1988 U.S. Tax Ct. LEXIS 26 | Tax Ct. | 1988
Lead Opinion
Respondent determined deficiencies in income tax and additions to the tax as follows:
Sheldon S. Watnick and Susan Watnick
Additions to tax
Sec. 6653(a)(1), Sec. 6653(a)(2), Sec. 6661,
Year Deficiency I.R.C. 1954 I.R.C. 1954 I.R.C. 1954
1978 $345.00 0 0 0
1979 24,674.58 $1,233.73 0 0
Sheldon S. Watnick
Additions to tax
Sec. 6653(a)(1), Sec. 6653(a)(2), Sec. 6661,
Year Deficiency I.R.C. 1954 I.R.C. 1954 I.R.C. 1954
1980 $34,510.44 $1,725.52 0 0
1981 30,160.83 1,508.04 (1) 0
Sheldon S. Watnick and Elizabeth Fay Taylor-Watnick
Additions to tax
Sec. 6653(a)(1), Sec. 6653(a)(2), Sec. 6661,
Year Deficiency I.R.C. 1954 I.R.C. 1954 I.R.C. 1954
1982 $24,171.39 $1,208.57 (1) $2,417.14
1 50 percent of the interest due on $30,160.83 and $24,171.39 for 1981 and 1982, respectively.
The parties have settled all issues except one. The only issue remaining for decision is whether a cash payment in the amount of $36,345.17 received by petitioner Sheldon S. Watnick in 1982 for the assignment of an interest in an oil and gas lease to Exxon Co., U.S.A., should be treated as ordinary income subject to depletion or as a long-term capital gain.
FINDINGS OF FACT
Petitioners were all residents of Michigan at the time the petition was filed.
During 1979, 1980, 1981, and 1982, petitioner Sheldon S. Watnick (petitioner) participated in a program offered by Melbourne Concept, Inc. (Melbourne). The objective of this program was to acquire leases for oil and gas exploration and development through a noncompetitive, simultaneous filing system and an over-the-counter filing procedure, both conducted by the Bureau of Land Management (BLM) of the U.S. Department of the Interior. The lands leased under this lottery program were not within any known geologic structure of a producing oil or gas field. 30 U.S.C. sec. 226(c) (1982).
In the lottery program, petitioner acquired Mineral Lease W-72892 (sometimes hereinafter the lease), effective September 16, 1981, covering 311.53 acres in Uinta County, Wyoming. The lease is located along the Darby Thrust within the general overthrust belt region of Southwest Wyoming and Utah. The cost to petitioner for the lease consisted of a nominal filing fee and $1 per acre for the first year delay rental.
After winning the lottery, petitioner received oral and written inquiries from potential purchasers of the lease, including Marathon Oil Co.; Exxon Co., U.S.A. (hereinafter Exxon); Conoco, Inc.; and J.R. Holcomb Associates, Inc. The majority of these letters were form letters.
Petitioner hired Frank W. Brown, a consulting landman, by a verbal agreement to handle the negotiations for the assignment of Lease W-72892. In an attempt to sell the lease at the highest price and best terms, Mr. Brown contacted various oil companies soliciting offers in a bidding-type process. At this point, Harold Drange, an executive in the upper management of Exxon, contacted Mr. Brown regarding the lease. Mr. Drange told Mr. Brown that Exxon would be willing to meet or better any other offers.
On January 16, 1981, petitioner signed a letter agreement to assign Lease W-72892 to Exxon for cash consideration of $54,517.75, reserving a production payment of $10,000 per acre out of 5 percent of all production from the leased lands.
On November 1, 1981, petitioner assigned a one-third interest in Lease W-72892 to Melbourne. On October 3, 1982, petitioner and Melbourne, for a cash consideration of $54,518, assigned 100 percent of Lease W-72892 to Exxon, excepting and reserving a production payment of $10,000 per acre to be paid out of 5 percent of eight-eights of the market value of all oil and gas which may be produced, saved, and marketed from the lands. In this respect the assignment provided:
Assignor hereby excepts and reserves an obligation equal to $10,000 per acre for the number of acres assigned hereby, the same to be paid out of 5 percent of 8/8ths of the market value at the wells, as produced, of all the oil and gas which may be produced, saved and marketed from the above described lands under the terms of said lease or any extensions or renewals thereof. All payments made on account of said obligation shall be computed and paid at the same time and in the same manner as royalties payable to the Lessor under the terms of said lease are computed and paid. Except as specifically herein provided, this reservation of said obligation shall not imply any leasehold preservation, drilling or development obligation on the part of the Assignee; however, nothing herein contained shall relieve Assignee from compliance with any of the terms and conditions of said lease. * * *
The total reservation amounts to $3,115,300 ($10,000 X 311.53). The oil and/or gas reserve in the 311.53 acres subject to Lease W-72892 would have to produce $62,306,000 worth of oil and/or gas in order to pay off the $10,000 per acre obligation to petitioner and Melbourne.
At the time of the assignment, there was no commercial production anywhere along the Darby Thrust in the area of petitioner’s lease. The drilling of three wells on property adjacent to the lease, immediately to the north and the south, yielded dry holes. In 1981, the only production along the Darby Thrust was at the north end in the LaBarge area along the Moxa Arch. The LaBarge production is approximately 90 miles north of the lease and is not considered thrust belt production.
The closest production, which was at Spring Valley and Sulphur Creek, west and southwest of the lease, was from shallow formations. These leases were not considered thrust belt production and recognition of potential production from them would not contribute meaningfully to a determination of the potential productivity of Lease W-72892.
There are a number of producing fields to the west of petitioner’s lease. These include the Pineview, Painter Reservoir, Painter Reservoir East, Clear Creek, and Ryck-man Creek oil fields as well as eight gas fields, the largest being the Whitney Canyon-Carter Creek field. All of these fields produce from reservoirs in the Absaroka and Tunp Thrusts. These fields are considerable distances from petitioner’s lease. The record does not show the exact distance.
Petitioner’s expert, Frank W. Brown, referred to above, a consulting landman and partner in Brown & Hagemeier Oil Properties (B & H), assisted petitioner in the negotiation of the assignment of the lease to Exxon. Mr. Brown has recently retired from Gulf Oil Corp. (Gulf) in Casper, Wyoming, where he was land manager for the Rocky Mountain District. He has more than 30 years of experience in the Rocky Mountain area. His last position with Gulf included supervision of 25 landmen, management of 5 million acres of fee, State, and Federal leases, and responsibility for an annual lease purchase budget of more than $20 million. Mr. Brown is a certified professional landman qualified through the American Association of Petroleum Landmen and is also a past president of the Wyoming Landmen Association.
Marvin E. Hagemeier, Mr. Brown’s partner, collaborated with Mr. Brown on the preparation of petitioner’s expert report. Prior to his partnership with Mr. Brown, Mr. Hagemeier had worked for approximately 30 years for Gulf in various positions both in this country and abroad. His last position with Gulf was as “Manager-Williston Area.” He was responsible for the evaluation of a lease inventory of approximately 2.5 million acres and supervision of a professional staff of 32 geologists and geophysicists.
B & H has on only two occasions given opinions or appraisals concerning the value of a lease and the length of the payout period. One such occasion involved petitioner.
Petitioner’s expert report prepared by Mr. Hagemeier concluded that there was a reasonable prospect that Lease W-72892 would produce $10,000 per acre out of 5 percent of the production during its economic life. This conclusion was based primarily on information in regard to the potential reserves underlying the five oil and gas fields, referred to above, in a geologic formation similar to, but a considerable distance from that of Lease W-72892.
Respondent’s expert, Jeffrey Lambert, obtained an undergraduate degree in petroleum engineering from New Mexico Institute of Mining and Technology in 1983 and a master’s degree in mineral economics from Colorado School of Mines in 1986. Mr. Lambert has been a petroleum engineer with the Internal Revenue Service in Denver since 1984. His responsibilities include valuations of producing and nonproducing oil and gas properties, analyzing the economic feasibility of production operations, estimating reserves, determining goodwill, and providing reports on these subjects. Mr. Lambert spends approximately 75. percent of his time in production and reservoir engineering and 25 percent of his time interpreting the Internal Revenue Code.
In arriving at his opinion on the production potential of Lease W-72892, Mr. Lambert located the property on a base map of the area and examined records on file for three dry holes drilled on properties adjacent to the lease. The records indicate which formations were penetrated and indicate the type of subsurface geology to the depths drilled. His research showed that the five fields used in petitioner’s report as analogies to Lease W-72892 all produce from the Nugget formation. Mr. Lambert’s research also showed that the Nugget formation either was not present or was not shown to be productive in the overthrust plate of the Darby Thrust.
Because of the lack of any other geologic information or known hydrocarbon traps underlying the lease, Mr. Lambert expressed the view that an appropriate analogy for estimating the potential reserves underlying petitioner’s lease cannot be found. Mr. Lambert concluded that there was no reasonable prospect or expectation that Lease W-72892 would pay off the reserved $10,000 per acre out of 5 percent of any production from the lease during its economic life.
Petitioner reported the cash payment received on the assignment of Lease W-72892 on his income tax return for 1982 as a long-term capital gain. The notice of deficiency treated the assignment as a sublease rather than a sale and determined that the cash payment was an advance royalty rather than capital gain.
OPINION
This controversy relates only to the cash payment of $36,345.17 received by petitioner for the assignment of his interest in Lease W-72892. The issue for decision is whether this payment should be taxed as ordinary income subject to depletion or as long-term capital gain. In order to decide this issue, we must determine what type of interest petitioner reserved under his lease assignment.
Respondent contends that the reservation under the lease assignment was in substance an overriding royalty, and, consequently, the cash payment received by petitioner should be treated as an advance royalty and taxed as ordinary income subject to depletion. Petitioner argues that the reservation was a production payment or oil payment, and that the cash payment should be taxed as long-term capital gain.
In weighing these arguments, the difference between an overriding royalty interest and a production or oil payment must be borne in mind. A royalty interest is defined as “a right to receive a specified percentage of all oil and gas produced during the term of the lease,” i.e., during the entire term of the lease. Anderson v. Helvering, 310 U.S. 404, 409 (1940). “An overriding royalty is similar to a royalty in that, for Federal tax purposes, each is a right to minerals in place that entitles its owner to a specified fraction of production, in kind or in value, and neither is burdened with the costs of development or operation. They differ in that an overriding royalty is created from the operating interest, and its term is co-extensive with that of the operating interest from which it is created.” C. Russell & R. Bowhay, Income Taxation of Natural Resources, sec. 2.05 (1988). A production payment is, in general terms, “a right to a specified share of the production from mineral in place (if, as, and when produced), or the proceeds from such production.” Sec. 1.636-3(a)(1), Income Tax Regs.; Commissioner v. P.G. Lake, Inc., 356 U.S. 260, 261 n. 1 (1958). A production payment right may be cast in terms of a specified quantity of oil or gas or a sum of money payable out of a stated percentage of the mineral if, as, and when produced. Anderson v. Helvering, supra at 410.
If an oil and gas lease is transferred and the transferor receives a cash payment plus an overriding royalty interest, the transferor has retained an economic interest in the oil and gas in place which will be depleted by production. The transaction is not a sale because the transferor will participate in production during the entire life of the lease. The transaction is treated as a sublease, and the cash payment is an advance royalty taxable as ordinary income subject to the depletion allowance.
The bonus received by the Smitherman partnership was a return pro tanto of the petitioner’s capital investment in the oil, in anticipation of its extraction, resulting in a corresponding diminution in the unit depletion allowance upon the royalty oil as produced. * * * [Citation omitted.]
See also Burnet v. Harmel, 287 U.S. 103, 111-112 (1932); Murphy Oil Co. v. Burnet, 287 U.S. 299, 302 (1932).
A production payment retained on the execution or assignment of a lease, like an overriding royalty interest, is also an economic interest in oil and gas in place and receipts from production are taxed as ordinary income subject to depletion. Thomas v. Perkins, 301 U.S. 655, 659 (1937); Lee v. Commissioner, 126 F.2d 825, 826 (5th Cir. 1942), affg. 42 B.T.A. 1217, 1228 (1940); see also Anderson v. Helvering, supra at 409-411. Nonetheless, when only an oil payment is retained upon the transfer of a mineral lease, any cash payment received along with the production payment, as a general rule, is treated as arising from a sale rather than a sublease. The transaction as a whole is a sale except for that part of the production necessary to satisfy the oil payment; as to that part, it is in “effect an exception or reservation of oil.” Commissioner v. Fleming, 82 F.2d 324, 327 (5th Cir. 1936), affg. 31 B.T.A. 623 (1934); see also United States v. Witte, 306 F.2d 81 (5th Cir. 1962). In Hammonds v. Commissioner, 106 F.2d 420, 425 (10th Cir. 1939), revg. and remanding 38 B.T.A. 4 (1938), where a lease was sold for cash and an oil payment was retained, the court explained:
The cash consideration was not in tbe nature of a bonus or advance royalty. Rather, it was a part payment for the interest sold and assigned. The sole economic interest reserved by petitioner was in the oil runs to the extent of the consideration to be paid out of such runs. * * *
The cash received is attributed to the portion of the lease that is sold or assigned and, if all other requirements are met, may be taxed as capital gain.
In the instant case, under the foregoing principles, petitioner’s assignment of his lease to Exxon, in form, was made for cash and an oil payment right. The assignment states that it—
excepts and reserves an obligation equal to $10,000 per acre for the number of acres assigned hereby, the same to be paid out of 5 percent of 8/8ths of the market value at the wells, as produced, of all the oil and gas which may be produced, saved and marketed from the * * * described lands under the terms of said lease or any extensions or renewals thereof. * * *
If this language is controlling, petitioner is entitled to prevail. The cash he received in the sale would be payment for the interest in the lease which he sold and assigned. Any payments he may receive pursuant to the oil payment he reserved (did not sell or assign) would be ordinary income subject to the depletion allowance.
Respondent contends, however, that in order to pay off the $10,000 per acre oil payment, the lease would have to produce in excess of $62,306,000 worth of oil and gas and argues that the evidence does not show there was any reasonable prospect that it will produce that amount or that petitioner expected it to do so. Because the lease had no reasonable prospect of producing that much oil, the argument goes, the purported oil payment retained by petitioner was, in substance, a retained overriding royalty interest which entitles petitioner and Melbourne to receive 5 percent of the market value of any oil or gas produced and marketed during the entire economic life of the lease. It thus has the characteristics of an overriding royalty. Accordingly, respondent maintains that, consistent with the principles of Palmer v. Bender, supra, and its progeny, the cash received on the execution of the lease is taxable as advance royalty, i.e., ordinary income subject to an allowance for depletion rather than as capital gain. We agree.
In United States v. Morgan, 321 F.2d 781 (5th Cir. 1963), the court was faced with a similar contention. In that case, the taxpayer acquired an oil and gas lease and assigned it for a cash payment of $71,400 plus a purported oil payment of $10 million payable out of one-sixteenth of all oil, gas, and other minerals as, if, and when produced, saved, and marketed. At the time of the sale, the lease was wildcat, the nearest production being 2 miles away from the taxpayer’s lease. On the taxpayer’s motion for summary judgment, the District Court, looking to the form of the assignment, granted the motion because the payments were to be “made from a particular source if, as, and when produced and until a given amount is realized.” 321 F.2d at 785. Citing United States v. Wheeler, 311 F.2d 60, 63 (5th Cir. 1962); Weinert’s Estate v. Commissioner, 294 F.2d 750, 755 (5th Cir. 1961), revg. and remanding 31 T.C. 918 (1959); and Commissioner v. Southwest Exploration Co., 350 U.S. 308, 315 (1956), the Court of Appeals reasoned that the tax laws deal with economic realities, not legal abstractions, and remanded the case for factual findings on two issues (321 F.2d at 786):
(1) could ordinarily prudent persons dealing in mineral lands or mineral leases, with knowledge of all facts then generally known or ascertainable upon reasonable inquiry pertaining to the lands and lease here involved, have reasonably expected, on or about July 24, 1954, that the alleged oil payment then reserved by taxpayer upon the alleged assignment by him of the mineral lease to E. A. Vaughey, would be paid out before the expiration of the lease and (2) did J. A. Morgan then so expect? We think if both of those questions be answered in the affirmative, taxpayer’s reservation was an oil payment, but that if either of those questions be answered in the negative, taxpayer’s reservation was a royalty and not an oil payment. * * * [3 ]
In resolving those factual issues, the District Court was directed to consider all economic and geologic facts pertaining to the oil reserve and lease including the fact that “the oil reserve in the 357 acres subject to the lease would have to produce in excess of $80,000,000 worth of oil and gas in order for the alleged oil payment to be paid out before the expiration of the lease.” 321 F.2d at 786.
We think the rule of United States v. Morgan, supra, is controlling here. We must, therefore, find from the evidence before us whether there was a reasonable prospect that the reserved $10,000 per acre purported oil payment from 5 percent of the production from the lease would be paid off during its economic life and whether petitioner so expected. A negative answer to either one of these questions requires a holding for respondent. The burden of proof rests with petitioner. Welch v. Helvering, 290 U.S. 111 (1933).
For the oil payment to be discharged, Lease W-72892, as indicated in our findings, would have to produce $62,306,000 worth of oil and gas. According to petitioner’s expert, the applicable spacing limitations would have permitted only one well on the property; depending on a variety of circumstances, permission for one additional well might have been obtainable after a producer was drilled. We must, therefore, seek to determine the reasonable prospects of recovering the $62,306,000 from one, possibly two, wells which might or might not be drilled on the lease, and, if drilled, might or might not be productive.
The record before us on the prospects in October 1982 of production from Lease W-72892 is skimpy, imprecise, and largely conclusionary, with meager facts and reasoning to support many points. The record is abundantly clear, however, that the lease was wildcat. It is located in a geologic formation referred to as the Thrust Belt of Wyoming, Utah, and Idaho, and is part of the overthrust belt which extends from the Brooks Range in Alaska down through Mexico. The area in which Lease W-72892 is located is called the Darby Thrust.
In 1982, there were no producing wells along the Darby Thrust. There was production in “the area of LaBarge” and, in words adopted by petitioner’s expert, “that’s like a long ways away”; according to a map introduced in evidence, it was approximately 90 miles away. Even that production was on the Moxa Arch and was not “thrust belt production.”
Given these facts, the realistic probability in October 1982 that the lease would pay off petitioner’s reserved oil payment was extremely slight. First, the probability that a well would be drilled on the lease was meager. Drilling is undertaken on an extremely limited percentage of wildcat leases. That possibility is rendered even more remote by the fact that two dry holes had been drilled on the adjoining property to the south and another dry hole on the adjoining property to the north. One of these dry holes was drilled by Amoco to a depth of about 8,500 feet in 1978. All three of these dry holes, according to a map introduced in evidence, were within a short distance (a few hundred yards) of petitioner’s property. There is no evidence to indicate that any other drilling in the area of petitioner’s lease was planned or anticipated.
Second, if a well should be drilled, the possibility that production will be obtained is, again, remote; respondent’s expert testified that the ratio of producing wells to dry holes in the over-thrust belt was about 1 to 11. We find this testimony as it relates to Lease W-72892 entirely reasonable. Third, if production should be obtained, there would remain the serious question whether the one well (or possibly two) would produce the required $62,306,000. We are not satisfied that it would.
Respondent’s expert referred in his report and testimony to the court’s findings in Collums v. United States, 480 F. Supp. 864, 868 (D. Wyo. 1979). Based on expert testimony, the court in that case found that, in Wyoming and the Rocky Mountain States, the probability that a wildcat lease will be drilled is 1 in 50 and the probability of an exploratory well thereon being a producer is 1 in 10. Multiplying the probabilities of each of these events, the court found that the probability of a wildcat lease becoming a producer is about 1 out of 500. Although respondent’s expert acknowledged that he did not know the specific facts respecting the leases on which the testimony in the Collums case was based, he expressed the view that “the same conclusion should be appropriately applied here.” Petitioner offered no testimony on drilling experience showing that the drilling or success ratio on wildcat leases was, in fact, any more favorable than that adopted by respondent’s expert. Petitioner’s expert expressed the view that drilling in the Wyoming-Utah thrust area during 1975 through 1981 furnished information that would permit improvement of the ratio but that type of general information provides no real basis for evaluating the probabilities on this particular lease.
Petitioner’s expert does not rely upon the producing wells in the LaBarge area to support his conclusion. Instead, if we understand his report, he bases his opinion on estimated reserves underlying five fields which had been developed by 1982 in the thrust belt: Pineview, Ryckman Creek, Clear Creek, Painter Reservoir, and Painter Reservoir East. Assuming that the reserves per acre under petitioner’s lease are similar to the reserves in those producing fields, the report estimates the proceeds available for the discharge of petitioner’s oil payment under two scenarios:
I. 6,875 bbl/ac X 207.685 ac X 5% X $50/bbl = $3,569,500
II. 13,846 bbl/ac X 207.68 ac X 5% X $50/bbl = $7,188,843
The report further states these estimates “could justifiably be doubled” if the Department of Energy’s “projected average price of approximately $100 per barrel for the period 1985 to 1995 were used.”
We think petitioner’s estimates ignore the realities. The expert’s report assumes that, because production was obtained in the five listed fields, it will be obtained from petitioner’s lease. The report makes no allowance for the probabilities that a well will not be drilled on the lease; if drilled, it will be a dry hole; and, if a producer, it will not produce the requisite $62,306,000. The five oil fields listed in the report Eire miles away from petitioner’s lease. The record does not show the distance but it shows they are located between what are referred to as the Tunp and Absaroka Thrusts rather than on the Darby Thrust. We do not understand the expert to maintEiin that commercially producible oil underlays the entire thrust area. As we understand the evidence, it is that there is a likelihood that traps of oil and gas exist in various locations in the thrust belt area. The fact that production existed in the five producing fields cited by petitioner provides scant support, in our view, for a conclusion that production is obtainable from petitioner’s lease.
We conclude that petitioner has not shown there was a reasonable prospect, within the meaning of the tests set forth in United States v. Morgan, 321 F.2d 781, 786 (5th Cir. 1963), that the oil payment reserved by petitioner from Lease W-72892 would be paid off, or that petitioner had any reasonable basis for expecting that it would be. Accordingly, the cash which he received on the assignment of the lease to Exxon is taxable as an advance royalty subject to any allowable depletion.
In maintaining that he sold the lease to Exxon and is thus entitled to capital gain treatment of his receipts, petitioner further argues that he did not retain an economic interest in any underlying oil and gas in place and that the cash payment from Exxon was not, therefore, depletable income but was capital gain. He contends that this is so because, the argument goes, he did not look solely to the extraction of minerals for a return of capital under the test propounded by the Supreme Court in Palmer v. Bender, 287 U.S. 551, 555 (1933). He points out that his basis in the property was $10,918.79; that he received a payment of $54,517.75 for his interest in the lease; and that he has thus already recovered his capital investment. That argument misconceives the economic interest concept.
In his transaction with Exxon, petitioner fragmented his interest in the lease. He retained (did not sell) his right to receive $10,000 per acre payable out of 5 percent of the oil and gas produced and marketed from the lease; he sold only the balance of his interest.
An investment in minerals in place may be retained if it is represented by a portion of a previously owned economic interest. It is not necessary that the taxpayer incur a cost in the acquisition or retention of the investment, or that he have any tax basis in such investment. In fact, it is sufficient to show only that a clear capital interest exists, that the interest diminishes as the mineral is extracted, and that the taxpayer shares directly in the economic productivity of the minerals and market risk on their sale.
See Weaver v. Commissioner, 72 T.C. 594, 601-603 (1979). Based on the evidence before us, we have found that there was no reasonable prospect or expectation that the oil payment retained by petitioner will be paid off. It will extend throughout the economic life of the lease. It is therefore, in substance, an overriding royalty which qualifies as a retained economic interest in the minerals in place.
To reflect the foregoing,
Decision will be entered under Rule 155.
The record does not show precisely the distance between petitioner’s lease and the LaBarge production. However, respondent requested and petitioner did not object to the finding that it was 90 miles away. The finding is based on the calculation of the distance by reference to a scaled map which is in evidence.
The year before the Court (1982) ended before the effective date (Aug. 16, 1986) of sec. 613A(d)(5), as added by the Tax Reform Act of 1986, 100 Stat. 2227, which denies percentage depletion in respect of bonuses or advance royalties in the absence of actual production, reversing the rule of Commissioner v. Engle, 404 U.S. 206 (1984).
On remand, the District Court concluded in part (Morgan v. United States), 245 F. Supp. 388, 390 (S.D. Miss. 1964):
“It simply was not reasonable that on July 24, 1954, that anybody could have reasonably expected the sum of $10,000,000 to be paid before the expiration of the lease, and Morgan never actually expected it. So viewed, it is the inescapable conclusion as a matter of law that this income must be treated for tax purposes as an advancement to the taxpayer against an overriding royalty interest being paid by Vaughey to Morgan for said lease in 1954. * * *”
The Court of Appeals stated that it knew of no cases adopting the test it adopted but that textual commentary indicated that substantial consideration had been given to the problem, citing C. Breeding & A. Burton, Income Taxation of Oil and Gas Production, sec. 2.07 (1961); Appleman, Assignment of Mineral Interests and the Incidence of Income, 18th Ann. N.Y.U. Tax Inst., 507, 512 (1960); Note, 35 Tex. L. Rev. 459, 461 (1957).
Sec. 636, I.R.C. 1954, adopted as part of the Tax Reform Act of 1969, Pub. L. 91-172, 83 Stat. 631, prescribes rules for the tax treatment of carved out production payments and retained production payments on the sale and the lease of mineral property. Although the section does not change the rule for the taxation of production payments to lessors in leasing transactions (sec. 636(c), I.R.C. 1954), the regulations under the section, consistent with its legislative history, limit the term “production payment” to a right which has “an expected economic life (at the time of its creation) of shorter duration than the economic life of one or more of the mineral properties burdened thereby.” Secs. 1.636-2(a) and 1.636-3(a)(l), Income Tax Regs.; H. Rept. 91-413, 1969-3 C.B. 200, 203; S. Rept. 91-552, 1969-3 C.B. 423, 428. Although United States v. Morgan, 321 F.2d 781 (5th Cir. 1963), deals with the tax of a sublessor, the definition closely parallels the reasoning of that opinion.
This 207.68 acres represents petitioner’s two-thirds interest in the 311.53 acres covered by the lease.
Vague references were made throughout the testimony to Department of Energy oil price forecasts but no documentation was offered. We are aware that a 1980 Annual Report to Congress, vol. Ill, issued by the Department of Energy, forecast substantial oil price increases. By 1982, when petitioner’s lease was assigned, however, the price of crude oil had already started dropping. A report by the American Petroleum Institute entitled “Basic Petroleum Data Book, Petroleum Industry Statistics,” vol. VII, n. 3, sec. VI, table 8b (Sept. 1987), shows that the price of crude oil in Wyoming dropped from $32.30 per barrel in 1981 to $29.37 in 1982 and to $27.19 in 1983. The undisputed testimony is that business transactions in the oil industry at that time were carried out on the basis of current prices, not at prices forecast by the Department of Energy.
Petitioner makes much of the fact that Exxon paid $54,517.75 for the lease assignment and argues that Exxon must, therefore, have been convinced that oil would be discovered under the leased lands. The record, however, contains no information on the considerations prompting Exxon to acquire the lease. That Exxon was willing to pay $54,517.75 for an assignment of the lease provides little support for the conclusion that the lease would produce over $62 million worth of oil and gas.
A strict application of the tax laws would require an allocation of his basis in the lease between these two fragments. Columbia Oil & Gas Co. v. Commissioner, 118 F.2d 459, 461 (5th Cir. 1941).