiff for said years. (See finding 105(b), infra.) Adjustments were found necessary for reasons which are mentioned earlier in this opinion, and explained in more detail in finding 107, footnote 12 thereto, and finding 120, all infra.
      
     
      
       See footnote 6, swpra, for complete citations to the sections of the 1939 Code that provide the statutory authority upon which the claim giving rise to this, issue is based. Pertinent sections of said Code are set forth in the Appendix, infra.
      
     
      
      
         The discrepancy between this stipulated figure and the one stated in finding 127, infra> is explained in footnote 25 to said finding.
     
      
       This figure is based on the stipulated one contained in finding 127, infra. See footnote 11, supra, and footnote 25 to finding 127.
     
      
       These factors were as follows :
      “(a) The volume available for sale. Generally, the greater the volume or reserves, the greater the price the seller could command.
      (b) The location of the leases or acreage involved, whether in a solid block or scattered, and their proximity to prospective buyers’ pipelines.
      (c) Quality of the gas as to freedom from hydrogen sulphide in excess of 1 grain per 100 cubic feet.
      (d) Delivery point.
      (e) Heating value of the gas.
      (f) Deliverability of the wells. The larger the volume that could be delivered from a reserve, the greater the price the seller could command.
      (g) Delivery or rock pressure. The higher the pressure, the less compression for transportation is required.” * * * [172 Ct. Cl. at 449-50, n. 7, 349 E. 2d at 420-21, n. 7.]
     
      
       See finding 130, infra, for details covering Mr. Hinton’s qualifications, the investigation made by him, and his conclusions.
     
      
       Neither party offered in evidence a single contract under which any of these sales were made.
     
      
       See footnote 13, supra.
      
     
      
       Defendant’s contention that this case is not in point is unsupported by reasons considered accurate, valid, or relevant.
     
      
       Defendant objects to the Riverton case on the ground, inter alia, that it was not an oil or gas case. This argument is hardly convincing. In its decision in the Hugoton case, this court did not hesitate to cite with approval mineral depletion cases. For instance, the leading case of United States v. Gannelton Sewer Pipe Oo., supra, involved mineral depletion — not oil and gas; however, no one would deny its application to the entire depletion field.
     
      
       The court was referring to Treas. Reg. 118 § 39.23(m) — 1(e) (1), supra. See Appendix, infra.
      
     
      
       In the second Sugoton decision, this court analyzed, discussed, and cited with approval the decision of the Fifth Circuit in Senderson. A reading of this court’s references in said Sugoton decision to Senderson and study of the opinion in the latter case discloses the soundness of our action in eschewing the “market comparison” method in the instant proceeding.
     
      
       Treas. Reg. 118 § 39.23 (m)-1(e) (1) supra. See Appendix, infra.
      
     
      
       This formula, as proposed by the Government in the first Hugoton proceeding, is summarized in the court’s first opinion in that case and described more fully in Finding 49 therein. See Hugoton Promotion Co., supra. See 161 Ct. Cl. at 279, n. 13, and Finding 49 at 314-315, 315 F. 2d ait 870, n. 13, and Finding 49 at 891.
     
      
       Treas. Reg. 118 § 39.23 (m)-1(e) (1), supra. See Appendix, infra.
      
     
      
      
        Ibid.
      
     
      
      
         In its brief to tbe court, defendant contends tbat tbe 29‡ figure should be reduced by an amount, which defendant says, represents profit on tbe taxpayer’s investment in its gathering and transportation facilities. This contention raises a factual issue which should have been but was not presented to the trial commissioner by defendant. For that reason, we think the defendant has waived the contention and do not consider it.
     
      
       See finding 82 and footnote 8 relating thereto, infra.
      
     
      
       Many of these findings of fact are based upon facts incorporated in a comprehensive Stipulation of Pacts (to -which are attached joint exhibits 1 through 28) filed by the parties on October 29,1965.
     
      
      Of this amount, $44,720 was thereafter refunded to plaintiff on an issue not involved in this proceeding.
     
      
       It should be noted that gathering: system rights-of-way costs, per se, are not involved in this case; however, this finding of fact has been found despite defendant’s objection thereto on the ground, inter alia, of irrelevancy, since plaintiff directs certain arguments to this subject matter and defendant raises in its brief a claim of “setoff” with respect to such costs.
     
      
       Defendant contends that these statements are contrary to applicable Treasury Regulations (citing Treas. Regs, on Income Tax, § 1.167 (a) (3) (1954), and Treas. Reg. 118, §39.23(1)2 (1938)), which assertedly bar depreciation of an “intangible” unless the length of its useful life “can be estimated with reasonable accuracy.” Plaintiff argues that the evidence establishes that its right-of-way costs are not “intangibles” and thus do not come within the above-cited regulation; that, therefore, there is no conflict between the findings in question and said regulations.
     
      
       None of these exhibits nor any other evidence in the record discloses the number of well completions, if any, in the State of Texas during the year 1964.
     
      
      The reserve balances include adjustments for normal retirements and transfers of the following reserve amounts:
      1942 Transfer to Land and Crop Damages. ($128,982)
      1943 Michigan Gas acquisition. 68,693 Illinois Natural Gas acquisition... 40,139
      1954 Disallowance of Howell Field rights-of-way. 2,169
     
      
       Exhibits 17, 18, and 19 attached to the stipulation of facts (referred to inj footnote 1) are copies of pages 1 of the “Necessity” certificates issued under the 1989 Code, and Exhibits 20, 21, and 22 are copies of pages 1 of such certificates issued under the 1954 Code.
     
      
       See footnote 5.
     
      
      
        Ibid.
      
     
      
       The condensate Involved is the same as the “liquid hydrocarbons” extracted on the individual leases or properties by use of mechanical separators described by one of plaintiff’s witnesses. The inclusion of the proceeds from the sale of the condensate or liquids in gross Income for depletion purposes is not in controversy between the parties.
     
      
      
         Ibid.
      
     
      
       A “favored nation” clause obligated the buyer to Increase the contract price to the level of any higher price paid by the buyer to any other producer in the area, or to increase the contract price to the level of any higher price paid by any other purchaser in the area.
     
      
       161 Ct. Cl. 274, 315 P. 2d 868 (1963), and 172 Ct. Cl. 444, 349 P. 2d 418 (1965).
     
      
       Plaintiff does not deny that Its purchases in 1952 and 1953, under the two contracts in question, were at the wellhead in the Texas portion of its selected area; however, despite this fact and that plaintiff acknowledges that “[t]he occasional obvious error should be corrected,” it inconsistently contends that it was justified in disregarding the two known errors in question when computing the weighted-average prices simply because such purchases were not listed in the gas purchase sections of the Forms 2. It is plaintiff’s position that the information contained in said forms should control regardless of the fact certain of such information is known to be erroneous, since other improper omissions or even inclusions may have occurred and it is impractical to go behind the forms for the purpose of making a determination with respect to the accuracy of the information shown thereon. In this connection, it should be mentioned that during the course of pretrial proceedings, it was understood by both parties that for practical reasons they would rely, in the main, upon the information contained in the gas purchase sections of the Forms 2 ; but the parties did not agree to be limited to, or bound by, such information and no commitment was made by either party that it would be unnecessary to correct any errors which actually turned up in said forms. While defendant generally relied on the information contained in these forms, it, for varying reasons, went back thereof in a number of instances and examined certain gas purchase contracts on file with the FPC to determine whether they involved wellhead or non-wellhead sales. As a result of such checks, defendant discovered the errors noted in the instant finding and used corrected figures in computing its proposed weighted-average prices for plaintiff’s production of natural gas during the years in suit. In response to a comment made by the commissioner at the trial to the effect that he did not know what would have developed if both parties had gone behind the Forms 2 to any greater extent than this had been done by defendant, the attorneys for both plaintiff and defendant stated, “We would never have tried this case.”
     
      
       Guymon-Hugoton is the name given to the Oklahoma portion of the Hugoton Field of Kansas, Oklahoma, and Texas.
     
      
      
         See Cities Service Gas Co. v. Peerless Oil & Gas Co. and Phillips Petroleum Co. v. State, 203 Okla. 35, 220 P. 2d 279 (1950).
     
      
       See Cities Service Gas Co. v. Peerless Oil & Gas Co., 340 U.S. 179 (1950) ; and Phillips Petroleum Co. v. Oklahoma, 340 U.S. 190 (1950).
     
      
       See Natural Gas Pipeline Co. v. Panoma Corp., 349 U.S. 44 (1955).
     
      
       See Kansas-Nebraska Natural Gas Co. v. State Corporation Commission, 169 Kan. 722, 222 P. 2d 704 (1950) ; 170 Kan. 341, 225 P. 2d 1054 (1951).
     
      
       See Cities Service Gas Co. v. State Corporation Commission. 355 U.S. 391 (1958).
     
      
       Except for tie changes and variations in the approach taken by plaintiff mentioned in this finding (and explained further in finding 115(a)), the computations of both plaintiff and defendant reflect the same contracts and the same volumes of gas for the years 1952 through 1956. As noted in finding 115(a), infra, defendant’s computations of 'weighted-average prices for the States of Kansas and Oklahoma for certain years included volumes of gas produced and sold in other states.
     
      
       These same contracts were used by defendant in the Hugoton Production Go. case, supra, without any separation hy state lines.
     
      
       Neither the plaintiff nor defendant proposed that the weighted-average prices respectively computed and proposed by them he adjusted to reflect the volumes of gas Included in this purchase that were actually produced and sold in Texas and Oklahoma.
     
      
      Volumes used include some production in the State of Colorado.
     
      
       The figures under this heading are included among those listed in the table set forth in finding 68.
     
      
       The figures under this heading are included among those listed in the table set forth in finding 114 (b).
     
      
       The prices found for the years 1952 and 1953 vary from the weighted-average prices computed by plaintiff and set forth in finding 105(b), since the instant finding reflects adjustments made consistent with finding 107 (and footnote 12 thereto) and finding 120.
     
      
       In explanation of the discrepancy in the stipulated figure relating to the number of MCE of gas produced by plaintiff from its wells in the Howell Field during 1952 (set forth in finding 122), and. the MCE it soldi (delivered) during that year shown in the instant finding, it should he noted that the parties further stipulated that the difference was due to line gain or overage caused by variations in temperature where the gas was metered.
     