Panhandle Eastern Pipe Line Co. v. The United States

408 F.2d 690, 187 Ct. Cl. 129, 32 Oil & Gas Rep. 307, 23 A.F.T.R.2d (RIA) 933, 1969 U.S. Ct. Cl. LEXIS 130

• Court: United States Court of Claims
• Decided: March 14, 1969
• Docket: 547-58, 166-60, 400-61
• Status: Published

Opinion

OPINION

COWE.N, 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, infra,, 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, 1938, known as the “Natural Gas Act,” 15 U.S.C. § 717 et seq. 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 Liberal, 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 25 $ 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 agreéments from predecessor corporations which were named as the grantees in these agreements and were the parties that obtained the agreements from the 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 1 ) covering the above-mentioned items ranged from $1,914,490.11 on December 31, 1951, to $2,365,744 on December 31, 1956. 2 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 Embayment. 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. 3 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 disallowances 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.

I

DEPRECIATION OF RIGHTS-OF-WAY 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, 401 F.2d 799, 185 Ct.Cl. 547 (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 de-preciable under the provisions of Section 167 of the Internal Revenue Code of 1954. 4 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(e) 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, 347 F.2d 275, 294, 171 Ct.Cl. 580, 613-614 (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 further consideration of $- per linear rod, to be paid when the pipe lines hereinafter specified are laid, do hereby grant- and convey - unto Panhandle Eastern Pipe Line Company, a Delaware Corporation of Kansas City, Missouri, its sueeesors 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 to $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. of Missouri v. Commissioner of Internal Revenue, 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, 401 F.2d 796, 185 Ct.Cl. 570 (1968) ; Rev.Rul. 65-264, 1965-2 Cum.Bull. 53. 5

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 Revenue 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.Rep. No. 1622, 83d Cong., 2d Sess., p. 26, (3 U.S.C. Cong. & Adm. News (1954), p. 4837)]

The abbreviation “etc.”, following the word “leases”, shows a congressional intent to exclude from the depre- eiation 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 rights-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 EMBAYMENT

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 Revenue Code of 1939, and the corresponding and similar provisions of the 1954 Code, §§ 611 and 613, 6 a taxpayer holding an economic interest in oil or gas wells is permitted to take as a deduction from income 27% 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 income” from the raw product, if marketable in that form, and not on the finished article’s value. United States v. Cannelton Sewer Pipe Co., 364 U.S. 76, 80 S.Ct. 1581, 4 L.Ed.2d 1581 (1960). See also, this court’s second decision in Hugoton Production Co. v. United States, 349 F.2d 418, 172 Ct.Cl. 444 (1965) ; Greensboro Gas Co. v. Commissioner of Internal Revenue, 79 F.2d 701 (3rd Cir. 1935).

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

* * * From the outset, the producer [integrated] has been held entitled to include a 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. [315 F.2d at 869, 161 Ct.Cl. at 277.]

The first regulations bearing on the problem were adopted by the Internal Revenue Service (IRS) 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.Reg. 118, § 39.23(m)-1(e), as amended October 31, 1944. See also, Treas.Reg. 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. 7 For 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, sup ra, is that they do not define the term “representative market or field price” nor explain how gross income is to be determined in the absence of a representative market or field price. tt

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% 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.Reg. 118, § 39.23 (m)-l(e) (1), essentially the same as Treas.Reg. 1.613-3(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 * * * [315 F.2d at 877, 161 Ct.Cl. at 289.]

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. [349 F.2d at 421-422, 172 Ct.Cl. at 451-452.]

The court rejected the plaintiff’s argument, reasserting the position that “[t]he ‘representative market or field price’ required by the Regulation demands the utilization of an accounting system which considers comparative sales.” [349 F.2d at 427, 172 Ct.Cl. at 459.] 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 Colo rado) 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 Hugoton 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 30 miles of the taxpayer’s acreage provided sufficient sales of comparable gas from which to compute a representative market price. See 349 F.2d 418, 421, n. 9, 172 Ct.Cl. 444, 450, 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. 8

Thus, in the present ease, 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; that 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 puchase 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 aforestated 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 that there were both 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 context 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 geo graphical 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 * * *. [349 F.2d at 430-431, 172 Ct.Cl. at 463-465.]

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 plaintiffs 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. [349 F.2d at 431, 172 Ct.Cl. at 465.] 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 repersentative 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, infra, from that decision. [349 F.2d at 430-431, 172 Ct.Cl. at 464.]

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 that 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 Hugoton 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 Hugo-ton 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 in- elude 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. [315 F.2d at 876-877, 161 Ct.Cl. at 289.]

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 area 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 ease 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. [349 F.2d at 424-425, 172 Ct.Cl. at 455.] So here, the presence of an economic factor that affected a part of the Kansas and Okla homa 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 9

Year per MCF

1952 ......................... 7.530

1953 ......................... 8.230

1954 ...........-.............. 10.740

1955 ......................... 10.950

1956 ......................... 11.230

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 ISSUE— HOWELL FIELD

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 Revenue (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 Revenue Code of 1939, 10 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 Howell 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 Hugoton 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 11 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% 0 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%^ 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, totalling 2,413,619 MCF 12 of natural gas, was sold off the leases at 32% 0 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 3%{é 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 26%^ 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 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. 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 32%0 amounting to $61,399-.12, since the price of 32% (i 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 32% <f for its entire production of natural gas from the Howell Field. As indicated earlier in this opinion, the applicable Treasury Regulations pertaining to the depletion of gas (as well as oil) wells, Treas.Reg. 118 (1939 Code), § 39.23(m)-l(e) (1), supra, (see Appendix), provides that the words “gross income from the property,” as used in the depletion provision of the 1939 Code, means:

* * * [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.

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 Hugo-ton Production Co., supra.)

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 Hugoton 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 Hugoton 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 BTU 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 Hugoton decision, supra, this court noted that in the proceedings underlying the court’s first decision in Hugoton, 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 Hugoton Embayment. 13 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. 14 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, 15 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 16 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 Hugoton 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 Hu-goton case, 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 in vestigation 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 had 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 32per 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, supra,:

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. [315 F.2d at 877, 161 Ct.Cl. at 289,.]

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-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. * * [Emphasis supplied.] [349 F.2d at 431,172 Ct.Cl. at 464.]

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 Government 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 MCF. 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), 17 which case was cited by this court with approval in its second decision in Hugoton, supra. [349 F.2d 418, 425, n. 18, 172 Ct.Cl. 444, 455-456, 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 230 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. 18 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 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 [ 19 ] demands the utilization of an accounting system which considers comparative sales.” [349 F.2d at 427, 172 Ct.Cl. at 459.] 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 Hugoton 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%$ 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 Hugo-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%$ 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]. 20 We, too, find that a determination by us here that a 32% 0 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. 21 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. [315 F.2d at 869, 161 Ct.Cl. at 277.]

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% <f 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 82% 0 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 (32%0 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 arguments 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. 22

Defendant concedes that in the following sentence quoted from the first Hugo-ton 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. [315 F.2d at 873, 161 Ct.Cl. at 283.]

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 23 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.” [349 F.2d at 427, 172 Ct.Cl. at 459.]

As to the language last quoted from the court’s first Hugoton 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 24 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 the 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 321/20 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 321/20 per MCF sales price of such gas, the stipulated cost of 31/20 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. 25

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 depletable income in the Hugoton Embayment. 26 Accordingly, said amount should be included in plaintiff’s gross income.

IV

DEFENDANT’S CLAIMED SETOFF

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 setoff 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, 381 F.2d 421, 180 Ct.Cl. 676 (1967) ; GMO Niehaus & Co. v. United States, 373 F.2d 944, 179 Ct.Cl. 232, 253 (1967) ; Missouri Pac. R.R. Co. v. United States, 338 F.2d 668, 168 Ct.Cl. 86 (1964).

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

* The court acknowledges the 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.

1 . 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, and costs of clearing and grading the rights-of-way and damages attributable thereto. Items of this nature are not in controversy.

2 . 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.

3 . Plaintiff produced gas from its properties in the Howell Field during the other years in suit, but this production is not in controversy.

4 . Insofar as pertinent, Section 167 of the Internal Revenue Code provides:

“SEC. 167. DEPRECIATION.

“(a) General 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 * *

5 . In Connecticut Light and Power Co. v. United States, 368 F.2d 233, 177 Ct.Cl. 395 (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.

6 . 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.

7 . Treas.Reg. 1.613-3(a). See Appendix, infra.

8 . For example, in the landmark decision rendered by the Supreme Court in Con-nelton Sewer Pipe Co., supra, the Court pointed to sales of raw fire clay in Ind iana “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. 76, 80, 86, 80 S.Ct. 1581.]

9 . 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.

10 . See footnote 6, supra, 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.

11 . The discrepancy between this stipulated figure and the one stated in finding 127, infra, is explained in footnote 25 to said finding.

12 . This figure is based on the stipulated one contained in finding 127, infra. See footnote 11, supra, and footnote 25 to finding 127.

13 . 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.” * * * [349 F.2d at 420-421, n. 7, 172 Ct.Cl. at 449-450, n. 7.]

14 . See finding 130, infra, for details covering Mr. Hinton’s qualifications, the investigation made by him, and his conclusions.

15 . Neither party offered in evidence a single contract under which any of these sales were made.

16 . See footnote 13, supra.

17 . Defendant’s contention that this case is not in point is unsupported by reasons considered accurate, valid, or relevant.

18 . 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 ease of United States v. Cannelton Sewer Pipe Co., supra, involved mineral depletion— not oil and gas; however, no one would deny its application to the entire depletion field.

19 . The court was referring to Treas.Reg. 118 § 39.23(m)-1(e) (1), supra. See Appendix, infra.

20 . In the second Hugoton decision, this court analyzed, discussed, and cited with approval the decision of the Fifth Circuit in Henderson. A reading of this court’s references in said Hugoton decision to Henderson 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.

21 . Treas.Reg. 118 § 39.23 (m)-1(e) (1) supra. See Appendix, infra.

22 . 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 Production Co., supra. See 315 F.2d at 870, n. 13, and Finding 49 at 891, 161 Ct.Cl. at 279, n. 13, and Finding 49 at 314-315.

23 . Treas.Reg. 118 § 39.23(m)-1(e) (1), supra. See Appendix, infra.

24 . Ibid.

25 . In its brief to the court, defendant contends that the .290 figure should be reduced by an amount, which defendant says, represents profit on the 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.

26 . See finding 82 and footnote 8 relating thereto, infra.