104 Oil & Gas Rep. 651 | Tax Ct. | 1989
Lead Opinion
Respondent determined deficiencies of $131,475 and $52,497 in petitioners’ Federal income tax for 1981 and 1982, respectively. The sole issue for decision is whether cash payments received by petitioners in 1981 and 1982 for the transfer of interests in oil and gas leases should be treated as ordinary income subject to depletion or as long-term capital gains.
Unless otherwise indicated, all Rule references are to the Tax Court Rules of Practice and Procedure, and all section references are to the Internal Revenue Code, as amended and in effect for the years in issue.
FINDINGS OF FACT
Some of the facts have been stipulated. The facts set forth in the stipulations are incorporated in our findings by this reference. Richard M. and Brenda R. Yates resided in Santa Fe, New Mexico, at the time they filed their petition.
Lease Transactions
Although petitioner Richard M. Yates is an architect, members of his family are in the oil and gas business and own Yates Drilling Co. and Yates Petroleum Corp. During the 1970s, petitioners participated in a Federal noncompetitive lottery of oil and gas leases conducted by the Bureau of Land Management (BLM) of the U.S. Department of the Interior.
Pursuant to a verbal agreement, petitioners were represented by Jack McCaw (McCaw), an experienced landman and manager of the land department at Yates Petroleum Corp., in entering into the transactions in issue. When acting on behalf of Yates Petroleum Corp., McCaw filed for all available leases in “oil country.” When acting on behalf of petitioners, however, McCaw filed only for those leases that he deemed the “best” available and filed only on leases that had been held for 10 years or longer by a major oil company.
Under the Federal lottery system, petitioners were awarded three oil and gas leases, as follows:
BLM lease No. Lease date Tract covered by lease Location of property covered by lease
M31845 (ND) 8/01/75 554.39 acres Golden Valley County, North Dakota
W59609 8/01/77 2,060.98 acres Campbell County, Wyoming
W59617 8/01/77 1,120.00 acres Converse County, Wyoming
The lands leased under the Federal lottery system were not within any known geologic structure of a producing oil or gas field. 30 U.S.C. sec. 226(c) (1982). Petitioners’ cost for these leases consisted of a $10 filing fee and $1 per acre annual delay rental.
Oil and gas activity in the Northern Rockies during 1981 and 1982 was at unprecedented high levels. Areas of particularly high activity included the Powder River Basin. Both Campbell County, Wyoming, and Converse County, Wyoming, are located in the Powder River Basin.
After winning these leases in the lottery, petitioners received oral and written inquiries from potential purchasers. When petitioners received offers to acquire any of their leases, they would forward the offers to McCaw for his review and recommendations. Before beginning negotiations to transfer the leases, McCaw would review numerous factors, including: the total lease acreage, the lease termination date, the lease rental payments, the number of Federal lottery filings previously submitted for the lease, dry hole maps, the ownership of adjoining acreage, well completion cards listing the depth and production of wells in the area, and daily petroleum information bulletins listing the location of every drilling well in the Rocky Mountains. Based on these factors, McCaw determined a price that he thought was reasonable and transferred the lease for that price.
During 1981 and 1982, petitioners assigned 100 percent of the Converse County and Golden Valley leases and 50 percent of the Campbell County lease, subject to retained interests in production proceeds, as described below. Petitioners received cash payments for the lease assignments, as follows:
BLM lease No. Date of transfer Transferee Cash payment
W59617 Converse Co. 4/16/81 Davis Oil Co. (Davis) $112,000
W59609 Campbell Co. 9/24/81 Lear Petroleum Exploration (Lear) 309,147
M31845 (ND) Golden Valley 3/08/82 Anadarko Production Co. (Anadarko) 250,000
McCaw recommended that petitioners retain a limited interest in the lease properties in order to participate in any future revenues that might come out of oil or gas production. In order to qualify the transactions for capital gains treatment on the cash payments received at the time of the assignments, McCaw intended that the retained interests would terminate when 90 percent of the oil or gas had been produced.
On McCaw’s recommendation, petitioners retained interests in the proceeds received from the sale of the oil and gas that might be produced from the properties subject to the leases, as follows: Converse County, 5 percent; Campbell County, 7.5 percent; and Golden Valley, 6.25 percent.
The language contained in the assignments of the three leases was identical in all material respects. To reflect petitioners’ retained interest, the assignment of the Converse County, Wyoming, lease contained the following language:
Assignor hereby excepts and reserves an overriding royalty of 5% of the proceeds received from the sale of all (8/8ths) of the oil and gas which may be produced, saved and marketed from said lands under the terms of the lease or any extensions or renewals thereof, until such time as the then estimated recoverable reserves in any producible formation in any well drilled on said lands are 10% or less, whereupon said overriding royalty shall automatically terminate only with respect to said formation, but said overriding royalty shall continue as a burden on all other formations underlying said lands. Upon termination of this overriding royalty with respect to any formation, Assignor shall execute and deliver unto Assignee a recordable reassignment of the overriding royalty with respect to the formation in which the then estimated recoverable reserves are 10% or less. “Recoverable Reserves” is defined as the unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
The determination of Recoverable Reserves shall initially be made by a “Qualified Engineer” (defined as a petroleum engineer, licensed or certified by the State of New Mexico, provided a person having a direct or indirect interest in the lease shall not be deemed a Qualified Engineer), selected by Assignee. If Assignor does not accept such determination, then, and within 60 days after receipt of such determination, Assignor shall cause a Qualified Engineer of Assignor’s selection to determine Recoverable Reserves and furnish such determination to Assignee. If Assignee does not accept such determination, then, and within 20 days after receipt of such determination, the two Qualified Engineers shall select a third Qualified Engineer, provided if such two Qualified Engineers are unable to agree upon a third Qualified Engineer, Assignor or Assignee may request the District Court to select a third Qualified Engineer. Within 30 days after the selection of such third Qualified Engineer, the three Qualified Engineers shall determine the Recoverable Reserves and the written determination of a majority of such three Qualified Engineers shall be conclusive and binding upon Assignor and Assignee. [Emphasis supplied.]
Under the terms of the transfer of the Campbell County lease to Lear, Lear was also obligated to drill one test well on the lease property within 6 months of the transfer date. The well was required to be drilled to a depth sufficient to test the Minnelusa Formation. McCaw believed that the reason Lear would agree to the drilling requirement in addition to the cash price it paid was because the property was a good prospect.
Prior to the time of the transfer of the Campbell County lease to Lear, McCaw knew that Lear had begun drilling a well approximately one-half mile from the lease property. In addition, at the time of the transfer, McCaw knew that Lear had completed this well on September 1, 1981, for approximately 400 barrels of oil per day. McCaw considered the completion of this well to be a significant discovery.
At the time of the transfer of the Golden Valley lease to Anadarko, McCaw knew that Anadarko was drilling an offsetting well to the depth of 10,000 to 12,000 feet at a cost of approximately $1 million. Based on seismic information, McCaw believed that the Golden Valley property was on the same field as the well that Anadarko was then drilling. McCaw believed that the reason Anadarko was willing to aUow petitioners to retain a limited interest in the lease, in addition to the substantial cash payment it paid to petitioners, was because the Golden Valley property was on the same field as the well Anadarko was drilling.
After studying maps, well completion cards, and petroleum information buUetins, McCaw believed that the Converse County lease property was located over an area that was potentially productive in five different zones. McCaw knew that the Spearhead field was located to the south of the Converse County lease property, and he believed that the lease property was on the same trend as that field.
Tax Treatment
The payor oil companies deducted as royalties the payments made to petitioners for their retained interests in the lease properties. On their 1981 and 1982 Federal income tax returns, however, petitioners reported the income from the transfers of their interests in these leases as long-term capital gain. Respondent determined that petitioners’ retained interests in the leases were overriding royalties rather than production payments as defined in section 636. Accordingly, respondent determined that the amounts received by petitioners in these transactions constituted ordinary income subject to depletion deductions.
OPINION
The issue for decision is whether the cash payments received by petitioners for their lease assignments or transfers should be taxed as ordinary income subject to depletion or as long-term capital gain.
In order to decide this issue we must determine the type of interest petitioners retained under the lease assignments or transfers. If petitioners’ retained interests are characterized as production payments, the transactions will be treated as sales. On the other hand, if petitioners’ retained interests are characterized as overriding royalties, the transactions will be taxed as subleases.
Petitioners argue that their retained interests under the leases were production payments as defined under section 636 and that the cash payments they received should be taxed as long-term capital gain. Respondent contends that petitioners’ retained interests under the leases were in substance overriding royalties. Consequently, respondent asserts that the cash payments petitioners received should be regarded as advance royalty payments and taxed as ordinary income subject to depletion.
Substance Over Form
In creating their retained interests in the leases, petitioners labeled those interests “overriding royalties.” Petitioners now argue, however, that their interests are in actuality production payments as defined by case law and by statute. Whether a retained interest is a production payment or an overriding royalty is not controlled by the label petitioners used, but rather depends upon the substance of the transaction. Commissioner v. P.G. Lake, Inc., 356 U.S. 260, 266-267 (1958); United States v. Morgan, 321 F.2d 781, 786 (5th Cir. 1963). Section 1.636-3(a)(2), Income Tax Regs., provides in part:
A right which is in substance economically equivalent to a production payment shall be treated as a production payment for purposes of section 636 and the regulations thereunder, regardless of the language used to describe such right, the method of creation of such right, or the form in which such right is cast (even though such form is that of an operating mineral interest). Whether or not a right is' in substance economically equivalent to a production payment shall be determined from all the facts and circumstances. * * *
Respondent agrees that the label petitioners used to describe their retained interests is not necessarily controlling. Respondent submits, however, that petitioners’ choice of the term “overriding royalty” rather than “production payment” is relevant in determining whether petitioners expected that their retained interests would be paid out before the expiration of the leases. In any event, petitioners have the burden of proving that respondent’s determination is erroneous. Doyal v. Commissioner, 616 F.2d 1191, 1192 (10th Cir. 1980); Rule 142(a). To satisfy that burden in this case, petitioners must establish that the form of their retained interests, i.e., insofar as they terminate, in effect, when 90 percent of the recoverable reserves have been reached, has substance and that the label put on those interests should be disregarded.
Definitions
In Anderson v. Helvering, 310 U.S. 404, 409 (1940), the Supreme Court defined a royalty interest as “a right to receive a specified percentage of all oil and gas produced during the term of the lease.” (Emphasis supplied.) A royalty interest lasts during the entire term of the lease. Under a royalty interest, cash paid to the lessor before production is regarded as an advance royalty and is taxed as ordinary income subject to depletion. United States v. Morgan, 321 F.2d 781, 783 (5th Cir. 1963). Where a mineral interest is assigned in return for a lump-sum cash bonus and the assignor retains a royalty interest, the transaction is a lease rather than a sale of capital assets, and the payments are taxable as ordinary income. Burnet v. Harmel, 287 U.S. 103, 107-108 (1932).
By contrast, the Supreme Court, in Anderson v. Helvering, 310 U.S. at 410, defined a production payment as “the right to a specified sum of money, payable out of a specified percentage of the oil, or the proceeds received from the sale of such oil, if, as and when produced.” (Emphasis supplied.) Where mineral rights are assigned for a cash consideration and no interest is reserved or the only interest reserved is a production payment, the transaction is a sale of a capital asset. Cash paid to the lessor in advance of production is regarded as a conversion of capital by sale and is taxed as long-term capital gain. United States v. Morgan, 321 F.2d at 783-784.
In United States v. Morgan, supra, the taxpayer acquired an oil and gas lease and assigned it for a cash payment of $71,400 plus an 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 leased property. 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. 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:
(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 that if both of those questions be answered in the affirmátive, 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. * * * [321 F.2d at 786.]
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 $80,000,000.00 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. On remand, the District Court concluded:
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. * * * [Morgan v. United States, 245 F. Supp. 388, 390 (S.D. Miss. 1964).]
The 2-part test established in United States v. Morgan, supra, has been characterized as having both an objective and a subjective part. The first part of the test asks whether, objectively, an ordinarily prudent person with knowledge of all relevant facts could reasonably expect payment before the expiration of the mineral lease. In contrast, the second part of the test asks whether petitioners subjectively so expected.
Following the rule established in United States v. Morgan, supra, section 636, adopted as part of the Tax Reform Act of 1969, Pub. L. 91-172, 83 Stat. 487, 1969-3 C.B. 10, 94, prescribes rules for the tax treatment of production payments on the sale of mineral property. The regulations under section 636 limit the term “production payment” to a right that 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. * * * A production payment may be limited by a dollar amount, a quantum of mineral, or a period of time. A right to mineral in place has an economic life of shorter duration than the economic life of a mineral property burdened thereby only if such right may not reasonably be expected to extend in substantial amounts over the entire productive life of such mineral property. * * * [Sec. 1.636-3(a)(l), Income Tax Regs.]
In Watnick v. Commissioner, 90 T.C. 326 (1988), the taxpayer acquired an oil and gas lease and assigned it for a cash payment, retaining a purported production payment of $10,000 per acre payable out of 5 percent of the production, if any, from the lease. This Court found that the realistic probability that the lease would produce the required $62,306,000 to pay off the taxpayer’s reserved oil payment was extremely slight. The only production in the area of the lease at the time of the transaction was approximately 90 miles away. The Court found that first, the probability that a well would be drilled on the lease was meager; second, if a well should be drilled, the possibility that production would be obtained was remote; and third, if production were obtained, the probability was slight that the well would produce the required $62,306,000. 90 T.C. at 337. Accordingly, the Court in Watnick held that a reasonable person could not have expected that the oil payment reserved by the taxpayer would be paid off, and that the taxpayer could not have had any reasonable basis for expecting that it would be. 90 T.C. at 339.
Petitioners argue that both Morgan and Watnick are factually distinguishable from the instant case. In both Morgan and Watnick, the payments reserved were of such high dollar amounts that the practical effect was to create an interest with a life that was coextensive with the life of the underlying lease, i.e., an overriding royalty. Petitioners argue that the factor that distinguishes this case from both Morgan and Watnick is the percentage limitation or “floor” on the interests retained.
In a footnote, the Court of Appeals in Morgan stated that substantial consideration had been given to the effect of the duration of a retained oil payment and quoted from Breeding & Burton, Income Taxation of Oil and Gas Production, section 2.07 (1961), as follows:
the Internal Revenue Service has acknowledged in private rulings that the possible classification of an oil payment as an overriding royalty because its life may be coextensive with the life of the property out of which it is payable can be successfully avoided by putting a ‘floor’ on the oil payment which would make it impossible for the economic interest to extend over the life of the property. For example, if the assignment creating the oil payment provided that the interest would be extinguished when the estimated economically recoverable reserves were reduced to a specified reasonable amount, the term of the oil payment would not be coextensive with the life of the property. * * * [United States v. Morgan, 321 F.2d at 787 n. 3]
Petitioners intended that the limitation in the assignments would insure that their retained interests would be of shorter durations than the underlying leases from which they were reserved (and thus, that they would qualify for capital gains treatment).
Respondent contends that petitioners have failed to satisfy their burden of proof because the difference between 90 percent and 100 percent, given the “wildcat” nature of the wells, is in all probability zero. Respondent argues that the most probable duration of production from an exploratory well is zero. Because there would be no expectation of production from the subject leases, the lives of the retained interests and the lives of the underlying mineral leases would be coextensive. This approach was suggested in Brountas v. Commissioner, 73 T.C. 491, 566 (1979), revd. on other grounds 692 F.2d 152, 161 (1st Cir. 1982), where the Tax Court suggested that respondent could have argued that the taxpayers’ retained interests were not production payments because the “most probable duration of production from an exploratory well is zero,” and thus the interests “did not have economic lives of shorter duration than the most likely productive life of the property.” Because respondent did not argue this issue in Brountas, the Tax Court stated “We note it here merely to clarify the fact that we have not decided it and that in a future case, the point remains open.” 73 T.C. at 566; 696 F.2d at 161.
Petitioners do not dispute the “wildcat” or exploratory nature of the wells. They cite United States v. Foster, 324 F.2d 702 (5th Cir. 1963), for the proposition that a production payment can be created from undeveloped property. The Court of Appeals in Foster held that a reasonable expectation that a specified sum will be paid out before the expiration of a lease can be formed even though the burdened property has not yet produced any minerals. 324 F.2d at 708. Although the burdened property in Foster was nonproducing, there was production on immediately adjoining property.
Respondent does not disagree with the proposition that a production payment can be created from undeveloped property. He argues that the facts of Foster are significantly distinguishable from the facts in the present case. Respondent points out that the taxpayer in Foster accepted a nominal cash bonus for the mineral lease when ordinarily the bonuses for similarly located leases would have been much more. Respondent also notes, as did the court in Foster, that:
Pay-out of an oil payment carved from producing property can be predicted with reasonable accuracy if it is not unreasonable to conclude that total reserves and the amount of production dedicated to pay-out are adequate for that purpose. For undeveloped property, however, an additional determination is necessary, i.e., that adequate pay-out production reasonably can be expected from the property. [United States v. Foster, 324 F.2d at 708. Fn. refs, omitted.]
We do not here adopt a per se rule that a production payment cannot be created from an exploratory or “wildcat” property. We must decide from the evidence before us whether there was a reasonable prospect that the retained share of proceeds from the oil produced from any of the subject properties, up to the time that 90 percent of the recoverable reserves had been extracted, would in substance be paid out prior to extraction of 100 percent of the recoverable reserves, and whether petitioners so expected. A negative answer to either of these questions defeats petitioners’ claims. See United States v. Morgan, 321 F.2d at 786; Watnick v. Commissioner, 90 T.C. at 336.
The Evidence
Petitioners argue that McCaw acted as their agent in the acquisition and subsequent disposition of the subject leases. McCaw was experienced and knowledgeable in oil and gas leasing in the Rocky Mountain area. McCaw testified that he expected the lease properties to be productive. He testified further that he advised petitioners to retain limited interests in the leases but to limit those interests to 90 percent of the oil to be recovered so that the transactions would be accorded capital gains treatment. McCaw did not, however, provide any objective evidence that the wells would be productive. While we have no reason to reject his testimony as to his subjective beliefs, or petitioner Richard M. Yates’ testimony that he relied on McCaw as an agent with respect to the transactions, this testimony does not constitute proof of the objective part of the Morgan test, i.e., that there be a reasonable expectation that the retained interests would be paid out before the expiration of the leases.
Petitioners ask us to take “judicial notice” of certain alleged characteristics of the assignees and assume that they would have paid such substantial cash sums only if they expected substantial production. No representative of the assignees was called at trial, and we refuse to draw any inferences about their motivations. The only evidence concerning their views was the evidence that each assignee treated the payments made to petitioners as overriding royalties.
Respondent’s expert witnesses, Jeffrey A. Lambert (Lambert), Forrest A. Garb (Garb), and Enrique Gonzalez-Gerth (Gonzalez-Gerth), evaluated the oil and gas leases at issue. For each of the subject leases, Lambert estimated there was a 1 in 20 probability that any wells would be drilled. In addition, he estimated there was a 1 in 6 probability that a well drilled on any of the leases would be productive. Finally, he estimated that there was a 1 in 120 probability that a producing well would be drilled on any of the leases. Lambert concluded, therefore, that the interests reserved by petitioners in each of the subject leases “could not have been reasonably expected, at the time of the transaction, to have an economic life substantially less than the entire productive life of the subject lease.”
Because the subject lease properties were undeveloped as of the transfer dates, respondent’s experts Garb and Gonzalez-Gerth also classified the leases as “wildcat” exploration properties. Based only on existing producing wells and dry holes at the transfer date, Garb and Gonzalez-Gerth estimated the probability for successful production as 10 percent for the Golden Valley and the Campbell County leases and 4 percent for the Converse County lease.
Petitioners failed to furnish expert witness reports to the Court or to respondent’s counsel within the time required by Rule 143(f) and the standing pre-trial order served with the notice of trial. Accordingly, the Court ruled that petitioners’ expert witnesses would be allowed to testify only in rebuttal of evidence presented by respondent’s expert witnesses. At the end of the trial, it did not appear that any expert testimony offered by petitioners and excluded would have supported a conclusion different than one based on the evidence that was received.
Petitioners’ expert witnesses, Roger D. Teselle (Teselle) and N. Raymond Lamb (Lamb), testified as rebuttal witnesses. Teselle believed that Lambert’s estimate of one producer out of six exploratory wells was a correct statistic for the Powder River Basin as a whole. Because the Powder River Basin covers a very large area, including parts of 7 different counties, Teselle believed that an overall ratio of 1 to 6 was not correct for evaluating the Campbell County and Converse County leases, which were in areas of higher than average productivity. In particular, Converse County had a higher than average production success ratio due to its “multiple pay zones.” Because one well can be drilled through four or five producing zones, the possibility of finding production in one or more of the zones is increased and the risk of drilling is decreased.
Petitioners’ experts also pointed out relevant information omitted by respondent’s experts. Specifically, respondent’s experts failed to consider how the recently drilled Lear well and the Lear drilling agreement would affect the probability that a producing well would be drilled on the Campbell County lease property.
The experts agreed that the productive life of a producing oil or gas property could actually be determined. Both respondent’s expert Gonzalez-Gerth and petitioners’ expert Lamb stated that a knowledgeable person with the necessary information as to production history could establish a decline curve and thereby determine the economic life of a producing property as well as determine when 90 percent of that productive life had been reached. There is no evidence, however, that an attempt was made to quantify the productive life of any of the properties in question at the time of the respective assignments. In any event, this formula alone does not satisfy petitioners’ obligation to show that the formula had substance.
Conclusion
Based on all of the evidence in the record, we cannot conclude that production was probable from any of the leases in question. The likelihood of productivity was small. The evidence most favorable to petitioners, although far from persuasive, suggests that the prospects of productivity were one chance in five. Such a chance may be worth speculation to those in the oil business, but it cannot fairly be characterized as an expectation that the difference between 100 percent and 90 percent of future production would be cognizable.
We agree with respondent that petitioners have not proven, in the words of Morgan, that ordinarily prudent persons dealing in mineral leases, with knowledge of all facts generally known or ascertainable upon reasonable inquiry pertaining to the lands and leases here involved, could have reasonably expected on the dates of assignment that the payments reserved by petitioners would be paid out before the expiration of the leases. Petitioners have not proven, in the words of section 1.636-3(a)(l), Income Tax Regs., that their rights may not reasonably be expected to extend in substantial amounts over the entire productive lives of the properties.
Thus they have not proven that the retained interests were, in substance, production payments. We must therefore sustain respondent’s determination that the retained interests were overriding royalties taxable as ordinary income subject to depletion.
Decision will be entered for the respondent.
