
    Paul P. BROUNTAS, et al., Petitioners, Appellees, v. COMMISSIONER OF INTERNAL REVENUE, Respondent, Appellant. Paul P. and Lynn T. BROUNTAS, Petitioners, Appellants, v. COMMISSIONER OF INTERNAL REVENUE, Respondent, Appellee.
    Nos. 81-1840, 81-1877.
    United States Court of Appeals, First Circuit.
    Argued June 4, 1982.
    Decided Sept. 28, 1982.
    
      George L. Hastings, Jr., Atty., Tax Div., Dept, of , Justice, Washington, D.C., with whom Glenn L. Archer, Jr., Asst. Atty. Gen., Michael L. Paup and Ann Belanger Durney, Attys., Tax Div., Dept, of Justice, Washington, D.C., were on brief, for C.I.R.
    Thomas B. Rutter, Philadelphia, Pa., for Paul P. Brountas, et al.
    Before CAMPBELL and BREYER, Circuit Judges, and PETTINE, Senior District Judge.
    
      
       Of the District of Rhode Island, sitting by designation.
    
   BREYER, Circuit Judge.

In this “tax shelter” case, we are asked to determine the propriety of certain deductions taken by a limited partner in an oil- and-gas drilling partnership. There is little question that subsequent changes in the law have made deductions similar to those at issue here improper for individual taxpayers. See 26 U.S.C. § 465 (Supp. IV 1980) (the “at risk” provisions). But, under the law as it stood when the deductions were taken, which is the law we must apply, the propriety of the deductions is a complicated and unsettled question. The Tax Court’s opinion from which this appeal was taken holds that the deductions were proper. See 73 T.C. 491 (1979). Yet, the Fifth Circuit, in a different case but on nearly identical facts, determined that they were not. Gibson Products Co. v. United States, 637 F.2d 1041 (5th Cir. 1981). Having reviewed both of these decisions, as well as the briefs filed and various cases and authorities, we find as did the Fifth Circuit (but for somewhat different reasons) that the deductions here were improper.

I

This case arises out of the activities of a Texas limited partnership known as “Coral I.” The partnership was organized in 1972, and was set up to explore and develop “oil and gas” property. The case involves two investors in Coral I. One is CRC Corp., which was both a limited and a general partner. The other is Paul Brountas, one of several limited partners in Coral I. Brountas contributed $10,000 in 1972 and $1,000 in 1973. He and his wife (who filed a joint return with her husband) filed a petition in the United States Tax Court contesting a notice of deficiency in their return for 1972. The Tax Court found in favor of the petitioners. The Commissioner has appealed. Brountas has also appealed from one part of the Tax Court’s decision. The appeals in this circuit concern Brountas and his wife but not CRC.

The Coral I partnership worked in essentially the following manner: At the outset, partners would contribute money (as Brountas did in the amount of $10,000). This money would then be used to buy participations in what looked like promising “oil and gas” ventures. These ventures were invariably set up by- CRC officials, and then sold in fractional interests to various CRC-managed partnerships (such as Coral I) and to CRC on its own account. In each case, a venture encompassed a package of several (typically three) oil and gas leasehold interests, or “prospects.” These prospects (leaseholds) were owned by an “operator” — an entrepreneur unrelated to CRC who wanted to develop the prospects but lacked the money to do so. The investors had the money at a time when it was apparently difficult to obtain in the oil and gas industry; they were in a position to strike advantageous bargains.

The bargains followed a uniform pattern. The operator would agree to convey to the investors a set of “oil and gas” leaseholds and would agree to drill a test well on each. The test well was often an expensive undertaking because CRC officials insisted that the operator agree to complete the well no matter how difficult this proved to be. In return, the investors agreed to pay the operator a “total” contract price. This price consisted of a “lease purchase price” and a “drilling contract price,” corresponding to the two parts of the operator’s agreement. Each of these component prices was apparently negotiated separately with the operator by someone on CRC’s behalf. The Tax Court found, and the government does not contest, that the two prices were each the result of arms-length bargaining and represented reasonable charges for the leaseholds and obligations in question.

The investors, however, did not pay the total price in cash. Rather, they paid the contract price with what the Tax Court found amounted to 40 percent in cash and 60 percent in a “nonrecourse” note. The “nonrecourse” note bore interest and was payable “on demand” after a certain time (usually about five years). It was “secured” by a percentage of oil and gas production from the underlying prospects, by a percentage of the leaseholds themselves, and by some of the equipment used. And, it provided that payment on the notes would be made out of production once production began. Despite these assurances, however, it was quite clear to all concerned that neither principal nor interest on a note would ever be paid if the prospects in a given venture all proved to be nonproducers. The investors were not personally liable on the notes; the operators could look to no property other than that securing the notes for payment; and all of that property would be essentially worthless if the wells proved to be dry. As a practical matter, the notes would be paid out of production or not paid at all.

The agreement between the investors and the operator provided the operator with one further potential source of compensation for drilling the test wells — a “development option." If a well proved successful, the agreement allowed the operator to gain an “equity” interest in its production by entering into a “completion joint venture” with the investors. To exercise this “development option,” the operator would have to agree to “complete” the test well to obtain production and to reimburse the investors for certain previous expenses. The operator and investors would then share all future costs and production in a specified ratio (subject to certain additional restrictions and conditions not relevant here).

The limited partners believed they had invested in a leveraged “tax shelter.” This type of shelter provides an investor with tax deductions greater in amount than the cash that he initially provides for the investment. These extra deductions can be subtracted from the investor’s ordinary income, thus “sheltering” some of his ordinary income from tax. Of course, these extra deductions may some day be offset when the investor must recognize “income” though he receives no payment. But this day of reckoning is in the future, and in the meantime the government has provided the investor at least with what is effectively an interest-free loan of the dollars that it otherwise would have taxed away. See Harrell & Stricoff, Overview of an Oil and Gas Tax Shelter, 28 Oil & Gas Tax Q. 496, 496 (1980).

We can illustrate how the promoters and investors thought this shelter would work by using the facts of this case in simplified form. Assume the operator conveys a package of- prospects to investors for $250,000 and agrees to drill test wells on each prospect for another $750,000. The investors, in turn, agree to pay the “total contract price” of $1,000,000 with $400,000 in cash and $600,000 in a nonrecourse note payable out of production and secured (as indicated above) by production, leaseholds, and equipment. The operator and the investors further agree to allocate $100,000 of the cash and $150,000 of the note to the “purchase price” of the prospects, and $300,000 of the cash and $450,000 of the note to the “drilling contract price.” In short, they agree that the same note/cash ratio as applies to the total price shall also apply to the two component prices. For simplicity, assume that there is only one investor, a partnership called Coral I, and that a (hypothetical) limited partner called Brountas has contributed cash equal to one percent, or $4,000, of the partnership’s initial cash capital. Assuming these numbers, Brountas’ argument amounts to a claim that he is entitled to deduct $7,500 as expenses. This figure— $7,500 — equals one percent (Brountas’ share) of the total “drilling contract” price.

Brountas’ argument begins with the fact that the cost of drilling an oil well is an immediately deductible expense. This is so because the Internal Revenue Code allows taxpayers (who make the proper election) to deduct all “intangible drilling and development costs” (or IDC’s) in the year incurred. 26 U.S.C. § 263(c) (Supp. IV 1980); Treas. Reg. § 1.612-4(a) (1965). The Code treats other expenses less favorably. The cost of machinery and equipment must be capitalized and depreciated. The cost of acquiring leaseholds is not immediately deductible, but instead becomes part of the investor’s tax “basis” and must be recovered gradually through the depletion allowance or on final disposition of the property as an offset against “amount realized.” But unlike these costs, the “intangible” costs of drilling and developing a well, such as “wages, fuel, repairs, hauling, supplies ... [and] the cost to [the investors here] of any drilling or development work ... done for them by contractors under any form of contract,” Treas. Reg. 1.612-4(a) (1965), are immediately deductible.

Brountas thus claims that the partnership incurred what (in our example) amounts to $750,000 in IDC’s in its first year. This expense consists of its payment to the operator (in return for a promise to drill) of $300,000 cash and $450,000 in nonrecourse notes. Brountas believes that the partnership, an accrual base taxpayer, can accrue as an expense in 1972 the future obligation to pay money that the notes represent. And, as a one percent partner, Brountas seeks to deduct one percent of the partnership’s total IDC expense, or $7,500.

Brountas is aware that he must first demonstrate that he has a “basis” in the partnership of at least $7,500. The Internal Revenue Code limits the share of partnership losses that a partner may deduct to the extent of the partner’s “basis” in the partnership. 26 U.S.C. § 704(d) (1976). This basis includes the money or other property that the partner has contributed to the partnership. 26 U.S.C. §§ 705 & 722 (1976). But, in our example, that amounted only to $4,000. How then can Brountas deduct $7,500? Brountas points to § 752(a), which states that “[a]ny increase in a partner’s share of the liabilities of a partnership ... shall be considered as a contribution of money .... ” The nonrecourse notes, he explains, are liabilities of the partnership. Hence, his basis increases by his share of the notes, or $6,000, and thus § 704 does not limit his right to deduct his proportionate share of the IDC expense.

The Commissioner of Internal Revenue disagrees with Brountas. His major point of disagreement concerns treatment of the nonrecourse notes. The Commissioner argues that the notes do not represent liabilities sufficiently certain and definite to warrant their accrual as IDC expenses of the partnership or to warrant counting them as a “liability” of the partnership for “basis” purposes under § 752(a). The Fifth Circuit essentially accepted the Commissioner’s views in Gibson, supra.

Brountas, the taxpayer, can prevail only if 1) his partnership basis increased sufficiently to allow him to deduct his full proportionate share of partnership expenses, and 2) the partnership’s accrual for tax purposes — and hence the partners’ deduction — of the total (cash plus noncash) “cost” of the drilling contract were proper. We shall address each of these issues in turn.

II

As previously mentioned, a partner’s basis in a partnership is defined to be the amount of money he contributes to the partnership. 26 U.S.C. §§ 705, 722 (1976). But since “[a]ny increase in a partner’s share of the liabilities of a partnership ... shall be considered as a contribution of money,” 26 U.S.C. § 752(a) (1976), it is clear that when the partnership itself incurs a liability, a partner’s basis ordinarily rises by his share of the liability. See generally 1 W. McKee, W. Nelson & R. Whitmire, Federal Taxation of Partnerships and Partners § 7.01[1] (1977). In an ordinary (i.e., non-limited) partnership with recourse indebtedness, partners are personally liable for partnership debts. For this reason, “the practice generally has been to treat the indebtedness of the partnership as the indebtedness of each member of the partnership according to his proportionate share of the debt. Theoretically, each partner (other than a limited partner) is liable for the entire partnership indebtedness. However, because of the right of contribution among the partners, the partners have been considered as economically burdened only with their share of the partnership debt. The share of partnership debt was treated under the 1939 Code as a contribution by the partners and included in the bases of their partnership interests. Section 752 of the 1954 Code, in substance, continues [this] practice.” 6 Mertens Law of Federal Income Taxation § 35.45 (1968); see 1 W. McKee, W. Nelson & R. Whitmire, supra, at § 8.01[1].

A limited partner, however, is liable for debts of the partnership only to the extent of the money he has contributed or is obligated to contribute. Thus, regulations provide that “a limited partner’s share of partnership liabilities shall not [in general] exceed the difference between his actual contribution ... and the total contribution which he is obligated to make .... ” Treas. Reg. § 1.752-l(e) (1956). But, where no partner is personally liable on a partnership liability (e.g., nonrecourse indebtedness), the regulations provide that “all partners, including limited partners, shall be considered as sharing such liability ... in the same proportion as they share the profits.” Id. The question before us here is whether the nonrecourse indebtedness in this case amounts to “liability” for purposes of § 752(a). We believe that it does not.

A

Were it not for a special “production payment” section of the Code, § 636, which we shall discuss in subpart B below, this question would not be difficult. The liabilities that investors typically are allowed to include in basis are relatively definite liabilities such as those upon which a lender might rely when he advances money to a borrower. In a typical loan transaction, a lender advances money or property only either when the borrower has personally promised to pay him back, or when there is adequate security to guarantee repayment, or both. Thus, the borrower does not take the loan into income, for it is offset by the obligation to repay. And, the amount of this obligation constitutes all or part of the borrower’s “basis” in the property to which the repayment obligation attaches. See generally Fiedler, Drilling Funds and Non-recourse Loans — Some Tax Questions, 24 Oil & Gas L. & Tax Inst. 527 (1973). As long as the obligation is secured by property of at least equivalent value, courts have been willing to treat even “nonrecourse” liabilities as sufficiently likely to be paid to warrant their inclusion in an investor’s basis. “[T]he reality [is] that an owner of property, mortgaged at a figure less than that at which the property will sell, must and will treat the conditions of the [nonrecourse] mortgage exactly as if they were his personal obligations.” Crane v. Commissioner, 331 U.S. 1, 14, 67 S.Ct. 1047, 1054, 91 L.Ed. 1301 (1947).

When, however, an obligation to pay is both nonrecourse and not secured by property of at least equivalent value, courts have been reluctant to consider it a liability that increases an investor’s basis. Thus, cases subsequent to Crane have found it proper to include nonrecourse debt in basis only insofar as the value of property securing the debt is equal to or greater than the face amount of the debt. See, e.g., Estate of Franklin v. Commissioner, 544 F.2d 1045, 1048-49 (9th Cir. 1976); Gibson Products Co. v. United States, 460 F.Supp. 1109, 1117-19 (N.D.Tex.1978), aff’d on other grounds, 637 F.2d 1041 (5th Cir. 1981); see also Rev.Rul. 77-110, 1977-1 C.B.58; Adams, Exploring the Outer Boundaries of the Crane Doctrine; An Imaginary Supreme Court Opinion, 21 Tax L.Rev. 159, 165-66 (1966); cf. Crane v. Commissioner, 331 U.S. at 14, n.37, 67 S.Ct. at 1054, n.37 (“if the value of the property is less than the amount of the mortgage, ... a different problem might be encountered”). A further line of decisions holds that highly contingent or speculative obligations are not includible in basis before the uncertainty surrounding them is resolved. Thus, in Lemery v. Commissioner, 52 T.C. 367, 377-78 (1969), aff’d on other grounds, 451 F.2d 173 (9th Cir. 1971), the court held that an obligation to pay part of the purchase price of a business out of “net profit” was too contingent to be included in the purchaser’s basis. Similarly, in Denver & Rio Grande Western Railroad Co. v. United States, 505 F.2d 1266, 1269-70 (Ct.Cl.1974), the court refused to allow the railroad taxpayer to include in its basis advances by a customer (used' to build a “spur line”) which were repayable only out of proceeds from shipping above a certain annual tonnage for ten years.

These decisions are consistent, for payment of a nonrecourse obligation is unlikely to be speculative to the extent that it is secured by property with a determinable value. Moreover, these decisions cannot be based upon a belief that the value of a nonrecourse note is limited to the value of the property that secures it, for a $1 million nonrecourse note secured by a $200,000 building is, other things being equal, considerably more valuable than a $200,000 note secured by the same building. (The note’s value will reflect the fact that the building’s value might rise, in which case the holder of the first note will receive more money than the holder of the second.) Therefore, these decisions must reflect an administrative fact — namely, the fact that it is simpler, when faced with obligations to pay that are highly uncertain, to wait and see if the contingency occurs. If it does not occur, the obligations need never enter basis, for they do not represent any obligation to pay. If it does occur, the extent of the monetary obligation will be reasonably capable of calculation, and any change in basis (where appropriate) can then be determined.

Given these cases and their apparent rationale, it is not surprising that the district court, facing this issue in Gibson Products Co. v. United States, 260 F.Supp. 1109, 1115-17 (N.D.Tex.1978), held that notes virtually identical to those at issue here were too contingent to be included in basis. Similarly, the Tax Court in the case at bar wrote that, leaving aside § 636 (the special section to be discussed in subpart B below), it is “highly doubtful that [the nonrecourse notes] ... or any similar nonrecourse highly contingent obligation would be a ‘liability’ for purposes of section 752(a) [governing basis in a partnership].” 73 T.C. at 559. The obligations here, unlike recourse notes, represented (as a practical matter) a promise to pay only if oil was found. They seem less like the repayment obligation that typically accompanies a recourse loan than like a device for sharing business risks — the risks that accompany oil explorations.

In sum, if these obligations are too contingent or speculative to warrant inclusion in an individual investor’s basis, we see no reason here why they should nonetheless count as basis increasing § 752 partnership “liabilities.” Rather, we believe the views of the Commissioner, the Tax Court, and the Gibson district court to the contrary are correct.

B

We now turn to the question of whether § 636 requires a different result. That section states in subsection (a) that a “production payment that is carved out of a mineral property shall be treated ... as if it were a purchase money mortgage loan and shall not qualify as an economic interest in the mineral property.” See also 26 U.S.C. § 636(b) (1976) (retained production payment). Brountas and the Tax Court reasoned as follows: 1) The nonrecourse obligations here amounted to “production payments.” 2) Under § 636 production payments are to be treated like “loans.” 3) True loans involve a lender who expects the borrower’s obligation to be paid and are typically treated as a liability that increases partnership basis. 4) Hence, the obligations here should be added to Brountas’ basis.

To understand the flaw in this reasoning, one must understand both what a production payment is and the purpose underlying § 636. Essentially, a production payment is a limited right to receive revenue from the production of mineral in place. The right may be limited by a dollar amount, by an amount of the mineral, and by a period of time. See Treas. Reg. 1.636-3(a)(1) (1973); Berry, Section 636 — Production Payments, 25 Inst, on Oil & Gas L. 389 (1974). Thus, a production payment might consist, for example, of a right to receive revenue from one-half annual production from a specified property for, say, ten years, or, say, until receipts total $100,000. It might consist of a right to receive the revenue from the first four hundred thousand barrels of oil produced. But a right that is not so limited — a right to receive revenue in perpetuity or until the mineral is exhausted — would be a “royalty,” not a “production payment.” *

An obligation must meet several other technical requirements to qualify as a “production payment.” See Treas. Reg. § 1.636-3(a)(l) (1973); Berry, supra. In fact, the Fifth Circuit in Gibson Products Co. v. United States, supra, resolved the § 636 problem we face here by holding that notes like these failed to meet one of these other requirements — namely, the requirement that the obligation be payable solely out of production. See Anderson v. Helvering, 310 U.S. 404, 412-13, 60 S.Ct. 952, 956, 84 L.Ed. 1277 (1940). It reasoned that the obligations were secured not only by production but also by the leaseholds themselves and by the salvage value of equipment used on the property. The Tax Court in the case at bar, however, found that these other sources of security lacked economic significance. And, the circuits appear to be split on the question of whether the existence of other security that is economically insignificant deprives an obligation of its status as a “production payment.” Compare Christie v. United States, 436 F.2d 1216 (5th Cir. 1971) with Standard Oil Co. (Indiana) v. Commissioner, 465 F.2d 246 (7th Cir. 1972); see also Treas. Reg. § 636-3(a)(2) (1973). We believe that it is not necessary to enter this controversy, for even if the obligation here at issue is a production payment, we do not believe that § 636 changes the result.

Next, it is important to understand the purpose of § 636. When it enacted § 636, Congress feared that by creating “production payments,” owners of oil wells could secure certain unjustified tax advantages. The precise way in which production payments achieved these advantages varied, depending, for example, on whether the payment was “carved out” by the property owner and transferred to one who in return provided services, money, etc., or whether it was “retained” by the seller when he sold the property. But, one can intuitively grasp the sort of problem that Congress saw by considering the following:

Suppose that Smith assigns to Jones the butcher (in return for meat) a ‘right’ to $20 worth of Smith’s future income. That income, when received by Smith, despite the ‘assignment’ is first taxed as Smith’s income and then again as Jones’. Suppose that Smith assigns $100,000 of future rents in Smith’s apartment house to Jones in return for services. Again, the $100,000 rent is taxed as Smith’s income first. Suppose Jones has sold the apartment house to Smith for $1 million taking $900,000 in cash and the remainder in the form of a ‘right’ to the first $100,000 of rent. Again, the rent is taxed as Smith’s income, for Jones is considered to have loaned Smith the extra $100,000 needed to pay the full $1 million and Smith is considered to be paying back this loan out of the apartment house rent. See Helvering v. Eubank, 311 U.S. 122, 61 S.Ct. 149, 85 L.Ed. 81 (1940); Helvering v. Horst, 311 U.S. 112, 61 S.Ct. 144, 85 L.Ed. 75 (1940). These examples would have worked out differently, however, before § 636 if we were dealing with oil, rather than apartment houses, for an assignment of what might have looked like future income (or rents) or a retained right to that income — if properly characterized as a “production payment” — was considered to be the income only of the person who received (or retained) the payment. That person was considered to possess an “economic interest” in the producing property; the income that it produced (that went to him) would be considered his income alone, not that of others who might possess “economic interests” in the property. Hence, if Smith paid Jones for services with an oil “production payment” (rather than a right to a share of apartment house rents) the payments, as they flowed in, would not be considered part of Smith’s income. And, if Jones sold Smith for $1 million an oil property (rather than an apartment house), retaining a $100,000 production payment (instead of a right to $100,000 of rents), the $100,000 as it flowed in would not be considered Smith’s income; that is to say, it would not be treated as if Jones had loaned Smith $100,000 which was being paid back out of income that went to Smith.

These examples illustrate the essence of what Congress felt was wrong. Congress felt that the oil property owner or buyer should be treated basically like the apartment house owner or buyer. He should not be allowed to pay for services or pay for his property (by creating a production payment) with what Congress viewed as “pretax” dollars. Indeed, Congress noted that tax advisors were taking advantage of the comparatively favorable tax treatment given production payments to structure what were known as “ABC transactions.” An oil property owner (A) would sell the property to B for some cash, reserving a production payment for the rest of the purchase price. A would then sell the reserved payment to C, a financial (or preferably a tax exempt) institution. A would thus receive the whole price in cash at once, while the buyer B, in effect, would pay off the loan from C to A with “pre-tax” oil revenue dollars (taxed as income to C and not taxed as income to B). See generally H.R.Rep.No. 91-413 (part 1), 91st Cong., 1st Sess. 140 (1969), U.S.Code Cong. & Admin.News, p. 1645; Berry, supra, at 403.

The way Congress dealt with this problem in § 636 was to require that some (but not all) production payments be treated like “loans.” See 26 U.S.C. § 636(a) (carved-out exploration or development production payment not treated as a loan). That treatment simply removed what had previously made the production payment unique, the special “income attribution” that went with it. As the Tax Court explained in this case:

When a production payment is treated as a loan, it is treated “as if” the recipient (holder) of the production payment loaned money, equipment, or services to the creator of the production payment, in return for which the recipient received rights under the production payment. When production is realized and the holder of the production payment is paid, the payments are treated as repayment of the liability created by the loans.

73 T.C. at 569-70. Thus, after § 636, the transferor of the production payment or buyer of the property (Smith in our examples) will normally be charged with the income used to satisfy the production payment.

Congress, then, was concerned with the special “income attribution” effect of production payments. It changed that effect in § 636 so that, for example, the buyer of the oil property would be treated like the buyer of the apartment house. This was its object in saying that a “production payment” should be treated as a “mortgage loan” (§ 636(a)) or a “purchase money mortgage loan” (§ 636(b)).

Given this background, the Tax Court and Brountas cannot draw from 1) § 636’s use of the word “loan” and 2) the fact that loan repayment obligations are normally not highly contingent or speculative, the conclusion that § 636 prohibits treating any production payments for basis purposes as highly contingent or speculative. For one thing, the “income attributive” purposes of § 636 do not require treating highly speculative or contingent payment obligations as if they were not highly speculative or contingent. Rather, those purposes have nothing to do with the effect that the speculative or nonspeculative quality of the obligation has on basis. And, treating highly speculative or contingent payment obligations in the presence of § 636 just as they would be treated in its absence would not, as far as we know, interfere with any of § 636’s stated purposes.

For another thing, the language of § 636 is broad enough to allow this result. That language states that a “production payment” is to be treated as a “mortgage loan” or as a “purchase money mortgage loan.” The language is general, rather than precise. As pointed out by the Tax Court, it means that the right to money under the payment is viewed as if it were received under an obligation to repay a loan. Thus, the language is best taken as a general instruction to view the whole transaction in a way that carries out the section’s purpose. In any event, one can consider the notes — the payment obligations — at issue here as if they were “loan repayment” obligations (for income attributive purposes) and at the same time consider them as highly speculative or contingent payment obligations (for basis purposes). The Fifth Circuit has specifically held that what it characterized as a “mortgage loan” is not “an indebtedness within the meaning of the Code.” Guardian Investment Corp. v. Phinney, 253 F.2d 326, 331 (5th Cir. 1958).

Further, the Treasury Regulations offer mild support for our interpretation of § 636. Treas. Reg. 1.636-l(a)(l)(i) (1973) states in part that:

[I]n the case of a transaction involving a production payment treated as a loan pursuant to this section, the production payment shall constitute an item of income (not subject to depletion), consideration for a sale or exchange, a contribution to capital, or a gift if in the transaction a debt obligation used in lieu of the production payment would constitute such an item of income, consideration, contribution to capital, or gift, as the case may be.

This regulation suggests that the “debt obligations” (which production payments are to be “treated as”) should continue to be treated differently in different circumstances, just as they were before § 636. Indeed, there is simply no reason to believe that Congress in using § 636 to close what it saw as one tax loophole wished to open another by erasing the tax distinction between those payment obligations that are highly contingent or speculative and those that are not. The Fifth Circuit refused to interpret § 636 “to produce such an absurd result.” Gibson Products Co. v. United States, 637 F.2d at 1052.

Finally, the single argument that gives us pause consists of the claim that where production payments are at issue, highly contingent or speculative repayment obligations should not be distinguished from others because production payments are always speculative. One can never be certain whether there is sufficient oil to meet the payment. We do not consider this argument determinative, however, because one can still distinguish among degrees of uncertainty; a right to collect funds from a property where oil has not yet been found would seem far more speculative than rights secured by the production of existing wells. (In fact, the Tax Court wondered how a right payable from a yet unexplored property could even qualify as a § 636 production payment given the Treasury Regulation’s requirement that the “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) (1973). But, the Commissioner did not argue this point.)

In sum, we do not believe that § 636 changes the tax basis treatment that Brountas’ nonrecourse notes would receive without it. Without that section, Brountas’ basis in the partnership would not increase to reflect the value of the nonrecourse notes. Hence, in this case he did not have the right to make certain of the deductions he claimed on his tax return.

Ill

We turn now to the second question that the Commissioner has raised, namely, whether the partnership’s accrual for tax purposes (and hence the deduction by the partners) of the total “cost” of the drilling contract was proper. In our view, the partnership could not accrue for tax purposes the noncash portion of that “cost.” We believe that the Fifth Circuit dealt with this issue correctly in Gibson, and we adopt its reasoning, set forth at 637 F.2d at 1046-47.

In essence, the same facts that make the nonrecourse notes too speculative or contingent to enter Brountas’ basis in the partnership make it improper for the partnership to accrue the expense that it claims transfer of the notes to the operator represented. That is to say, because Coral I’s note would effectively be paid only from the proceeds of any oil and gas delivered, “all the events” necessary to determine the fact and amount of liability had not yet occurred. Accordingly, the accrual of the liability as an expense was not yet proper. See Brown v. Helvering, 291 U.S. 193, 200-01, 54 S.Ct. 356, 359-60, 78 L.Ed. 725 (1934); United States v. Anderson, 269 U.S. 422, 441, 46 S.Ct. 131, 134, 70 L.Ed. 347 (1926); Subscription Television, Inc. v. Commissioner, 532 F.2d 1021, 1027 (5th Cir. 1976); Denver & Rio Grande Western Railroad Co. v. United States, 505 F.2d at 1270 (Ct.Cl.1974); Treas. Reg. § 1.461-l(a)(2) (1957).

The fact that the Tax Court found that the notes had economic substance, see 73 T.C. at 545-46, does not change our result. A note may have economic substance yet be so contingent as not to warrant its accrual as a present expense. See Brown v. Helvering, 291 U.S. at 201, 54 S.Ct. at 360 (accrual of expense improper where amount was uncertain, even though “[ejxperience taught” that there was “strong probability” that some expense would be incurred); Mooney Aircraft, Inc. v. United States, 420 F.2d 400, 410 (5th Cir. 1969). Nor is our result affected by the Tax Court’s finding that the combined value of the cash, notes, and development options transferred by Coral I were at least equal to the total contract prices, see 73 T.C. at 577-78, for the option could not be exercised unless oil was found; thus the development options were fully as contingent as the notes. An expense may be accrued only when the fact and amount of the liability can be determined “with reasonable accuracy,” Treas. Reg. § 1.461-1(a)(2) (1957); the fact that the notes and options had a fair market value of “at least” a given amount does not show whether (and if so, how much of) the liability they represent will ever be paid.

IV

The Commissioner raises two other issues in his appeal. First, he argues that Brountas should not be allowed to deduct on his tax return amounts representing the interest charge accruing on the nonrecourse notes. Our decision in parts II and III thus far controls this matter. The accrued interest charges on the notes, insofar as relevant here, must receive the same tax treatment as the notes, for the reasoning of parts II and III applies to them, mutatis mutandis. Second, the Commissioner seeks review of the Tax Court’s supplemental opinion, see 74 T.C. 1062 (1980), concerning the recognition of lease abandonment losses. However, the Commissioner states in his brief that, if this court agrees with his position on the “basis” and “deductibility” issues, his challenge to the supplemental opinion becomes moot. Hence, we do not consider it.

Y

Finally, we turn to taxpayer Brountas’ appeal from a separate part of the Tax Court’s decision. Evidently, the individual leaseholds were divided into separate parts called “horizons.” When a test well was drilled and turned out dry, a geologist would recommend whether to abandon the horizon or to abandon the entire leasehold. When an entire leasehold was abandoned, the taxpayer stopped paying “delay rentals” and presumably lost his right to the property. When only some horizons and not the entire leasehold were abandoned, however, the taxpayer continued to pay “delay rentals,” presumably so that he would not lose his right to drill elsewhere on the leasehold. The taxpayer nonetheless sought to deduct as a loss that part of his investment in a leasehold accounted for by abandoned horizons. The Tax Court refused to allow this deduction. And, since some of the investment was in cash, our previous discussion does not make the issue moot.

We reject the taxpayer’s claim and we agree with the government and the Tax Court: it was improper to take abandonment losses for mere pieces of a leasehold. The law is clear. To be entitled to an abandonment loss, a taxpayer must show “an intention ‘to abandon the property, coupled with an act of abandonment ....’” Massey-Ferguson, Inc. v. Commissioner, 59 T.C. 220, 225 (1972) (emphasis added). Where “delay rentals” were no longer paid, the Tax Court found such an “act” and allowed the loss deduction. Where the taxpayer continued to pay “delay rentals,” however, the court found no such “act.” The Tax Court in the case at bar noted:

We believe that a geological determination of total worthlessness, coupled with the objective cessation of the payment of delay rentals, establishes that a mineral lease has been abandoned. There may be other ways in which an act of abandonment could have occurred — such as delivery to the lessor of a legally binding instrument disclaiming further rights under the lease — but we need not decide this because there is no evidence here of any irrevocable, definitive act of abandonment prior to letting the delay rental due date lapse without payment.

73 T.C. at 585.

We believe the Tax Court’s decision on this point is correct. The mere determination that a stratum is worthless, even if made on the advice of geological experts, does not necessarily show abandonment. As long as the investors continued to pay the delay rentals, they had the right to test other strata and even the purportedly abandoned stratum. “In a case such as this it would be more reasonable to fix the date of worthlessness as being the date when the parties refused to pay further rents .... ” A. T. Jergins Trust v. Commissioner, 22 B. T.A. 551, 561-62 (1931), rev’d on other grounds, 61 F.2d 92 (9th Cir. 1932), rev’d sub nom. Burnet v. A. T. Jergins Trust, 288 U.S. 508, 53 S.Ct. 439, 77 L.Ed. 925 (1933); see also Macon Oil & Gas Co. v. Commissioner, 23 B.T.A. 54 (1931); cf. Thor Power Tool Co. v. Commissioner, 439 U.S. 522, 545-46, 99 S.Ct. 773, 787-88, 58 L.Ed.2d 785 (1979) (disallowing a deduction for “excess” but not yet scrapped inventory with the comment: “There is also no reason why Thor should be entitled, for tax purposes, to have his cake and eat it too.”).

In asserting their right to take “partial abandonment” losses, taxpayer refers us to the case of A. J. Industries, Inc. v. United States, 503 F.2d 660 (9th Cir. 1974). But we see nothing in that case which conflicts with the Tax Court’s decision. To be sure, the Ninth Circuit indicated in A. J. Industries that the “subjective judgment of the taxpayer ... as to whether the business assets will in the future have value is entitled to great weight .... ” Id. at 670. But it did not say that a “business judgment” of worthlessness obviated the need for an affirmative act of abandonment. To the contrary, it referred to that requirement as settled law. See id. at 670-72. And, it upheld the challenged deductions (relating to the abandonment of a mine) because there was such an act (the execution of a salvage contract). Id. at 674.

The decision of the Tax Court is vacated and the case is remanded for proceedings consistent with this opinion.  