Richard M. And Brenda R. Yates v. Commissioner of Internal Revenue

*969 BRORBY, Circuit Judge. Taxpayers appeal an adverse tax court decision. Taxpayers acquired three separate oil and gas leases of federal minerals through the federal oil and gas lottery. Their cost for each lease was a $10 filing fee and $1 per acre annual delay rental. These three leases covered acreage in North Dakota and in two Wyoming counties, Campbell and Converse. The North Dakota lease was acquired in 1975 and the two Wyoming leases were both acquired in 1977. Each of the three leases was assigned by a separate assignment to three different corporations that apparently were interested in exploring these lands for oil. The Campbell County acreage and the Converse County acreage were assigned in 1981 while the North Dakota acreage was assigned in 1982. At the time of the assignments the leases were undeveloped. Each of the three lease assignments reserved to the Taxpayers approximately a 5% overriding royalty. The language used in the assignments was essentially identical, which is as follows: Assignor hereby excepts and reserves an overriding royalty of [5%] of the proceeds received from the sale of all ... oil and gas which may be produced ... from said lands ... until such time as the then estimated recoverable reserves ... are 10% or less, whereupon said overriding royalty shall automatically terminate.... Production was subsequently obtained and Taxpayers contended their income should be classified as a production payment and thus would be entitled to capital gains treatment. The IRS contended the income to be royalty income and thus taxed as ordinary income, subject to depletion. The tax court, relying upon United States v. Morgan, 321 F.2d 781 (5th Cir.1963), and Watnick v. Commissioner, 90 T.C. 326 (1988), analyzed the question by inquiring: [WJhether 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 the extraction of 100 percent of the recoverable reserves, and whether petitioners so expected. Yates v. Commissioner, 92 T.C. 1215, 1226 (1989). The tax court then analyzed the evidence and concluded that at the time of the assignments the likelihood of commercial production was small. The tax court determined from Taxpayer’s own evidence that the prospects of productivity were one chance in five, and consequently it rendered its decision in favor of the IRS. Id. at 1229. Taxpayers assert the interests reserved are production payments and offer several arguments which we shall answer separately. The tax court made findings of fact that required determinations of weight and credibility. We may not set aside finding of fact made by the tax court unless such findings are clearly erroneous. 26 U.S.C. § 7482(a); Fed.R.Civ.P. 52(a); Dotese v. Commissioner, 811 F.2d 543, 546 (10th Cir.1987); Marathon Oil Co. v. Commissioner, 838 F.2d 1114, 1119 (10th Cir.1987). Findings of law and of ultimate fact from applying the legal principles to the facts are subject to de novo review. Pollei v. Commissioner, 877 F.2d 838, 839 (10th Cir.1989). There can be no doubt that Congress has allowed favorable tax treatment for income properly classified as a “production payment.” The Internal Revenue Code makes special provision for the treatment of income so classified. 1 Our first task is to define the term “production payment” for tax purposes. As the Code fails to define this term we turn to the definition contained in the applicable IRS regulation. 2 This regulation *970 uses a definition that was distilled from two older cases, namely, Thomas v. Perkins, 301 U.S. 655, 57 S.Ct. 911, 81 L.Ed. 1324 (1937), and Anderson v. Helvering, 310 U.S. 404, 60 S.Ct. 952, 84 L.Ed. 1277 (1940). This administrative definition of the term “production payment” does not answer all questions but from its plain language it can generally be said that to qualify income as a “production payment,” the income must derive from: (1) a right to a specific share of the production; (2) this right must have an expected economic life, at the time of its creation, of shorter duration than the economic life of the mineral property; (3) the right must be an economic interest in the mineral in place; (4) this right may only be satisfied by the production of the mineral; and (5) this right must be limited by either a dollar amount and a quantum of mineral or by a period of time. The parties agree, and we concur, that the resolution of this case involves only the second of the above listed requirements, which is “[s]uch right must have 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.” Treas.Reg. § 1.636-3(a)(l) (emphasis added). The plain language contained in this portion of the regulation establishes the parameters of our inquiry. By parsing the language contained in the regulation we find the first requirement which Taxpayers’ overriding royalty 3 must meet is that it must possess “an expected economic life.” The use of the word “expected,” in ordinary usage, connotes a likelihood or a probability of commercial production during the primary term of the lease. Websters II New Riverside University Dictionary 454 (1984). The use of the word “expected” as used in the regulation neither connotes nor means a mere possibility of production. Some reasonable degree of certainty, but less than absolute, is thus required. The regulation requires this expectation to exist and be measured at the time of its creation which, in the instant case, would mean at the time each lease was assigned as this was the time when the overriding royalty was created. Having defined the focus of this step of the inquiry, i.e., was there a reasonable likelihood of commercial production being obtained from each lease, we now turn to the standard applied by the tax court: 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. Yates, 92 T.C. at 1226. For the -sake of simplicity, we restate the standard in language employed by the Fifth Circuit in Morgan: could ordinarily prudent persons dealing in mineral lands or mineral leases, with knowledge of all facts then generally known or ascertainable upon reasonable *971 inquiry pertaining to the lands and lease here involved, have reasonably expected, on [the date of each lease assignment], that the alleged oil payment then reserved by taxpayer ... would be paid out before the expiration of the lease and (2) did [taxpayer] then so expect? 4 United States v. Morgan, 321 F.2d 781, 786 (5th Cir.1963). The plain language of the regulation requires the adoption of this standard. We hold the tax court adopted and utilized the correct legal standard in deciding this case. Our conclusion is bolstered by the fact that other courts have reached a similar result. See United States v. Foster, 324 F.2d 702, 707-08 (5th Cir.1963); Morgan, 321 F.2d at 786. Having discussed the general principles guiding our review, we now examine the evidence before the tax court. 5 At the time of acquisition, none of the three leases was located within any geologic structure and at the time of assignment, none of the three leases was developed, none had been drilled, and none was producing. Yates, 92 T.C. at 1216-20. It serves little purpose to detail the evidence as much was conflicting opinion evidence. The evidence may be summarized by stating that each of the three leases presented a reasonable prospect for exploration and drilling, but the likelihood of obtaining commercial production on any of the three leases was small. Id. at 1229. The expert witnesses for the IRS testified that the chances of obtaining production were anywhere from 1 out of 25 to 1 out of 120. This conclusion was, in essence, the tax court's conclusion and the evidence is more than sufficient to support this conclusion. The tax court noted “the evidence most favorable to [Taxpayers], although far from persuasive, suggests that the prospects of productivity were one chance in five.” Id. at 1229. As there exists substantial evidence to support the tax court’s decision, we cannot overturn its factual conclusions. Dolese, 811 F.2d at 546; Marathon Oil, 838 F.2d at 1119. Taxpayers argue the tax court failed to consider the impact of nearby wells and further failed to consider the impact that the assignees paid to Taxpayers 10,000 to 60,000 times the Taxpayers’ cost of lease acquisition. These facts were considered by the tax court who found that they were not determinative and noted there existed evidence tending to show the proximity of nearby production was not significant. For example, the North Dakota lease was offset by a well which was completed at about the time of the assignment; however, Taxpayers ignore the existence of two dry wells within three-quarters of a mile and the opinion of Taxpayers’ assignee that there existed a ten percent probability of production being obtained upon the North Dakota lease. The same is true of the Campbell County lease. A well to the Min-nelusa formation had been completed within approximately three-quarters of a mile (Taxpayers inform us this well was within 1,106 yards). Again, Taxpayers ignore the fact that this Minnelusa well was the only well producing from this formation within twenty miles. The fact that Taxpayers received many multiples of its acquisition cost is not persuasive for two reasons: First, as Taxpayers note, the oil business was booming in the early 1980s; presumably this was not the case when the leases were acquired; in short, conditions may change. Second, the fact that a knowledgeable oil and gas producer believes that certain acreage is a good prospect for drilling simply does not mean that there exists a likelihood of commercial production being obtained. When undeveloped oil and gas property is evaluated to determine the likelihood of future production, all relevant circumstances must be examined. Relevant *972 circumstances would include numerous factors such as available geologic and seismic information; the cost of lease acquisition; the costs of exploring, drilling and producing; the price of oil and the price of its treatment and transportation costs; the probable pay-out; the prices received by the taxpayer; the proximity of production as well as many other factors. It would be a rare case if any one or two of these factors were alone controlling. Taxpayers argue that if the tax court’s decision were upheld the result would be a de facto rule that no production payment can ever be created out of non-producing property. This is simply not the case, nor do we so hold. There can be little doubt that a taxpayer who attempts to create a “production payment” from non-developed property bears a difficult burden of persuasion; however, it is not an impossible burden. The significant issue remains the same, i.e., whether there exists a reasonable likelihood of production on the lease assigned as of the date the production payment is being reserved. As we have explained, as used in the regulation the plain meaning of the word “expectation” includes the element of likelihood or probability. Oil and gas developers are “world class” optimists and the fact they may regard a slight chance of production being obtained as a “reasonable expectation” does not make it so. Having determined that the tax court applied the proper law and that the tax court’s findings of fact are not clearly erroneous, we AFFIRM the decision. Footnotes [1] See 26 U.S.C. § 636. Section 636 was enacted as part of the Tax Reform Act of 1969. See Pub.L. No. 91-172, tit. V, § 503(a), 83 Stat. 487, 630-31 (1969). [2] Treas.Reg. § 1.636 — 3(a)(1) (1973) which reads as follows: (a) Production payment. (1) The term "production payment” means, in general, a right to a specific share of the production *970 from mineral in place (if, as, and when produced), or the proceeds from such production. Such right must be an economic interest in such mineral in place. It may burden more than one mineral property, and the burdened mineral property need not be an operating mineral interest. Such right must have 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 right to mineral in place which can be required to be satisfied by other than the production of mineral from the burdened mineral property is not an economic interest in mineral in place. 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. The term "production payment” includes payments which are commonly referred to as “in-oil payments”, "gas payments” or “mineral payments". [3] The fact that Taxpayers, their assignees, title examiner, and crude purchasers have correctly labeled this interest as a royalty interest does not necessarily make it a royalty interest for tax purposes. The only requirement expressed in the regulation is that the interest must be a "right.” Treas.Reg. § 1.636-3(a)(l). [4] The tax court also asked the question concerning the Taxpayers expectations. Yates, 92 T.C. at 1226. In the instant case it is clear and uncontroverted that Taxpayers possessed such expectation. These facts make any further discussion of this requirement unnecessary. [5] Unless otherwise stated, all evidence pertains to the conditions existing at the time of each lease assignment.