# Brountas v. Commissioner

> United States Tax Court · December 26, 1979 · 73 T.C. 491

URL: https://www.frixlaw.com/law-library/cases/4592528

## Case

- **Full name:** Paul P. Brountas and Lynn T. Brountas v. Commissioner of Internal Revenue, Respondent CRC Corporation v. Commissioner of Internal Revenue
- **Court:** United States Tax Court
- **Decided:** December 26, 1979
- **Citations:** 73 T.C. 491; 1979 U.S. Tax Ct. LEXIS 3
- **Precedential status:** Published
- **Opinion:** Opinion
- **Judges:** Hall
- **Cited by:** 66 later opinions in the Frix Law Library

## Citator (automated)

- **Red flag:** Reversed by Paul P. Brountas v. Commissioner of Internal Revenue, Paul P. And Lynn T. Brountas v. Commissioner of Internal Revenue, 692 F.2d 152 (1982).
- Negative treatments: 1
- Distinguished by: 0
- Full citator and citing cases: https://www.frixlaw.com/law-library/cases/4592528

## Opinion text

Paul P. Brountas and Lynn T. Brountas, Petitioners v. Commissioner of Internal Revenue, Respondent; CRC Corporation, Petitioner v. Commissioner of Internal Revenue, Respondent
Brountas v. Commissioner
Docket Nos. 8231-76, 8497-76, 8698-77, 6255-78 1
United States Tax Court
73 T.C. 491 ; 1979 U.S. Tax Ct. LEXIS 3 ;
December 26, 1979 , Filed
*3 Petitioner Brountas was a limited partner in an oil and gas drilling partnership, Coral I, while petitioner CRC was a general partner in Coral I, Coral II (another similar venture), and a direct investor in other drilling ventures. Each of these ventures used the following basic format, with variations. An exploratory drilling prospect would be presented to CRC by an operator. If the geology appeared favorable, CRC would purchase for itself, or cause a limited partnership such as Coral I or Coral II to purchase, the operator's leasehold interest and the operator's promise to drill to the hoped-for producing zone on a "no-out turnkey" basis. The operator would be paid in cash 40 percent of the nominal total price of the leasehold and drilling contract. The purchaser would execute a nonrecourse note to the operator or a "lender" for the 60 percent balance, payable solely from production, if any, from the prospect or from certain other prospects (usually two) with respect to which the note would be cross-collateralized. The operator would also receive a completion option, permitting it to pay the costs of completing the well if potential production was discovered and repay the *4 purchaser's lease acquisition price and thereby regain a 40-percent interest in the well. The cash portion of the price for the drilling contract would have alone been a fair price for a "Gulf Coast Clause" or "standard turnkey" drilling contract, which, unlike the no-out turnkey, relieved the operator from his responsibility if certain unfavorable conditions were found in the course of drilling. The terms of the entire package were within a reasonable range of commercial practice.
Held , on the facts, the nonrecourse notes had value and commercial reality and were not shams. Held, further : The nonrecourse notes constituted oil or gas payments or the substantial economic equivalent within the meaning of sec. 636 and regulations sec. 1.636-3(a)(2) , and must therefore be treated for tax purposes as loans from the lender or operator to the purchasers. Therefore, the face amount of the notes was fully includable, in the case of partnership purchases, in the basis of the partners' partnership interest, as liabilities under sec. 752 , despite the contingent nature of the obligation. Held, further , the fact that the security for the notes was less than their face value does not prevent inclusion *5 of the notes at face value for purposes of sec. 752(c) . Tufts v. Commissioner , 70 T.C. 756 (1978) , on appeal (5th Cir., Apr. 23, 1979), followed. Held, further , the partnerships were entitled to deductions for intangible drilling and development costs equal to the face value of the no-out turnkey drilling contract. Held, further , interest payable on the nonrecourse notes was deductible by the accrual-basis partnerships as it accrued, despite the contingent nature of the obligation, under regulations sec. 1.636-1(a)(3) , example ( 1 ). Held, further : Respondent properly disallowed deductions to the partnership or CRC for the 60-percent note portion of the lease purchase price. On the facts, these were not advanced royalties, for the leasehold interests were acquired from the operators by purchase and not by lease. Held, further , respondent properly disallowed deductions claimed by the partnerships for management fees to the extent these fees in fact represented sales commission expenses paid by CRC and reimbursed by the partnerships to CRC. Held, further , respondent properly disallowed abandonment losses of capitalized leasehold acquisition expenses of unproductive leases for periods *6 prior to acts of definitive abandonment (i.e., periods before delay rentals were permitted to fall due unpaid). A. T. Jergins Trust v. Commissioner , 22 B.T.A. 551 (1931) , affd. on other issues 288 U.S. 508 (1933) , revg. 61 F.2d 92 (9th Cir. 1932) , followed. Held, further , fraud penalties against CRC are not sustained.
Reserved for further briefing and opinion is the issue of the timing and character of cancellation of indebtedness income generated in the case of nonrecourse indebtedness secured only by nonproductive leaseholds.
Thomas B. Rutter , for the petitioners.
Bernard Nelson, M. Kevin Phalin, David Johnson , and Bob Hollohan , for the respondent.
Hall , Judge .
HALL
*492 Respondent determined deficiencies, plus additions to the tax for fraud under section 6653(b) 2 and accumulated earnings tax under section 531, as follows: Petitioner Year Docket No. Deficiency Sec. 531 Sec. 6653(b)
Paul and Lynn Brountas 1972 8231-76 $ 6,283.35 none none
Paul and Lynn Brountas 1973 6255-78 19,006.43 none none
CRC Corp. 1972 8497-76 238,826.00 $ 152,485 $ 195,656
CRC Corp. 1973 8698-77 272,821.00 none 136,411
Petitioner *7 Paul Brountas was a limited partner in a "leveraged" oil and gas drilling venture (Coral I), and petitioner CRC *493 Corp. (CRC) was both the general partner and a limited partner in Coral I and in another "leveraged" oil and gas drilling venture (Coral II). CRC also made direct investments for its own account in similar ventures. These ventures were "leveraged" in that they used nonrecourse notes as a portion of the consideration (in addition to cash contributed by CRC and various limited partners) in transactions with unrelated oil and gas operators. Coral I, Coral II, and CRC claimed deductions in 1972 and 1973 in excess of the amount of cash they expended in exploratory oil and gas drilling, giving rise to losses in both years, and petitioners Brountas and CRC reported their distributive shares of Coral I's and Coral II's claimed losses in 1972 and 1973. Other issues having been severed for trial at a later date, 3 *9 the issues for decision at this time are:
(1) Whether Coral I, Coral II, and CRC are entitled to deductions for intangible drilling and development costs in excess of the amount of cash spent in these transactions. Specifically, we must consider:
(a) Whether the nonrecourse *8 notes were shams.
(b) If the nonrecourse notes were not shams, whether petitioners may include the face amount of these notes in their bases in their partnership interests. This issue involves consideration of (i) the applicability of section 636 (production payments) to these notes, and (ii) whether petitioners' bases are limited to the fair market value of the security for the nonrecourse notes.
(c) If these nonrecourse notes provide bases, the amount of the intangible development and drilling costs which Coral I, Coral II, and CRC are entitled to deduct.
(2) Whether Coral I, Coral II, and CRC are entitled to interest deductions relating to interest paid on the nonrecourse notes.
(3) Whether Coral I, Coral II, and CRC are entitled to claimed deductions for advanced royalties.
*494 (4) Whether Coral I and Coral II are entitled to claimed deductions for management fees.
(5) Whether Coral I, Coral II, and CRC are entitled to claimed deductions for abandonment losses.
(6) With respect to 1973, whether petitioners realized ordinary income from discharge of the indebtedness on these notes. 4
(7) Whether any part of petitioner CRC's underpayment of tax for 1972 was due to fraud.
FINDINGS OF FACT
Some of the facts have been stipulated by the parties and are found accordingly.
At the time they filed their petitions, Paul and Lynn Brountas were residents of Weston, Mass. Lynn Brountas is a party solely by virtue of the fact that she filed joint returns with her husband Paul Brountas (hereinafter Brountas) for the years in issue.
Petitioner CRC Corp. (CRC) is a Delaware corporation. At the time it filed its petitions, CRC's principal office was located in Jenkintown, Pa.
Brountas was a limited partner in Special Coral 1972 Drilling Venture I (Coral I) during the years in issue. During these years, CRC was both the general partner and a limited *10 partner in Coral I and in Special Coral 1972 Drilling Venture II (Coral II). Coral I and Coral II are duly organized limited partnerships under the laws of the State of Texas. At all times pertinent hereto, Coral I, Coral II, and CRC used the accrual method of accounting.
Brountas is a lawyer. In 1972, he contributed $ 10,000 in cash to Coral I; in 1973, he contributed an additional $ 1,000 cash for an additional development program for Coral I. He had a 0.8811-percent capital and profits interest in Coral I during both years. CRC contributed $ 25,000 cash to Coral I in 1972, $ 25,000 cash to Coral II in 1972, and an additional $ 2,500 to each partnership in 1973 for additional development. CRC had a 2.2026-percent interest in Coral I during 1972 and 1973 and a 2.1872-percent interest in Coral II during those years. CRC made direct cash investments in various partnerships which engaged in leveraged drilling operations. Such investments totaled $ 359,000 in 1972.
*495 A. Background
The format for the leveraged oil and gas drilling ventures at issue in this case was developed by Milton Dauber and William Soter. Brief background information concerning these two individuals, their formation *11 of CRC, and the oil and gas industry in general will assist in understanding this case.
Dauber is a tax attorney. In 1969, he left the private practice of law and, together with Charles Scoggins, organized a limited partnership, GeoDynamics Investors, Ltd., for the purpose of raising money for the purchase of oil and gas leasehold interests for resale. Scoggins had previously been employed as a geologist, a Texas State legislator, and an independent consultant. GeoDynamics Investors, Ltd., consisted of two general partners, Scoggins and Dauber, as well as 18 to 20 limited partners. Its offices were in Corpus Christi, Tex., and Jenkintown, Pa. Scoggins headed the office in Corpus Christi, and he was responsible for the selection of attractive oil and gas leasehold interests for purchase by the partnership. Dauber headed the office in Jenkintown, and he was responsible for the legal, accounting, financial, and administrative operations of the partnership.
Several months after the formation of GeoDynamics Investors, Ltd., Scoggins and Dauber organized GeoDynamics Oil & Gas, Inc. (GeoDynamics), which acquired the assets of GeoDynamics Investors, Ltd., in exchange for its stock. Concurrently, *12 the partnership, GeoDynamics Investors, Ltd., was dissolved. After this exchange, Scoggins and Dauber each owned 25 percent of the common stock of GeoDynamics, and the remaining 50 percent was divided among the former limited partners. Scoggins became the president of GeoDynamics, and Dauber became the chairman of its board of directors.
Like its predecessor, GeoDynamics engaged in the acquisition of leasehold interests in oil and gas properties for resale. GeoDynamics also engaged in the oil and gas business as an "operator." An operator is an entrepreneur who attempts to locate and obtain oil and gas prospects. Initially, an operator's geological staff searches for geographical areas beneath the surface of which may exist oil and gas reserves in commercial quantities. These areas are called prospects. The operator then attempts to obtain leasehold rights to these mineral interests by negotiating with either the landowner or other owners of the *496 mineral rights. Once the operator has obtained the mineral leasehold rights, and has decided to drill on the prospect, the operator usually attempts to bring in venture capital partners for the drilling. An operator, if it does not have *13 sufficient funds of its own, will attempt to have the cost of drilling a test well on the prospect paid for by others. 5 Of course, by the time the prospect has been located and the leasehold rights have been acquired, the operator has invested its own capital and expertise in the location and acquisition of the mineral properties to be explored.
Once financing has been obtained, the next step is the drilling of the prospect. The drilling is usually performed by a drilling contractor. The drilling contractor's business is distinct from that of an operator; the drilling contractor simply brings his drilling rig to the prospect, drills the hole, and then takes his rig to a different location. In most cases, the drilling contractor does not care whether or not oil is discovered -- his job is simply to drill the hole. In contrast, the operator's business is to profit by creating for itself an equity in the oil and gas discovered. *14 6
There is no "standard" financing arrangement by which an operator and outside investors develop a prospect; numerous forms of trades are used in the oil field. Among the types of interests which can be created, in varying proportions, are royalties, overriding royalties, net profits interests, production payments, carried interests, and working interests. 7 In other words, there is no set pattern to deals between operators and outside investors.
On the other hand, there is a relatively "standard" arrangement among partners within the industry called a "third for a quarter" deal. The operator transfers three-quarters of the leasehold interest in a prospect to another person (or persons) in return for payment of 100 percent of the cost of drilling and, if successful, completing the test well on the prospect. For example, if the deal included three people plus the operator, each *15 person (other than the operator) would put up one-third of the *497 drilling cost and would receive a one-quarter interest in the well. The operator's quarter interest in the well is its reward for searching for, identifying, and leasing the prospect as well as the efforts it exerts in supervising the actual drilling and completion.
In 1969, GeoDynamics entered into arrangements as an operator with two outside investment groups, First Cameron Corp. and Intramerican Drilling Fund 1969 (Intramerican Fund). Intramerican Fund was a Pennsylvania partnership organized for the purpose of investing in oil and gas exploration. In its operations with Intramerican Fund, GeoDynamics provided the people who ran Intramerican Management Corp. (Intramerican Management), which acted as a general partner for Intramerican Fund. GeoDynamics owned 49 percent of the stock of Intramerican Management, and Dauber and Scoggins were president and vice president, respectively, of Intramerican Management. Scoggins was the general exploration manager, and he supervised the expenditure of the investors' funds through the acquisition of leasehold interests in prospects and the negotiation of drilling contracts *16 for test wells on these prospects.
The drilling contracts which Scoggins negotiated for Intramerican Fund were "standard turnkey contracts." In a "standard turnkey," the operator agrees to drill a well to a certain depth for a certain amount of money. However, in the standard turnkey, the operator is given what is commonly called a Gulf Coast Clause, which allows the operator "outs" to cease drilling if certain specified unfavorable conditions are reached. Among the conditions usually specified in a Gulf Coast Clause are high or low pressure, impenetrable subsurface formations, loss of mud circulation, 8 and salt.
For example, if a high pressure subsurface area is encountered, a "blowout" can result. If a blowout occurs, the well can easily catch on fire; in any case, considerable amounts must be spent to bring the well under control. Offshore, the costs and dangers are multiplied. (The record does not disclose *17 whether any of the prospects in issue were offshore.) On the other hand, if a low pressure subsurface area is encountered, the well can *498 "fall in." When a well falls in, the drilling mud and the drilling pipe are usually lost into the hole. Given the high cost of both drilling mud and drilling pipe, low pressure also may be very costly.
The Intramerican Fund raised approximately $ 1 million from investor subscriptions, with which it drilled, through GeoDynamics, 34 test wells. A similar program, Intramerican Drilling Fund 1970 (Intramerican 1970), was formed, and GeoDynamics again was the operating partner. Intramerican 1970 raised approximately $ 1.2 million with which it drilled 38 wells.
Although GeoDynamics continued as an operator for Intramerican in 1970, basically its business changed in that year. GeoDynamics' board of directors decided that neither the lease acquisition nor operating activities were as profitable as planned. Accordingly, it was decided to turn GeoDynamics into a money management fund. In the oil and gas business, a money management fund is an organization which raises money and places it with various operators for the purpose of conducting exploration. *18 However, in contrast to GeoDynamics' earlier role, a money management fund does not actively function as an operator.
At the time GeoDynamics was changing its business, Soter along with Kenneth Avanzino and Martin Fribush formed a new, unrelated corporation, Comprehensive Resources Corp. (Comprehensive). Soter was also a tax attorney who had left private practice to enter the oil and gas business; he met Dauber in early 1970. Soter developed a format in which limited partnerships were used to obtain outside investors in oil and gas exploration and development. 9 The limited partnership format was advantageous since it allowed the outside investors to limit their liability to the amount of their contribution to the partnership. Moreover, Comprehensive would serve as the general partner of these limited partnerships, in contrast to the previous norm in the oil and gas industry in which the operator served as the general partner. Soter felt that Comprehensive could better serve the investors' interests. 10 *19
*499 Soter and Dauber incorporated in the partnerships two other important changes in the format of oil and gas exploration programs. 11 The first was the "no-out turnkey drilling contract" under which the operator never had a right to quit drilling before reaching the agreed depth -- there were no escape clauses. The Gulf Coast Clause provision, which had existed in most prior contracts, was eliminated. From the investor's (limited partner's) point of view this was important since the investor was guaranteed (to the extent of the operator's assets) that all wells which were contracted for would be drilled regardless of difficulties encountered *20 and, moreover, that the investor would not have to contribute additional drilling funds. All the financial risks of drilling were placed on the operator. But the investor pays extra for the protection which the no-out turnkey drilling contract affords him, and the operator receives the extra money because of its added risks.
The possible adverse effects of the no-out turnkey drilling obligation on an operator were illustrated by the Boyken Church Prospect which Patrick Petroleum Co. drilled for CRC. Patrick Petroleum had estimated the cost of this well to be $ 375,000, but its actual out-of-pocket cost was $ 975,000 because the well had to be drilled 3 times. The first time the well was drilled, there was a blowout when a high pressure reservoir was encountered. The second time the well was drilled, the drilling pipe separated and a portion was lost. On the third attempt, the well was successfully drilled, but it was a dry hole.
The second major change was that leverage was added to the transactions with the operators. A portion of the sum agreed to be *21 paid to the operator for the no-out turnkey drilling contract was represented by a nonrecourse note. The importance of leverage in these transactions was, first, that the investors would have only the contributed cash at risk. Second, Soter believed that the amount of the nonrecourse notes would be included in the investors' bases in their limited partnership interests, allowing the promoters to hold out the expectation to *500 potential limited partners of deductions beyond the cash contributed.
In 1970, Comprehensive and GeoDynamics formed limited partnerships employing this format. A limited partnership (with Comprehensive and GeoDynamics as cogeneral partners, and the investors as limited partners) would purchase leases for an agreed "lease purchase price" from the operators. The limited partnership and the operator would then enter into a no-out turnkey drilling contract at an agreed "drilling contract price." The contract obligated the operator to furnish to the limited partnership a "log" taken at "casing point." Casing point is the depth at which the well is evaluated; it is the point at which the operator believes, on the basis of geological evaluation, that hydrocarbons may *22 be found. In other words, casing point is the depth to which the operator has obligated itself to drill. When casing point is reached, the well is tested for the presence of hydrocarbons, usually by an electronic induction log. This log furnishes information on the basis of which a decision is made whether to complete the well. If the logs do not justify completion, the well is a "dry hole" which is then plugged and abandoned.
If the total contract price (lease purchase and drilling contract prices together) were $ 100,000, the limited partnership would pay the operator $ 29,000 in cash. In form, the limited partnership would "borrow" $ 71,000 from the operator in return for a nonrecourse note secured by 80 percent of the partnership's leasehold interests. The limited partnership would then reconvey the amount "borrowed" ($ 71,000) to the operator in payment of the unpaid part of the total "contract price" ($ 100,000). In substance, the operator received $ 29,000 in cash plus a note for $ 71,000 which was payable solely out of production. 12 *23 The note was cross-collateralized, that is, was payable out of any production from several prospects, rather than one.
In addition, as part of the package of rights transferred to the operator in 1970 as consideration for the drilling contract and the leases, the operator received a completion option and a conversion right. The completion option entitled the operator, *501 after casing point had been reached, to complete the well and pay all costs related thereto. 13 *25 In return, the operator received an interest in the mineral property equal to the ratio of completion costs to total drilling costs (completion plus drilling to casing point) actually incurred. 14 For example, if total drilling costs were $ 100,000, of which pre-casing point costs were $ 60,000, and completion costs were $ 40,000, the operator would receive a 40-percent interest in the well. However, after the operator recovered its completion costs from production (payout), one-quarter of the operator's interest so earned would revert to the investors *24 under a so-called back-in. In the above example, one-quarter of the operator's 40-percent interest -- 10 percent of total production -- would revert to the investors.
The operator also received a "conversion right" to convert its nonrecourse note into 25 percent of the investors' interest, calculated after the operator exercised the completion option but before the back-in. Using the above example, under the completion option, the operator's and investors' interest were, respectively, 40 percent and 60 percent of production. If the operator exercised the conversion right, 25 percent of the investors' 60-percent interest, or 15 percent of production, would be transferred from the investors to the operator. Accordingly, the operator's and investors' interests would become, respectively, 55 percent and 45 percent. However, the back-in was made without reference to the conversion right, so that at payout, one-quarter of the interest which the operator received under the completion *26 option, or 10 percent of production, would revert from the operator to the investors. In this example, the interests *502 of the operator and the investors would thus become after payout 45 and 55 percent, respectively.
In sum, the operator received four property rights when it entered into a drilling contract in 1970 with a limited partnership -- cash, a nonrecourse note, the conversion right, and a completion option. As consideration, the operator undertook a no-out turnkey drilling contract, with its attendant risks.
In 1970, Scoggins or Dauber negotiated with various operators concerning GeoDynamics' leveraged drilling program; the contracts Scoggins negotiated were subject to Dauber's approval. Only operators with net operating loss carryovers were willing to enter into this type of leveraged drilling program. Other operators would not do so because the face amount of the note was believed to constitute income when received for tax purposes without yielding any cash with which to pay the tax thereon.
Within GeoDynamic's format, Scoggins negotiated prices with various operators. McMoRan Exploration Co. of New Orleans, La. (McMoRan), was a major one. Scoggins and McMoRan, for example, *27 followed a basic pattern in which McMoRan's estimated turnkey price was increased 20 percent over a "Gulf Coast" contract price for risks in "less risky" areas and more for risks in "risky or high pressure areas." The amount negotiated with the operators would be the total turnkey contract cost. Of this total turnkey price (e.g., $ 100,000), 29 percent was paid in cash, and the remainder was represented by the note. The operators hoped to cover all of their out-of-pocket expenses with the cash.
Sales under the 1970 program were very successful. GeoDynamics and Comprehensive raised over $ 8 million from investors which was placed, through limited partnerships, in oil and gas exploration projects with various operators. The drilling itself was also successful, most notably McMoRan's Ransom Island project. Due to the leverage feature of the arrangement (i.e., the nonrecourse note of $ 71,000), an investor (a limited partner) reported income tax deductions in 1970 of almost 3 times the amount he put up in cash, plus obtaining an interest in producing wells.
Several changes were made in late 1970 and 1971. First, Dauber discharged Scoggins for alleged incompetence and dishonesty, and *28 gave Scoggins' position to Bill Floyd, who had worked as an exploration manager for Gulf Oil Co. before he *503 joined GeoDynamics in 1969. Second, in late 1970, a new corporation, GeoResources Management Corp. (GeoResources) was formed. The stock of GeoResources was owned equally by GeoDynamics and Comprehensive. GeoResources was formed to function as the general partner in future publicly offered leveraged drilling funds. 15 *29 Third, in July 1971, CRC was organized to effect a business combination. CRC acquired all of the outstanding stock of Comprehensive and GeoDynamics, each of which owned 50 percent of the stock of GeoResources. Dauber became chairman of the board of directors of CRC, and Soter became president. For purposes of these findings and this opinion, CRC and its subsidiaries -- GeoDynamics, GeoResources, and Comprehensive -- will henceforth be referred to collectively as CRC, irrespective of which corporate entity actually became the general partner in any given drilling fund.
In addition to these changes, the contract format was changed in three major ways. 16 *30 First, the conversion right with respect to the note was eliminated. Second, the completion right was changed so that the interest in the well earned by the completing operator was no longer determined by the ratio of completion expenses to total expenses, but became a fixed percentage -- usually 40 percent. 17 Third, the amount of cash contributed by the limited partnerships was increased. In contrast to the 29-percent cash in the 1970 program, in 1971 the partnership paid in cash 40 percent of the total no-out turnkey contract price, with the remainder of the price represented by the nonrecourse note. 18 This increased cash was apparently intended to compensate the operator for the lack of the conversion right.
The 1971 program also enjoyed successful sales. Approximately $ 30 million was raised from investors, with $ 10 million being placed with operators for exploration programs through a *504 limited partnership registered with the SEC and the remainder through unregistered limited partnerships.
B. The 1972 Drilling Program
1. In general . -- In 1972, CRC organized and managed a leveraged program similar to the 1971 program. Investment capital totaling approximately $ 25 million was placed through two registered limited partnerships, GeoResources Drilling Fund 1972 Annual Program, and GeoResources Drilling Fund 1972 Year End Program. Additional investment capital totaling approximately *31 $ 10 million was raised and placed in 1972 through 20 unregistered limited partnerships, including Coral I and Coral II. CRC served as the general partner for Coral I and Coral II.
In 1972 CRC, either on its own behalf or on behalf of the limited partnerships (such as Coral I and Coral II), entered into various agreements with various operators. These agreements, which generally consisted of (1) a lease purchase and turnkey drilling agreement, (2) loan agreement, (3) promissory note (note), (4) mortgage, deed of trust, assignment of security interest (mortgage), and (5) joint venture agreement, would pertain to a "package" of prospects submitted by an operator. A package usually involved two or more (typically three) noncontiguous oil and gas prospects to be drilled by a single operator. Participation in the various packages was generally shared by various limited partnerships. A limited partnership invested in many packages, receiving a percentage interest in each, in order to obtain diversification. As a general rule, no more than 10 percent of a limited partnership's funds were invested in any given package. Shown below are the 24 packages participated in by Coral I and Coral *32 II in 1972: Coral I Coral II
Package partnership partnership
number Name of operator participation participation
72-1 McMoRan (Elpac) 0.3395 0.34405
2 Powers (Poco) .11632 .11788
3 Western States .38517 .39033
4 McMoRan (Elpac) .38517 .39033
5 McMoRan (Elpac) .38517 .39033
6 McMoRan (Elpac) 0.38517 0.39033
7 McMoRan (Elpac) .0516 .0520
8 Gibraltar (Elpac) .0516 .0520
9 Dynamic .0516 .0520
10 Emerald .0779 .0785
11 Gibraltar (Elpac) .0779 .0785
12 McMoRan (Elpac) .0779 .0785
13 Sinclair (Elpac) .0779 .0785
14 Powers (Poco) .0779 .0785
15 Gibraltar (Elpac) .0779 .0785
16 McMoRan (Elpac) .0779 .0785
17 McMoRan (Elpac) .0779 .0785
18 McMoRan (Elpac) .0779 .0785
20 Emerald .03 .0280
22 Birthright .03 .0280
42 Gibraltar (Elpac) .013 .013
31 McMoRan (Elpac) .0097 .0088
32 Patrick .0188 .0172
96 Arriba .0169 .0172
*505 At times, CRC or its subsidiaries would participate in a package in an individual capacity. CRC entered into the following 28 packages during 1972 as an individual investor for its own account: Package
number Name of operator CRC participation
72-35 Emerald 0.0394
37 Duquesne .0394
43 Gibraltar (Elpac) .0401
44 Cane .0394
45 Cane .0394
51 Patrick .0394
52 Patrick .0042
61 Nor-Am .0394
63 Triton .0394
67 Gibraltar (Elpac) .0401
68 Nor-Am .0394
69 Sinclair (Elpac) .0401
70 Corpening .0394
72 McMoRan (Elpac) .0401
75 Nor-Am 0.0394
76 Scoggins .0394
77 McMoRan (Elpac) .0042
78 McMoRan (Elpac) .0401
79 McMoRan (Elpac) .0401
80 McMoRan (Elpac) .0401
81 McMoRan (Elpac) .0401
82 McMoRan (Elpac) .0401
83 McMoRan (Elpac) .0401
84 McMoRan (Elpac) .0401
85 McMoRan (Elpac) .0401
86 Tech-Sym .0394
87 McMoRan .0401
88 Gibraltar (Elpac) .0401
*506 *33 2. The "standard" package . -- The transactions which CRC and the limited partnerships entered into, as well as the documentation thereof, were standardized to a significant degree. 19 The agreements were entered into by the operators and, on behalf of the limited partnerships and CRC (hereinafter collectively referred to as investors), by CRC. Typically, the five agreements mentioned above with respect to a package were executed simultaneously.
The lease purchase and turnkey drilling agreement provided, first, for the transfer from the operator to the investors of the operator's interest in the oil, gas, and/or mineral leases with respect to the prospects (usually three) in the package. A price (lease purchase price) is stated for each lease in the package. Second, the operator agreed to drill a test well on each prospect at a specified location to a specified depth. The operator's obligation to drill the well was a no-out turnkey obligation, meaning that the operator agreed to drill, or cause to be drilled, a well to the agreed depth and to perform all tests and logs which a prudent operator would reasonably *34 perform for its own account. The operator was obligated to furnish all equipment, drilling rigs, drilling mud, location preparation, etc., necessary for the drilling of the well. This obligation was absolute, regardless of circumstances or difficulties, foreseen or unforeseen, which might be encountered. If any well were a dry hole, *507 the operator was obligated to plug and abandon the hole and restore the surface. In consideration for this no-out turnkey drilling agreement, which applied to all the prospects in a package, the investors promised to pay the operator a single amount (drilling contract price). The agreement further provided that the covenants of payment by the investors and the promise of performance by the operator were mutually independent.
The loan agreement, note, and mortgage were all executed at the time the lease purchase and turnkey drilling agreement was executed. Each loan agreement provided that the operator/lender would lend to the partnership an agreed-upon sum to be used by the partnership in payment of a portion of both the lease purchase price and of the drilling contract price under the related lease purchase and turnkey drilling agreement. The agreed-upon *35 sum was usually 60 percent of the combined lease acquisition cost and turnkey drilling cost, although the percentage varied in some packages. For example, if the total cost of the lease purchase and the drilling contract were $ 100,000, the loan (hereinafter the note portion) would be $ 60,000; the remaining $ 40,000 would be the investors' contribution (the cash portion). The loan agreement provided that any sum lent to the partnership by the operator bore interest at the rate of 6 1/2 percent per annum from the date of the loan and was payable upon demand on or after December 31, 1978. The loan was not subordinated to any other debts.
The debt arising out of the loan agreement was evidenced by the note and secured by the mortgage. The collateral for the debt was set forth in the loan agreement. In a typical loan agreement, the collateral for the debt was as follows:
All of the indebtedness evidenced by such note or notes shall be secured by a Mortgage, Deed of Trust, Assignment and Security Agreement (the "Mortgage") substantially in the form attached as Exhibit "B" hereto, covering:
(i) 75% of all of the rights, titles, properties and interests acquired by Borrower, its successors *36 and assigns, under the agreement; and,
(ii) 75% of all personal property and equipment in, on, used in connection with, or attributable to such rights, titles, properties and interests; and,
(iii) 53 1/3% of 75% of the production from and attributable to all of the borrowers rights, titles, properties and interests * * * , and the proceeds thereof; * * *
subject, however, to the terms and provisions of any instruments or agreements referred to or described in the Agreement which affect such rights, *508 titles, properties and interests; such pledge of collateral to the lien of the Mortgage and assignment of production runs to be in form and manner as that contained in said Exhibit "B" hereto, but specifically subject to the provisions of Part V hereof.
Said assignment of production runs and proceeds realized therefrom, represented by (iii) * * * of the foregoing paragraph and Section 3.01 of the Mortgage, shall be applied on a monthly basis, towards the repayment of the indebtedness represented by the above described note or notes; such assignment of production runs and proceeds therefrom shall continue until such indebtedness is fully paid, or until the maturity date of such note or notes *37 if such indebtedness is not fully paid by such date, in which latter event the remaining balance of such unpaid indebtedness shall be due and payable by Borrower to Lender, in accordance with the terms of said note or notes.
The collateral from production specified in (iii) above equaled a net interest of 40 percent of the production from a prospect. The percentage of production specified in (iii) above varied from package to package and, within any given package, from prospect to prospect. 20 The loan agreement expressly provided that the borrower (partnership) had no personal liability for any loan or advance made pursuant thereto and that there was no recourse against the borrower (or any partner of the borrower, whether general or limited) for any of the indebtedness created under the loan agreement. The only recourse that the operator/lender had on the note was the collateral set forth above. The entire principal amount of the loan and accrued interest was payable out of oil and gas produced from (or out of the sale of) any and all leaseholds or other rights and property interests subject to the mortgage; they were not selectively payable out of the oil and gas produced from *38 (or proceeds from the sale of) each leasehold in proportion to the loan proceeds used in the acquisition or drilling thereof. Thus, the loan was cross-collateralized in that the production from any well in the package could be used to pay off the loan.
The loan agreement also provided the operator/lender an option to enter into a completion joint venture with the borrower within 24 hours after a well on a prospect had been logged and tested. The completion option also provided that as to any subsequent wells drilled on a prospect, the operator/lender had a right to exercise an option to enter into a separate joint *509 venture for each subsequent development well on a prospect. The joint venture agreement governed the completion joint venture to be formed if the operator/lender exercised its option. Such an operator will be sometimes referred to hereafter as a completing operator.
Under the joint venture agreement a completing operator had to pay all costs of completion, *39 production casing, and any costs if the well were to be plugged and abandoned. 21 It also had to indemnify and hold harmless the investors from any and all costs, expenses, and liabilities incurred in connection with the completion attempt. Additionally, the completing operator had to repay the partnership the consideration the partnership had paid for the leases. 22 Finally, it was to reimburse the investors for all tangible equipment installed in the well before the operator exercised its option to complete.
In return, the completing operator received through the joint venture agreement a 40-percent interest in all income realized after completion. After completion, all *40 costs were to be borne by the parties to the joint venture in the same ratio (i.e., 40 percent by the operator, 60 percent by the investors). If the completion attempt failed to produce a commercial well, the completing operator would be entitled to all equipment on the property. Additionally, when the operator exercised its completion option, the mortgage provided for a substitution of collateral. The collateral for the note became the investors' interest under the joint venture agreement. For example, in the loan agreement example above, the collateral for the loan was 53 1/3 percent of 75 percent of the investors' interest, or 40 percent of production. If the investors received under the joint venture agreement a 60-percent interest in the completion joint venture, then the collateral for the note would be 40 percent of the investors' 60-percent interest, or 24 percent of the production from the well. Since the amount of production which was collateral for the loan varied from package to package, the amount of collateral substituted under the mortgage varied accordingly.
*510 All of the above terms and conditions were contained in the basic documentation executed for each package. *41 Additional terms regarding the parties' rights after "payout," which is the point at which the operator has recovered from his share of production all of his costs incurred in completing a well, were contained in further, concurrently executed agreements. Prior to payout, the partnership and the operator usually divided revenues according to a 60/40 ratio; 23 the general partner (CRC or its subsidiary) was not entitled to any share of a partnership's share of production. After payout, several changes occurred. First, in both the registered and unregistered limited partnerships the general partner became entitled to one-fourth of a partnership's share, of 15 percent of production. Second, in the registered limited partnerships, the general partner also became entitled to one-third of the operator's interest under the joint venture agreement, or 13 1/3 percent of production. 24 The unregistered limited partnerships sometimes took a share of the operator's interest in production; in Coral I, this share varied from none of some operators' interest up to one-third of the interest of other operators. The share of one of the largest operators, McMoRan, was subject to a one-ninth back-in. *42 The operator's share thus taken by the limited partners would be subject to the general partner's one-fourth share.
The table on page 511 illustrates the shares taken by the various parties in this contractual framework, both before and after payout and before and after repayment of the notes, in the case of the initial test well of (1) a registered limited partnership, (2) an unregistered limited partnership in which the limited partners were not entitled to a portion of the operator's interest after payout, (3) an unregistered limited partnership in a McMoRan package, and (4) an unregistered limited partnership in which the limited partners were entitled to one-third of the operator's interest after payout.
The above discussion of costs and percentages of production in the joint venture refers only to the initial test well on each prospect. If the initial test well were successful, and if additional development wells were required, *43 both the expenses of and *511 Relative percentages of
revenue before payout
Before payment After payment
of nonrecourse of nonrecourse
Recipient notes notes
(1) A registered Limited partners 36 60
limited partnership General partners 0 0
Operator 40 40
Operator/lender 25 *44 24 0
(2) Unregistered Limited partners 36 60
limited partnership General partners 0 0
with no back-in Operator 40 40
Operator/lender 24 0
(3) Unregistered Limited partners 31 26 55
limited partnership General partners 0 0
with one-ninth Operator 45 45
back-in (i.e. McMoRan) Operator/lender 24 0
(4) Unregistered Limited partners 36 60
limited partnership General partners 0 0
with one-third back-in Operator 40 40
Operator/lender 24 0
Relative percentages of
revenue after payout
Before payment After payment
of nonrecourse of nonrecourse
Recipient notes notes
(1) A registered Limited partners 27 45
limited partnership General partners 22 1/3 28 1/3
Operator 26 2/3 26 2/3
Operator/lender 25 24 0
(2) Unregistered Limited partners 27 45
limited partnership General partners 9 15
with no back-in Operator 40 40
Operator/lender 24 0
(3) Unregistered Limited partners 27 45
limited partnership General partners 9 15
with one-ninth Operator 40 40
back-in (i.e. McMoRan) Operator/lender 24 0
(4) Unregistered Limited partners 36 2/3 55
limited partnership General partners 12 2/3 18 1/3
with one-third back-in Operator 26 2/3 26 2/3
Operator/lender 24 0
*512 production from such development wells were usually shared in a 70/30 ratio; the investors received 70 percent of the production for payment of 70 percent of the costs, while the operators contributed 30 percent of costs for 30 percent of production. Of course, all the income from the development wells was subject to the lien of the nonrecourse notes, so the investors' shares would be reduced accordingly. 27 *45 In addition, the partnership income from the development wells was also subject to reallocation among the partners after payout. In both the registered and unregistered limited partnerships, the general partner was entitled to one-fourth of the limited partners' share of production, or 17.5 percent, after payout. Additionally, at least in the registered limited partnerships, the general partner (CRC) was also entitled to one-third of the operator's share of the production from development wells after payout.
3. Negotiation and closing of transactions in the 1972 program . -- Bill Floyd represented the limited partnerships and CRC in negotiations with the operators in 1972. As various operators became aware of CRC's drilling program, 28 *46 they brought to Floyd so-called prospect data sheets. A prospect data sheet normally provided a prospect's name, the depth to which a well would be drilled, the lease purchase price, the price of the no-out turnkey drilling contract, the percentage interest in the mineral interest to be acquired, plus the size of the operator's hoped-for discovery if the well were successful. The operators would also give Floyd maps, geophysical records, seismic information, log records, and other geological data. In setting forth facts on the prospect data sheets as to the amount and type of hydrocarbons being sought, the operators had an honest belief that such hydrocarbons might be found in the prospect. They fully intended Floyd to rely on these statements, although they also expected him to make an independent analysis using the materials they presented to him.
Floyd and the other geologists employed on behalf of CRC made an independent evaluation of each prospect. Floyd's review involved study of the geological maps, seismic data, etc., submitted with each prospect. As a consequence of this review, *513 Floyd accepted, as to geology, only 5 to 10 percent of the prospects offered to CRC in 1972.
If Floyd approved a prospect geologically, he would negotiate terms with the operators. As was mentioned above, each prospect data sheet set forth the lease purchase price and the cost of the no-out turnkey drilling contract, as proposed by the operator. In his negotiations, Floyd attempted to obtain the lowest possible prices for the lease and no-out turnkey drilling contracts in order to benefit the investors. Floyd was a competent and "tough" negotiator. He rejected on grounds of price approximately 30 percent of the prospects approved geologically.
When Floyd negotiated prices with the operators, he did not receive an anticipated cost breakdown from the various operators. 29 The operators believed that the method by which they priced prospects was solely their concern, *47 not Floyd's. The operators were aware, however, when they submitted their prospect data sheets to Floyd that they would receive in cash only a portion of both the lease purchase price and the drilling contract price. The lease purchase price and the drilling contract price were negotiated separately. In pricing the transactions, the operators generally estimated their out-of-pocket drilling costs, their overhead and profit, and a risk factor. This estimate became the "cash portion" of the drilling contract price. In other words, if the drilling contract price were $ 100,000, the operator's own estimate of his cost, etc., would be $ 40,000. The note portion of the no-out turnkey drilling contract price would then be added to this estimate. The note was usually equal to 150 percent of the estimated cash cost, or $ 60,000 in this example. In most instances, the operators hoped to meet all their costs, and make a profit, solely from the cash portion (e.g., $ 40,000) of the consideration received from the investors. 30 Of course, if problems arose in drilling a well, such as a blowout or an encounter with impenetrable material, it was unlikely that the cash portion would suffice to *48 cover the operator's costs. Additionally, none of *514 the operators expected the cash portion of the contract price to cover their costs if a completion were attempted.
There was no established pattern by which the various operators determined the lease purchase prices, but the operators all believed they were entitled to a considerable markup on the leases. The operators made substantial investments in the leases before they were conveyed to the partnerships, including a geological workup and interpretation of this information by the operator's experts. The cost which the operator paid for the lease was only one factor which the operator considered in pricing the leases.
Without regard to how the various operators arrived *49 at the lease purchase and drilling contract prices which they presented to Floyd on the prospect data sheets, all negotiations between Floyd and the operators concerned only the total prices. As found above, the lease purchase price and the drilling contract price were negotiated separately. In 1972, Floyd's specific instructions from CRC were that, having approved a prospect in terms of geology, Floyd was to engage in pricing discussions regarding only the total prices, without regard to the note portion versus the cash portion. Floyd was instructed to arrive at prices which he considered to be fair and reasonable. 31 At no time did Floyd and the operators first negotiate the cash portion, followed by addition of the note. In these negotiations, the operators were aware that a portion of the lease purchase price and the drilling contract price would be paid by means of a nonrecourse note. They were also aware of the completion option they would acquire and the no-out turnkey drilling obligation they undertook.
All negotiations between Floyd and the operators were at "arm's *50 length." In each case, the terms were commercially negotiated and were within a reasonable range of commercial practice. Due to the apparent paucity of "no-out turnkey contracts" outside these deals, it is not clear whether the markup of 150 percent from the drilling price (if payable in cash) would have been excessive compensation for the added risk. There was much sincere testimony that the price was fair even without regard to the contingency, but due to lack of comparable deals, *515 such testimony was largely conclusory in nature. However, at least when the nonrecourse note is discounted for its contingent payability, it is clear that considerations on both sides for the drilling terms were commercially fair for both parties. For example, if the drilling contract price were $ 100,000, of which the cash portion was $ 40,000 and the note portion was $ 60,000, the $ 40,000 plus the nonrecourse note and completion option was fair and reasonable consideration for the no-out turnkey drilling contract involved. Similarly, the lease purchase terms were also fair and reasonable. Moreover, the terms of the total contract were fair and reasonable. The "terms of the total contract" refers *51 to all the rights and obligations exchanged by the parties. The operators received the cash portion of the total contract price, plus a nonrecourse note for the remainder of the contract price, and the completion option; in return, the operators sold the leases to the investors and were obligated, on a no-out basis, to drill the test wells, and if a completion were attempted, to pay all completion costs plus reimburse the investors for their lease purchase price plus tangibles. The operators viewed this transaction as an integrated whole. Significantly, none of the operators would have undertaken the no-out turnkey drilling obligation if they had been paid completely in cash 32 but without the completion rights. Moreover, at least two 33 *52 of the operators did not consider the transaction acceptable if they received only the cash portion plus the completion rights, but not the note. 34
In trades in the oil field, operators regularly demand large markups over their estimated cost. This was particularly true for no-out turnkey contracts, in which the operators were assuming all the risks in drilling the well. Accordingly, the fact that the nominal drilling contract price greatly exceeded the operators' estimated cost is not unusual for such a no-out turnkey drilling contract. Moreover, because CRC was the moneyed party, Floyd *516 was negotiating from a very strong position in 1972. As one of the operators commented, "We were all starving to death." CRC was able to require the operators to take part of the nominal price for *53 the drilling contract via a nonrecourse note because of this bargaining position. The operators were primarily concerned that the entire consideration which they received from CRC -- cash, the note, and the completion option -- was fair and reasonable compensation for the risks they undertook.
In order to verify that the drilling contract prices were fair and reasonable, CRC also instituted a "double check" on Floyd. Floyd was instructed to obtain from independent petroleum engineers opinions as to whether the drilling contract price for a proposed no-out turnkey drilling contract was fair and reasonable. 35 After CRC and an operator agreed upon a price for the contract, an independent engineer would be asked to opine whether the agreed-upon price was a fair and reasonable one. The engineers were not informed of the terms of the trade; that is, they did not know that a portion of the drilling contract price would be paid with a nonrecourse note, nor did they know about the completion option. Nine such independent petroleum engineers testified in this case. All of these engineers expressed the opinion that the total no-out turnkey drilling contract prices (i.e., the face cost of *54 the contract, including the cash portion and the note portion) were fair and reasonable in light of the no-out drilling obligation assumed by the operators. While such opinions were necessarily conclusory, they at least support our conclusion that the overall terms of the transaction were not wholly afield from fair commercial practices.
After a package of prospects had been approved geologically and a price had been negotiated by Floyd and the operator, the contracts were sent to Soter for approval. Soter was not a geologist, and he did not review the geology of the prospect. Rather, Soter verified that the proposed package fit within CRC's financial planning, particularly if the package were expensive. Soter had the ultimate responsibility as to whether a package was accepted or not, and sometimes he overruled decisions which Floyd had reached.
Once a package was approved, a formal closing was held. *517 These closings followed instructions which Soter had issued. A typical closing, for a transaction in which the lease purchase and turnkey drilling contract prices totaled $ *55 100,000, went through the following steps. First, the operator would obtain, usually through a 1-day loan from a bank, the note portion (e.g., $ 60,000) of the contract price. The operator would then "loan" this $ 60,000 to the partnership; in return, the operator would receive the loan agreement, the note, the mortgage, and the joint venture agreement. Next, the operator would deliver the lease purchase and turnkey drilling agreement to the partnership, in return for which the operator would receive the total contract price (e.g., $ 100,000) in cash. The operator would then repay to the bank the $ 60,000 which he had borrowed. 36 *56 At the closing, the operator had received the $ 60,000 nonrecourse note, the mortgage, and the loan agreement (including the joint venture agreement and the completion option), plus $ 40,000 cash, and the partnership had received the leases plus the operator's no-out turnkey drilling obligation.
CRC insisted that the closings follow this pattern on the advice of its accountants. Originally, CRC had simply given the operators a check for the cash portion plus a note in the amount of the note portion, but CRC's accountants disapproved of this format. The accountants felt that it was important to have the entire contract price paid in cash in order to create an "audit trail." CRC followed its accountants' advice and arranged for the check swap in which, in a $ 100,000 contract, CRC would get a check from the operator for $ 60,000 and would give back a check to the operator for $ 100,000. CRC did not believe that either the check swap or the "loan" format had any economic significance, nor did it; this form was followed merely to satisfy its accountants. CRC understood that, in substance, it was giving the operator the cash portion of the total contract price plus a nonrecourse note for the remainder of such price.
Similarly, the operators did not believe that they had actually "loaned" money to CRC in the traditional sense. The operators *57 were aware that, in substance, they received the cash portion of *518 the total contract price plus the nonrecourse note. The operators considered the payments due under the loan agreement and the nonrecourse note to be a production payment. A production payment, generally speaking, is an obligation of an operator or an owner of a working interest in an oil or gas well to pay a specified amount of money only out of a specified part of the production of the well. 37 Normally, the holder of the production payment has no right to foreclose on the property if not paid; in this case, the holders (i.e., the operators) could foreclose on the mineral leases and property thereon. Nevertheless, the operators expected that if all the wells in a package were dry holes, the note would have a de minimis value. 38 As a practical matter, as the operators understood, the only economically significant security for the nonrecourse notes was oil and gas, if found, in the prospects which were to be drilled. Accordingly, the operators considered the nonrecourse note to be a production payment which they received as part of the consideration (along with the cash portion and the completion option) for the *58 leases and their no-out turnkey drilling obligation. 39
4. The Elpac transactions . -- Numerous transactions entered into between CRC and the operators in 1972 were materially different from the "standard" transaction in that a third party, Elpac, Inc. (Elpac), assumed the "lender's" 40 role in the transaction. *59 The transactions in which Elpac participated involved three operators -- McMoRan, Gibraltar Oil Corp. (Gibraltar), and Sinclair Development Co. (Sinclair).
Elpac was a publicly held California corporation. In 1969 and 1970, it underwent a reorganization in bankruptcy, and as a result, F. L. Cappaert became its principal shareholder. Cappaert was on the board of directors of McMoRan and was also a major shareholder in McMoRan. Upon emerging from its reorganization, Elpac had a net operating loss carryover in excess of $ 8 *519 million. This net operating loss carryover was considered to be a valuable asset since it was believed that it could be used as a means of sheltering income which Elpac hoped to generate in its business activities. Although Elpac had previously been engaged primarily in the electronics business, Cappaert acquired Elpac with the idea of expanding it into the oil and gas business because he foresaw a coming energy shortage.
In 1970, McMoRan dealt directly with CRC in that McMoRan acted as the operator/lender in its transactions with CRC and the limited partnerships. In 1971, *60 McMoRan decided it did not want to act as the lender in its transactions with CRC, although it still wanted to do business with CRC. McMoRan had two primary reasons for not wishing to be the lender. First, McMoRan did not consider the lender's role to be as advantageous after CRC eliminated the conversion right in 1971. Second, McMoRan had a sufficient net operating loss carryover in 1970 to absorb the notes into income, but did not have this carryover in 1971. Accordingly, McMoRan decided not to enter into a transaction in which it would incur the tax liability represented by the notes. However, CRC informed McMoRan that CRC was unwilling to enter into drilling programs with McMoRan unless a portion of the consideration McMoRan received was paid with the nonrecourse notes. Accordingly, in order to continue working with CRC, McMoRan sought a net operating loss carryover company to take the notes.
Messrs. Rankin and Moffett on behalf of McMoRan, and Mr. Graham on behalf of Elpac, negotiated an arrangement under which Elpac agreed to be the "lender" in transactions with CRC. Elpac entered into the transactions not for the benefit of McMoRan but, rather, for its own benefit. 41 *61 Elpac wanted to enter into the oil and gas business, and it believed that the nonrecourse notes presented it with an opportunity to benefit from oil and gas exploration. Elpac was aware that only a net operating loss carryover company could afford to acquire these nonrecourse notes, since receipt of the notes was believed to generate substantial income for income tax purposes without generating cash to pay those income taxes. Accordingly, Elpac believed that acceptance of the notes would enable it to *520 participate in the exploration program of a successful operator, McMoRan, and benefit from the production, if any, at the cost of using up its net operating loss carryover plus the assumption of certain risks. When it entered these transactions, Elpac hoped that the notes would be paid.
Elpac's participation in transactions with McMoRan and CRC generally assumed the following pattern. First, McMoRan and CRC would negotiate the price of a lease purchase and turnkey drilling agreement identical to the agreements in the "standard" transaction. The agreement reached would be identical from CRC's point *62 of view, since CRC would receive the leases and a no-out turnkey drilling agreement in return for cash, a nonrecourse note, a mortgage, and a joint venture agreement indistinguishable from the agreements entered into with other operators. 42 After McMoRan and CRC reached an agreement, the following steps were taken simultaneously. McMoRan would assign to Elpac its oil and gas leases for the package of prospects. Elpac would deliver its check to McMoRan for the note portion of the partnership's total contract price (i.e., lease purchase and drilling contract prices), and Elpac would receive back from McMoRan the nonrecourse notes. Elpac would assign the leases to the partnership, commit itself to perform the no-out turnkey drilling contract, and receive a partnership check for the total price set forth in the lease purchase and turnkey drilling agreement. Elpac also received the completion option. Elpac would deliver its check for the cash portion of the total contract price, plus the completion option, to McMoRan in return for McMoRan's promise to drill the test wells. After the closing, Elpac had received the nonrecourse notes and the rights thereunder, McMoRan (which was *63 obligated to drill the test wells) had received the cash portion of the lease purchase and turnkey drilling agreement price plus the completion option, and the partnership had obtained the leases and a no-out turnkey drilling contract from Elpac under the terms identical to those of the "standard" transaction. As in the "standard" transaction, in the Elpac transactions the lease purchase and drilling contract terms were within a reasonable range of commercial practice.
*521 Elpac was required by a separate agreement with McMoRan to share with McMoRan any cost overruns. 43 That is, to the extent that McMoRan's out-of-pocket cost (representing lease costs, actual drilling costs, and third party service costs) exceeded the cash portion of the total contract price (i.e., lease purchase and drilling contract prices), Elpac was obligated to pay McMoRan 50 percent of such excess. In essence, even through McMoRan promised to drill the wells for Elpac, Elpac still had substantial risk, including particularly its *64 promise to share any cost overruns with McMoRan and Elpac's total liability to the investors. Because of these risks, Graham of Elpac reviewed all the contracts to see if any prospects were too risky from Elpac's point of view.
The drilling agreement entered into between Elpac and McMoRan obligated McMoRan to drill the wells which Elpac was required, under its no-out turnkey drilling contract, to drill for CRC. However, McMoRan did not assume Elpac's full obligation to CRC; rather, McMoRan simply promised to drill the wells for Elpac at an agreed-upon price and furnish Elpac with one induction electric log. In contrast, Elpac's agreement with CRC not only required Elpac to drill the well but, additionally, specified in great detail the site preparation, environmental costs, 44 related drilling costs, etc., which Elpac was required *65 to bear. Elpac also promised to "furnish all logs, cores and tests necessary to evaluate each well to the extent a prudent operator in the area could determine whether or not a completion attempt should be made thereon." In short, Elpac's drilling obligation to CRC was broader than McMoRan's obligation to Elpac.
McMoRan was not the only operator with which Elpac entered into such agreements; Elpac also entered into similar contractual agreements with Gibraltar and Sinclair. These operators similarly negotiated the terms of the lease purchase and turnkey *522 drilling agreement with CRC and then brought Elpac into the transaction. 45 The contractual agreements between Elpac and these operators were, essentially, identical to the agreements between Elpac and McMoRan. That is, Elpac bore the same risks in its contracts with Gibraltar and Sinclair that it bore in its contracts with McMoRan. However, there *66 was one substantial modification in the Gibraltar and Sinclair deals. In addition to assigning the completion rights to those operators, Elpac also assigned to them a production payment, usually equal to 15 percent of the note portion of the total contract price, which was payable out of receipts under Elpac's interest in the notes. Elpac considered this production payment which it gave to Gibraltar and Sinclair to be of value, and this contractual agreement was reached by negotiations between Elpac and these operators.
In entering these transactions, Elpac expected that the transaction would result in ordinary income to Elpac for tax purposes to the extent of the face amount of the notes (but not for financial accounting purposes) which income Elpac was willing to absorb. Elpac knew that it had no recourse against the investors on the notes, and it believed that "if the wells drilled on the prospects are dry holes, Elpac [will receive] no payments on the notes, and its security is valueless, resulting in *67 no profit to Elpac." Elpac planned, when the drilling was completed, to deduct any then-excess of the face amount of the notes over the value, if any, of its interests in discovered minerals.
5. The Duquesne-Kiowa-TNT transaction . -- In 1972, Patrick Taylor started in the oil and gas operating business as president of TNT, Inc. (TNT). Taylor was an engineer who was just getting into oil operating, and he had no source of outside funds. TNT had acquired several mineral leases which were about to expire if not drilled, but it lacked the funds to drill these prospects.
Jerry Freel, who was president of Kiowa Minerals Co. (Kiowa), was a friend of Taylor's. Kiowa was an oil and gas operator with offices in Houston. On September 13, 1972, Taylor submitted a prospect (the Singer prospect) to Freel. TNT submitted a price of $ 75,000 for testing the Singer prospect, and TNT proposed that it retain a one-sixteenth working interest for *523 bearing one-sixteenth of the costs. In other words, Kiowa could obtain fifteen-sixteenths of the working interest in the prospect, which would be drilled and tested by TNT, for $ 70,312. The proposed contract was not a no-out turnkey contract; TNT reserved *68 the protections of a Gulf Coast Clause. Taylor believed this was a minimal price, but he proposed it because the leases were about to expire and he wanted to make a reputation for himself.
Freel accepted Taylor's proposal, but Freel also did not have the money needed to test the Singer prospect. Like many other operators, Kiowa had very little money in 1972. In order to obtain funds to test the Singer prospect, Freel contacted CRC and negotiated with it. 46 *69 Freel negotiated a lease purchase price of $ 10,000 and a no-out turnkey drilling contract price on the Singer prospect of $ 204,125, of which 40 percent (or $ 85,650) was to be paid in cash, and the remainder ($ 128,475) was to be paid with a nonrecourse note. The total contract price agreed to by Freel and CRC was within a reasonable range of commercial practice for a no-out turnkey arrangement. Charles Stokley, an independent petroleum engineer, issued a credible, albeit conclusory, opinion that the price was fair, and there was no credible evidence introduced by respondent to the contrary.
Freel then returned to Taylor and told Taylor that he (Freel) needed a no-out turnkey contract for the Singer prospect at the agreed-upon price of $ 75,000 between Freel and Taylor. At first, Taylor objected, but eventually, he agreed to drill the well on a "no-log, no pay contract" basis for $ 75,000. 47 Taylor was willing to accept this change because he "very much wanted to drill the well," and because he had money invested in the Singer prospect. Moreover, TNT had almost no assets; Taylor knew that if he could not satisfy this drilling contract because the well cost too much, TNT would fail as a corporation. Accordingly, Taylor believed that Freel was taking most of the risk of the no-out provision of the drilling contract, because if "[TNT] had failed, *524 and could not drill the well, and [Freel] did not pay [TNT], then [Freel] would have been stuck * * *. So [Freel] would have had to *70 drill the well there to the limit of his assets." Taylor believed that a fair price for a no-log, no-pay drilling contract on the Singer prospect, in light of the risks involved, was 3 times what he was paid, or $ 225,000.
Although Freel had negotiated a drilling contract with CRC, Freel did not want Kiowa to receive the nonrecourse note. 48 *71 Accordingly, Freel contacted Leonard Carr of Duquesne Natural Gas Co. (Duquesne). Duquesne was a Pennsylvania corporation with offices in Houston, Tex.; it was primarily engaged in the manufacture of pumps and compressors and in the operation of barge-mounted offshore drilling rigs. Prior to 1972, Duquesne had also been an oil and gas operator, but it had ceased such business by 1972. Duquesne had a substantial net operating loss carryover.
In this transaction, Duquesne assumed the "lender" role which Elpac had performed in transactions with McMoRan, Gibraltar, and Sinclair. There was, however, a significant difference between this transaction and the Elpac transactions -- Kiowa expressly assumed all of Duquesne's obligations under the no-out turnkey drilling contract. In other words, in contrast to the Elpac transactions in which the "lender," Elpac, shared half of the operators' risks, in the Duquesne-Kiowa transaction the contractual risks were expressly assumed by Kiowa. However, there was no novation of the Duquesne-CRC contract, and Duquesne remained residually liable. Duquesne was willing to enter this transaction because it believed that "the odds are we will lose instead of winning on such a deal, however, the loss would be minimal and the gain could be substantial." The primary risk which Duquesne knowingly accepted was that it could have to perform on the drilling obligation. This risk existed despite Kiowa's assumption of Duquesne's obligation to CRC, because Kiowa *72 had few assets to use to pay for drilling if any problems were encountered. In other words, if problems were encountered in drilling the Singer prospect, since neither TNT nor Kiowa had assets to speak of, Duquesne could have had to pay for the drilling despite the contractual obligations of TNT *525 and Kiowa. Additionally, Duquesne had to pay a State corporate income tax to Louisiana of 4 percent of the face amount of the notes received. 49
In the transaction with CRC, TNT assigned to Duquesne the Singer lease, which, in turn, Duquesne assigned to CRC. Duquesne entered into a no-out turnkey drilling contract with CRC in return for the total contract price ($ 85,650 plus a $ 128,475 nonrecourse note), of which it retained the note portion and assigned to Kiowa the cash and all other rights, including the completion option. Kiowa expressly assumed Duquesne's obligations under the no-out turnkey drilling contract. In sum, Duquesne retained only the note, the income from which it offset with its net operating loss carryover. Kiowa assumed Duquesne's no-out turnkey drilling obligation and received the $ *73 85,650 cash portion of the contract price plus the completion option. Kiowa, in turn, entered into a no-log, no-pay contract under which TNT actually tested the Singer prospect for $ 75,000, $ 10,000 less than the cash received by Kiowa. This may not have been a fair price for the no-log, no-pay contract because of TNT's disadvantageous bargaining position. TNT believed it was grossly underpaid.
Before this transaction closed, Duquesne obtained a 3-day loan from a bank in the amount of the note portion of the contract price. At the closing, Duquesne issued a check to CRC in the amount of the note portion of the contract price, and, in return, received from CRC a check in the full amount of the contract price plus the note. Duquesne also gave CRC the leases and its no-out turnkey drilling obligation, which had been assumed by Kiowa. At the closing, an attorney for CRC specifically requested that Taylor, Freel, and the representative from Duquesne not discuss in his (the attorney's) presence the details of the Duquesne-Kiowa-TNT arrangement.
6. Success of the 1972 drilling program . -- The operators drilled and tested all wells as required under the lease purchase and turnkey drilling *74 agreements entered into in 1972. All the operators hoped to cover their drilling costs, including overhead, with the cash portion of the drilling contract prices received from the investors; some were successful in satisfying their *526 drilling obligations for only the cash portion, others were not. The record does not disclose how many were not.
Of the 24 packages participated in by Coral I and Coral II, 11 of the packages resulted in all dry holes which were plugged and abandoned. Of the 28 packages participated in by CRC individually, 13 of the packages resulted in all dry holes which were plugged and abandoned. Additionally, in many other packages, one or more wells were plugged and abandoned, although in all of the other packages, at least one well was completed as a producing well.
Despite the large number of dry holes drilled, sizable reserves of oil and gas were found. The total partnership investments in the 1972 program were $ 35 million in cash and $ 52 million in nonrecourse notes. 50 As of July 1, 1976, proven reserves in the *527 ground from the 1972 program had a value in excess of $ 68 million. This amount is in addition to all oil and gas extracted before July 1, 1976. *75 Out of this amount, production taxes and transportation costs of approximately $ 4 million, operating costs of approximately $ 11,300,000, and other deductions of $ 2,500,000 could be expected to be paid by 1990. Additionally, payments of principal and interest on the notes in the amount of approximately $ 9 million would be made from total production. Accordingly, after all of these deductions, proven reserves as of July 1, 1976, which would be payable to the partnerships, had a value in excess of $ 40 million. Discounted at 10 percent to present worth of the future stream of net income from production from the wells, CRC's proven reserves had a present worth as of July 1, 1976, of $ 24,087,148.
*76 An example of a successful operation under CRC's 1972 drilling program was that of Patrick Petroleum Co. (Patrick). In 1972, CRC invested approximately $ 7,800,000 with Patrick, which amount included both the cash and the note portion of the total contract prices, to drill seven packages. As of January 1, 1979, CRC and the partnerships had received back approximately $ 12 million and the reserves in the ground discovered by *528 Patrick had an estimated value of $ 40 million. Coral I and Coral II were investors in one Patrick package in 1972, and CRC was an investor in two Patrick packages.
Petitioner Brountas invested $ 11,000 in the Coral I limited partnership with the purpose of profiting from his investment. As of January 1, 1979, he had received cash repayments of approximately $ 3,000. Additionally, the value of his interest in Coral I, as reflected in the reserves of oil and gas in the ground as of January 1, 1979, was in excess of his original cash investment ($ 11,000) in the partnership.
7. Deductions claimed for exploration and development . -- Coral I, Coral II, and CRC claimed intangible drilling and development cost deductions for 1972 as follows: Coral I $ 1,533,871
Coral II 1,543,614
CRC 662,454
*77 Each Coral partnership and CRC validly elected, pursuant to section 263 , to deduct such intangible drilling costs. The amount claimed as intangible drilling and development costs was the aliquot share of the total price of the turnkey drilling contracts (cash and note portions) for the packages in which Coral I, Coral II, and CRC had direct interests. The portion of the total cost of the lease purchase and turnkey drilling contracts which was allocable to acquisition of the leases was not deducted as an intangible drilling and development cost.
C. Other Issues 1. Interest . -- The nonrecourse notes which were received as part of these transactions called for interest at the rate of 6 1/2 percent per annum. Coral I, Coral II, and CRC claimed interest deductions with respect to these notes in 1972 as follows: Coral I $ 32,743
Coral II 33,027
CRC 961
2. Advanced royalties . -- Coral I, Coral II, and CRC claimed deductions in 1972 for "advanced royalties" as follows: Coral I $ 66,319
Coral II 66,066
CRC 55,775
*529 The "advanced royalties" were equal to the note portions of the stated lease purchase prices under the lease purchase and turnkey drilling agreements which were entered into with various operators. *78 These portions of the notes (lease price) had the same security as the portions of the notes allocable to drilling. Each note was secured by a portion of the production, if any, from the package of prospects, plus a specified percentage of the mineral lease and equipment thereon. If the operator exercised its completion option, this portion of the note (as part of the lease cost) was to be reimbursed to the partnership. Such reimbursement was accomplished by cancellation of this portion of the note, as well as a cash reimbursement of the cash portion of the lease purchase price. If such reimbursement of the note portion of the lease cost were made, then the accountant for CRC or the limited partnerships credited this amount as a loan reduction. If the prospects generated a dry hole, these "advanced royalties" would not be reimbursed.
3. Management fees . -- On their partnership information returns (Forms 1065) for 1972, Coral I and Coral II claimed deductions for management fees of $ 185,946 and $ 187,152, respectively. Investors in Coral I and Coral II paid as a management fee to the general partners, of which CRC was one, an amount equal to 9 percent of total program drilling *79 commitments (i.e., total contract prices). Inasmuch as total drilling commitments were approximately twice total subscriptions from the limited partners, the management fee was, in fact, about 18 percent of the limited partners' subscriptions. This fee was in lieu of any allocation of overhead expenses of the general partners to the 1972 program and entitled the partnership to all necessary services of the general partners' personnel and equipment. This fee was in addition to the general partners' interest in production from the program (i.e., one-quarter of the partnerships' interest after payout).
The fee charged by CRC was comparable to the management fees imposed by other oil and gas exploratory drilling ventures in 1972. These fees were intended to compensate CRC for its services as general partner; the fees were credited to CRC's capital account in the partnerships and paid to CRC as soon as credited. Although the partnerships were forbidden to pay commissions on the sales of partnership interests, CRC used these fees to pay brokerage commissions on the sales of limited *530 partnership interests in Coral I and Coral II. Such brokerage commissions amounted to 8 percent of the *80 investor subscriptions in Coral I and Coral II.
4. Abandonment losses . -- Coral I, Coral II, and CRC claimed abandonment losses as follows in 1972: Coral I $ 286,473
Coral II 288,674
CRC 18,533
These claimed losses arose from the alleged abandonment of the mineral leases with respect to prospects which had been tested. The value of the leases was determined by the lease purchase prices paid to the operators.
The partnerships and CRC established a policy for abandoning leaseholds which depended entirely upon a geological determination whether the lease had further geological merit. If a test well were a dry hole, a geologist for CRC determined whether or not to abandon the lease. A lease was deemed entirely abandoned when CRC or the partnerships ceased paying delay rentals for that lease. In other instances, leases would be "partially abandoned," when the geologist would determine that a portion of a lease on which the test well was productive should be abandoned, or when the geologist determined to retain some or all of a lease despite a dry test hole because of the possibility of drilling another well or farming out the prospect to a third party.
After this geological determination was *81 made, the geologist (usually Floyd) would contact CRC's accounting staff and inform them whether all or any portion of a leasehold was to be abandoned. When all or a portion of a lease was retained, delay rentals for the entire lease would be paid. These delay rentals were nominal in amount. However, the record discloses no instance in which another well was drilled or such a prospect was, in fact, farmed out or ever produced any mineral. The indicated percentage of the leases to be abandoned would then be transferred from the capital account to the expense account as an abandonment loss. Such abandonment losses were then reported by the partnerships and claimed by petitioners on their tax returns.
5. Income from cancellation of indebtedness . -- When all the leases for the prospects in a package were "abandoned" entirely, *531 the nonrecourse note which was secured by the leaseholds was considered as worthless by the partnerships. Thus, as long as CRC continued paying delay rentals with respect to at least one lease in a package in which all the prospects were dry holes, the note with respect to the package would not be "canceled." A note would be considered canceled, and cancellation *82 of indebtedness income recognized by the partnerships, only when the geologist concluded that the payment of delay rentals for all prospects in a package should cease. The delay rentals required to retain a leasehold were relatively minimal. The effect of CRC's reliance on a geological determination as to when leaseholds should be abandoned was to defer recognition of the cancellation of the indebtedness on the nonrecourse notes when a package yielded all dry holes. In 1973, nominal delay rentals were paid with respect to at least eight packages after all the wells in the package were known to be dry holes.
D. Respondent's Determinations
On his income tax return for 1972, Brountas claimed a loss from Coral I in the amount of $ 18,919. He claimed a loss in 1973 of $ 1,882. On its corporate income tax returns for 1972 and 1973, CRC claimed losses from Coral I of $ 47,294 and $ 4,705, respectively. CRC claimed losses from Coral II in 1972 and 1973 of $ 47,259 and $ 4,737, respectively. These losses claimed by Brountas and CRC were their distributive shares, as limited partners, of the losses reported by Coral I and Coral II on Form 1065.
In his statutory notices, respondent disallowed *83 part of the deductions for intangible drilling and development costs (IDCs) claimed in 1972 by Coral I, Coral II, and CRC. The amounts of IDC deductions disallowed by respondent consisted of the amounts attributable to the note portions of the drilling contact prices. Respondent disallowed IDC deductions of $ 847,349 for Coral I, of which $ 12,531 was allocable to petitioner Brountas and $ 20,866 was allocable to CRC; respondent disallowed IDC deductions of $ 866,371 for Coral II, of which $ 20,814 was allocable to CRC; and respondent disallowed CRC's claimed direct (nonpartnership) deduction for IDC of $ 397,474.
Respondent disallowed the entire amount of interest expense deduction claimed by Coral I, Coral II, and CRC for 1972. Respondent also disallowed in their entirety the amounts claimed as abandonment losses by Coral I, Coral II, and CRC, and respondent disallowed in their entirety the deductions *532 claimed for advanced royalties by Coral I, Coral II, and CRC. Respondent disallowed $ 90,800 and $ 91,440 of the management fees deductions claimed in 1972 by Coral I and Coral II, respectively. The amount of management fees disallowed by respondent is equal to 8 percent of the *84 limited partners' subscriptions. Petitioner Brountas' and CRC's shares of the disallowed deductions of Coral I and Coral II for 1972 were as follows: Petitioner Deduction Coral I Coral II
Brountes IDC $ 8,834.22
Interest 288.50
Abandonment losses 2,524.11
Advance royalties 584.35
Management fees 800.04
13,031.22
CRC IDC 20,868.00 $ 20,814
Interest 722.00 722
Abandonment losses 6,320.00 6,314
Advanced royalties 1,463.00 1,445
Management fees 2,003.00 2,000
31,376.00 31,295
With respect to 1973, respondent determined that CRC received income from forgiveness of indebtedness related to Coral I in the amount of $ 27,895, and, with respect to Coral II, respondent determined income from forgiveness of indebtedness of $ 27,871. Respondent further determined CRC's income from forgiveness of indebtedness from other ventures was $ 399,461 in 1973. Respondent determined that petitioner Brountas realized income from forgiveness of indebtedness related to Coral I of $ 5,647.90 in 1973. The basis of respondent's determinations was that if this or some other court should hold that the nonrecourse loans had economic substance, then the loans had been forgiven in 1973, and the partners were in constructive receipt of ordinary income *85 in the amount of the loans. Respondent determined that Coral I's, Coral II's, and CRC's entire nonrecourse indebtedness outstanding as of December 31, 1972, had been canceled in 1973. CRC had reported its income from cancellation of indebtedness *533 as ordinary income, while the individual limited partners (such as Brountas) had reported their income as capital gains.
Respondent determined that all or part of CRC's (but not Brountas') payment of tax in 1972 was due to fraud.
ULTIMATE FINDINGS OF FACT
The nonrecourse notes which were included in these transactions had value and commercial reality and were not shams.
Transactions between CRC (on behalf of itself and the other investors) and the various operators followed a general pattern. In each case, the operator would submit to CRC a package of geological prospects to be drilled, along with the lease purchase cost and the drilling contract cost for the proposed package. The operators were aware they would receive cash and a nonrecourse note; the cash/note ratio was usually 40/60. The operators were also aware that they would receive a completion option, which would entitle them to a share of production if they paid the costs of completing *86 the well and reimbursed certain costs to the investors.
CRC and the operators engaged in arm's-length negotiations as to the lease purchase and drilling prices. The drilling contract terms agreed to were always fair and reasonable in light of the contingent nature of part of the price and the risks undertaken by the operator in a no-out turnkey drilling contract. The lease purchase terms were also fair and reasonable again considering the contingent nature of part of the price. Moreover, the total consideration which the investors gave to the operators -- cash, the note, and the completion option -- was fair and reasonable compensation for the leases and the services performed and contributions made by the operators. The transactions were integrated wholes, and the notes were an integral part of these transactions.
The notes were nonrecourse and were secured, in economic reality, only by the oil and gas found. The notes were cross-collateralized, so that production from any one prospect within a package secured the entire note. Although the notes were also secured by the equipment on the leasehold and the mineral interests, if all the test wells in a package produced dry holes, *87 this security had de minimis value. If all the wells in a package were plugged and abandoned, the nonrecourse notes became worthless. The operators viewed the notes as substantially *534 equivalent to production payments, which are rights to a specified amount of money only out of a specified portion of the production of one or more wells.
OPINION
I. Intangible Drilling and Development Costs The first issue for decision is whether Special Coral 1972 Drilling Venture I (Coral I), Special Coral 1972 Drilling Venture II (Coral II), and CRC Corp. (CRC) are entitled to deductions for intangible drilling and development costs in excess of the cash consideration which they paid to the various operators. In 1972, petitioner Paul Brountas (Brountas) was a limited partner in Coral I, and petitioner CRC was both the general partner and a limited partner in Coral I and Coral II. CRC also invested directly in drilling operations for its own account. As set forth in our findings of fact, these limited partnerships raised money which was invested with various oil and gas operators in exploratory drilling programs. In return for a mineral lease and a no-out turnkey drilling obligation, the operators *88 received consideration of three types: (1) The cash portion of the total "contract price" for lease purchase and turnkey drilling agreement; (2) a nonrecourse note, payable from production on any of a group of prospects, for the note portion of the total "contract price"; and (3) the completion option, under which if a well appeared productive, the operator could, by completing it and repaying the cost, recapture part of the leasehold interest.
On their returns, petitioners claimed losses resulting largely from deductions for intangible drilling and development costs (IDCs) claimed by Coral I, Coral II, and CRC. 51 *90 *91 *92 *93 *94 *95 *96 *97 *98 *99 *100 *101 The IDC *535 deductions claimed were in the total amount of the drilling contract prices for the lease purchase and turnkey drilling *536 agreements entered into with the various operators. Respondent allowed IDCs represented by cash invested but determined that *537 no deductions were allowable with respect to the note portion of the drilling contract price. Specifically, respondent determined *538 that petitioners are entitled to tangible drilling and development cost deductions only to the extent of the cash portion of the drilling contract price because (a) the notes were shams, (b) *89 the nonrecourse notes did not provide basis in the investors' partnership interests, or (c) the partnerships only incurred IDCs to the extent of the cash spent. Petitioners, on the other hand, contend that they are entitled to IDC deductions with respect to the note portion of the drilling contract prices because (a) the nonrecourse note represents a bona fide, albeit contingent, obligation incurred as part of the consideration given to the operator, (b) the face amount of the note is added to the investors' bases in their interests in the partnership as either a loan or a production payment (treated as a loan), and (c) the package of consideration given to the operators (i.e., cash, note, and completion option) was worth at least the face value of the no-out turnkey drilling contract. For reasons expressed hereinafter, we agree with petitioners on this issue.
A. Sham
Respondent's primary contention in this case is that the note portion of the lease purchase and turnkey drilling agreements *102 was a sham. Respondent summed up his position succinctly on brief: "The gravamen of respondent's position is that petitioners' program was a tax gimmick and a fraud." Respondent *539 contends that the true, or economic, deal was limited to the cash portion of the price; that the contingent "note" portion was a matter of no economic import cynically added on at CRC's behest to an otherwise entirely fair arrangement, contrary to sound economic practice, and solely to swell the nominal price in order to generate a fictitious, large, front-end shelter in excess of cash investment. Were this characterization correct, we might assume for present purposes that we could ignore the notes and uphold respondent on this issue. However, this question is a factual one, and we have rejected respondent's contention in our findings. Nevertheless, because of the importance of this factual question, as well as the length and complexity of the evidentiary record, we believe that discussion of our findings is necessary.
1. Economic reality of the notes . -- It is well settled that the economic substance of these transactions, rather than their form, governs for tax purposes. Gregory v. Helvering , 293 U.S. 465 (1935) . *103 In Higgins v. Smith , 308 U.S. 473 , 477 (1940) , the Supreme Court elaborated on this principle:
the Government may not be required to acquiesce in the taxpayer's election of that form for doing business which is most advantageous to him. The Government may look at actualities and upon determination that the form employed for doing business or carrying out the challenged tax event is unreal or a sham may sustain or disregard the effect of the fiction as best serves the purposes of the tax statute.
However, in Frank Lyon Co. v. United States , 435 U.S. 561 , 583-584 (1978) , the Supreme Court noted that where --
there is a genuine multiple-party transaction with economic substance which is compelled or encouraged by business or regulatory realities, is imbued with tax-independent considerations, and is not shaped solely by tax-avoidance features that have meaningless labels attached, the Government should honor the allocation of rights and duties effectuated by the parties.
In this case, the principal dispute involves the nonrecourse note. The operators and CRC negotiated agreed-upon contract prices for mineral leases and for a no-out turnkey drilling contract to be undertaken by the operator. *104 The operator then lent 60 percent of this total price (the note portion) to CRC and the limited partnerships (investors). For this loan, the operator received a nonrecourse note payable as a practical matter only from production. The investors, in turn, used this note portion plus the cash portion (which was derived from the contributions of the limited partners and was 40 percent of the total contract *540 price) to "pay" the operator the total agreed price for the leases and the no-out turnkey drilling contract (hereinafter the total contract price).
Respondent says that the note portion was a sham introduced "to create a tax deduction in excess of the amount known to be allowable." His position has changed through the course of this case. At trial, respondent stated that the crux of his case was that the total contract prices agreed to by the operators and CRC were not reasonable. In his opening brief, respondent maintained this position and argued, further, that the operators did not in reality finance 60 percent of the cost of the test wells. In the reply brief, however, respondent retreated from his original argument and asserted that it is not relevant whether the total contract *105 price negotiated by the operators was fair and reasonable; rather, respondent now contends that the parties negotiated for only the cash portion of the total contract price. Respondent now argues that the note portion was an unbargained-for addition to the terms of an otherwise reasonable contract "tacked on" at CRC's insistence only for its own and its partners' tax benefit. Accordingly, respondent contends that the notes lack economic substance. To test the merits of respondent's contention, it is necessary to analyze the business dynamics of the CRC-operators transactions. Our analysis supports petitioners rather than respondent.
Preliminarily, we have found, as respondent argues, that the operators did not "finance" 60 percent of the cost of the no-out turnkey contracts. We found that the operators borrowed the note portion of the total contract price from a bank, "loaned" this money to CRC and, when the total contract price was received, used 60 percent of this to repay the bank. Such a "loan" must be disregarded for tax purposes, and petitioners readily concede as much. In fact, petitioners contend that the "loan" format was instituted solely on the advice of CRC's accountants, *106 who wanted to create an audit trail. The loan may be ignored. The operators in substance accepted 40-percent cash, a cross-collateralized nonrecourse note for 60 percent, and a completion option, all in exchange for their leasehold interest and their no-out turnkey drilling obligation.
We have found, contrary to respondent's contention, that the nonrecourse notes which the investors gave to the operators had economic significance and were a bona fide and bargained for *541 part of these transactions. These transactions were integrated wholes. The specific bundle of rights which each operator received was arrived at through arm's-length negotiations between the operators and CRC, and the terms of the resulting contractual agreements were within a reasonable range of commercial practice.
Specifically, operators who had prospects which they wished to test approached CRC; the operators had heard of CRC and its drilling program by word-of-mouth within the oil and gas industry. The operators presented to Bill Floyd, CRC's chief geologist, prospect data sheets on which the operators described their package of properties, the hoped-for discovery of oil and gas, their lease price, their no-out *107 turnkey drilling contract price, and their total price for a lease and a no-out turnkey drilling contract. The operators were aware, when they submitted these prospect data sheets, that they would receive only a portion of their total contract price (usually 40 percent) in cash, and 60 percent of the price would be represented by a cross-collateralized nonrecourse note. They were also aware of the completion option which they would receive if a contract were entered into.
Floyd considered the geological merits of the prospects, and on geological grounds, he rejected 90 to 95 percent of the prospects offered to him. If he approved a prospect, he and the operator then negotiated terms. Floyd was a hard bargainer, who vigorously pursued CRC's interests. All price negotiations dealt with the total lease purchase price and the total drilling contract price; Floyd never negotiated the cash portion and then added to it the note portion.
Floyd and the operators negotiated prices for the leases and the no-out turnkey drilling contract which were objectively fair and reasonable at least considering the fact that part of the price would be represented by a highly contingent obligation. 52 *109 *108 Because of its bargaining position, CRC was able to require the *542 operators to accept only 40 percent (usually) of this total contract price in cash; the remainder was paid with a cross-collateralized nonrecourse note secured only by production, and with the completion option, which enabled the operator to recapture a percentage of the production from a successful lease if the operator paid the completion costs and repaid the lease costs.
None of the operators would have accepted these transactions with CRC even for a cash payment of the total contract price without the completion option. They wanted an interest in the reserves, this being the principal business interest of an operator as distinguished from a lease broker. The completion option required the operators to pay the costs of completion after a well drilled to casing point showed promise of being a producer, in order to recapture an interest in the lease.
CRC's format met the goals of both the operators and the investors. The investors received a no-out turnkey drilling obligation, which, with the completion option, effectively guaranteed that all their wells would be drilled, and good ones completed, at no further cost to them despite any drilling difficulties which could arise. Because *110 of the no-out obligation, the operators (rightfully) demanded and received a much larger price than would have been fair for an obligation which would let them out if high pressure, or low pressure, etc., were encountered. However, the operators received in cash only an amount sufficient to cover their anticipated no-problem costs and profit; the remainder of the price for their no-out turnkey drilling contracts was represented by nonrecourse notes. For the investors, this format was advantageous since it required less cash up front; on the other hand, the operators looked for more for their work due to the extra risks they undertook. However, the operators could collect on the note only if hydrocarbons were found, although the chances of payment were substantially greater in that the notes were cross-collateralized, meaning that one note could be paid from the production from a group of dispersed wells (usually three). This contingent nature of the operators' compensation was of considerable benefit to the *543 investors; not only did they have to contribute less cash, but in addition, the operators' self-interest led the operators to offer only their best prospects to CRC. 53 Finally, *111 the completion option provided the operators with the interest in production which they demanded. Yet even this completion option was beneficial to the investors, since the operators were required to pay all completion costs and repay the lease cost to the investors. The entire arrangement was well within a reasonable range of commercial practice and clearly had economic reality.
The economic reality of CRC's program is further supported by a comparison to the so-called "third for a quarter" deal, which was a relatively standard arrangement among oil and gas partners in the oilfields. Respondent contends that a comparison with the third for a quarter transaction reveals the sham nature of CRC's transaction, particularly the nonrecourse *112 note, but we conclude that such a comparison leads to the opposite conclusion. In a third for a quarter arrangement, an operator transfers his leasehold interest to the investors in return for the investors' agreement to pay the entire cost of drilling and completing a test well. The operator retains a 25-percent interest, so that if the well is successful, the operator is entitled to 25 percent of production and the investors receive the remaining 75 percent.
By comparison, under CRC's program, the investors paid through casing point in cash only an amount expected to cover the operator's expected no-problem costs, which might not turn out to be the total costs. 54 If difficulties were encountered (as they were in the Boyken Church prospect, where the well had to be drilled three times and then was dry), the operator had to pay all the extra costs. The operator was paid for his assumption of this risk by a much higher drilling contract price, although 60 percent of that price would be paid only if at least one of the wells in a package were sufficiently commercially successful to cover the price. Under a third for a quarter arrangement, the operator had to pay none of the costs *113 through casing point. Moreover, if at casing point the operator decided to complete a well, under CRC's program, the operator would be motivated by *544 the completion option to pay all the completion costs (and reimburse the cash portion of the lease purchase price plus tangibles to the investors). In return, the operator received a 40-percent interest in the well, which was reduced, in some instances, after payout to 26 2/3 percent. In contrast, under a third for a quarter arrangement, the operator received a 25-percent interest for payment of none of the cost through completion.
A comparison of these two formats reveals, we conclude, that without the nonrecourse notes, CRC's format would be extremely disadvantageous to an operator. Without the note, under CRC's program, the operator would have received only the cash portion of the no-out turnkey drilling contract which was his expected no-problem cost of drilling to casing point plus a profit element (and the operator took all attendant risks), and the operator would have to pay all completion costs if the well were successful. In return, the operator would *114 have received an interest in production which, after payout, was not significantly greater than the interest he would receive under a third for a quarter arrangement in which the operator pays no costs. In essence, the operator would receive about the same interest it would receive in a third for a quarter arrangement, but the operator would have assumed the drilling risk and paid all completion costs. However, under CRC's format, an operator also received the nonrecourse note, which entitled him to a share of production, if any. Although the value received through the note cannot be strictly correlated to either the risks undertaken by the operator or the completion costs incurred, the note was clearly an economically significant additional piece in the package which compensated the operator for the obligations which the operator undertook. In fact, respondent's principal witness, Scoggins, testified that there was not sufficient profit for an operator to justify the CRC transaction without the note. Even with the note, in light of the fact that the operator incurred all risks of drilling, paid all completion costs, and recovered on the note only if oil or gas were found, we *115 believe that CRC's program was less advantageous to an operator than a third for a quarter arrangement, unless the possibility of finding minerals was very high.
The reason CRC was able to negotiate these terms with operators -- terms relatively disadvantageous to the operators -- *545 was CRC's bargaining position. In the years in question, CRC was one of the few sources of available capital for operators who wanted to drill wells. Because of its position as the moneyed party, CRC could require the operators to accept somewhat onerous conditions including (1) the operators received 60 percent of the contract price for the no-out turnkey drilling obligation only in the form of a nonrecourse note, (2) the operators received 60 percent of the lease purchase prices through a nonrecourse note, and (3) the operators had to pay all completion costs. The net effect of these conditions was that CRC did not have to use its front-end cash to pay the full price for the leases, the full no-out turnkey contract price, or the costs of completion. By imposing these terms, CRC was able to use its funds to invest in more wells.
In reaching our conclusion that CRC's transactions (including the nonrecourse *116 notes) had economic substance, we have viewed these transactions as a whole. These transactions were carefully structured so that the entire package of compensation which flowed from the investors to the operators was within a reasonable range of commercial practice in light of the obligations which the operators assumed. We conclude that one part of this package -- the nonrecourse notes -- cannot properly be picked out of these transactions and be labeled a sham, as that piece provided a necessary part of the consideration which the operators received. To be sure, CRC structured those arrangements to provide tax shelter, and intended that the nonrecourse note would yield tax benefits to the investors in the limited partnerships, but there were sound economic reasons for the use of such obligations in these transactions. As we stated in McLane v. Commissioner , 46 T.C. 140 , 145 (1966) , affd. per curiam 377 F.2d 557 (9th Cir. 1967) , cert. denied 389 U.S. 1038 (1968) :
The building may not be constructed entirely from the tax advantage, but, if the foundation and bricks have economic substance, the economic or financial inducement of the tax advantage can provide the mortar.
2. Respondent's *117 factual contentions . -- In support of his determination that the nonrecourse notes were shams, respondent relies on the following: (a) That some of the operators hoped not only to cover the no-problem drilling costs but also to be compensated even for the risks of the no-out turnkey drilling contract with the cash received, (b) the testimony of Scoggins, a *546 discharged employee of GeoDynamics, that the notes were shams added to the contracts for tax reasons, (c) the facts of the Elpac transactions, and (d) the facts of the Duquesne-Kiowa-TNT transaction. We are unpersuaded.
First, respondent points out that certain operators testified that they took the risk into consideration in arriving at the cash portion of the drilling price. Thus, respondent concludes, any amount in excess of the cash portion (i.e., the notes) had no economic purpose. Respondent's conclusion, however, is undermined by the weight of the evidence. In the first place, the same operators who testified that they hoped to be compensated for their risks, as well as no-problem costs with the cash received, all also testified that the drilling contract prices (cash and note portion) they negotiated with Floyd were, *118 in all cases, fair and reasonable. And respondent has apparently abandoned his original determination to the contrary. Second, independent petroleum engineers (who were unaware that a portion of the drilling contract price would be paid with a note) certified in each case that the prices were fair and reasonable in light of the risks undertaken. Third, respondent introduced no credible evidence that the price was excessive. Fourth, the magnitude of the risks the operators took when they accepted a no-out turnkey drilling contract was illustrated in the Boyken Church prospect, for which Patrick Petroleum Co. had to spend several times the cash received in order to drill a dry hole. The fact that the operators hoped to meet all costs with the cash received and considered the risks does not mean the cash price alone sufficed as adequate compensation for the risks. It does not negate the fact that the drilling contract prices, in light of the risks undertaken and the contingent nature of the note portion, were fair and reasonable. Finally, we do not view the nonrecourse notes only in relation to the risks which the operators accepted in the no-out turnkey contracts. Rather, as *119 we have previously stated, the notes were an integral and necessary part of the consideration which flowed from the investors to the operators. Accordingly, as long as the total consideration received was fair and reasonable and arrived at through arm's-length negotiations, we do not find determinative that some of the operators hoped to cover not only their drilling costs but also possible unforeseen costs under the no-out turnkey contract with the cash received.
*547 Respondent's second factual support for his sham argument is based on the testimony of Charles Scoggins. Along with Dauber, Scoggins was a cofounder of GeoDynamics in 1969, and was its chief geological officer in 1970. Scoggins was discharged by GeoDynamics in early 1971 for alleged incompetency and dishonesty, although in 1972 he contracted with CRC as an operator. His transaction with CRC in 1972 followed the standard format.
Scoggins testified in effect that the nonrecourse notes were shams added to the transactions solely for tax purposes. Scoggins testified that he objected to this format, and he claimed that he resigned from GeoDynamics because he was worried about his own legal liability. 55 Scoggins also stated *120 that when he contracted with CRC in 1972, he took the fair and reasonable price for the leases and for drilling the wells (the cash portion) and multiplied this amount by 2 1/2 to reach the total contract price. The amount in excess of the fair and reasonable price was the note portion of the total contract price. Accordingly, Scoggins believed that the total contract prices were not fair and reasonable.
If we believed Scoggins' testimony, it would be strong evidence that the nonrecourse notes were, as respondent contends, shams added to these transactions solely for tax purposes. However, we did not find Scoggins to be a candid or credible witness. In the first place, on the witness stand he was evasive and uncooperative. Secondly, petitioners' counsel brought forth numerous instances in which Scoggins' prior sworn testimony was inconsistent with his testimony before us. 56 *121 These inconsistencies undermined his credibility.
*548 Moreover, Scoggins' testimony was in direct contradiction to the credible testimony of numerous operators and petroleum engineers to the effect that both the lease *122 purchase and drilling contract prices were fair and reasonable and reached in arm's-length negotiations. Scoggins, on the other hand, testified that the operators contracted with CRC with "tongue in cheek and a wink of the eye." If we accept Scoggins' testimony, we must then conclude that these operators and petroleum engineers were not truthful in their testimony. However, we found these operators and engineers credible witnesses. For example, when Scoggins contracted with CRC in 1972, he was required to obtain an appraisal from an independent petroleum engineer that the drilling contract price was fair and reasonable. Scoggins contacted James Blackmon, who wrote such an opinion. At trial, Blackmon reaffirmed his opinion under oath, and we found Blackmon, unlike Scoggins, to be a candid and credible witness. Nonetheless, Scoggins testified that he and Blackmon "laughed about" the opinion letter and, further, that Blackmon was "lying" if he testified that the drilling contract price was fair and reasonable. In light of Blackmon's forthright demeanor and otherwise uncontradicted testimony, and Scoggins' contradictions of his own prior sworn testimony, Scoggins' assertion that *123 Blackmon was lying is part of the basis for our conclusion that Scoggins' testimony must be disregarded.
Respondent's third major factual contention is that the Elpac transactions indicate that the notes were shams. In the Elpac transactions, operators which did not have net operating loss carryovers but which wished to deal with CRC brought a third party -- Elpac -- into the transaction, primarily to absorb the income tax consequences of the notes. 57 Elpac had a large net operating loss carryover, which it used in these transactions. In these transactions, Elpac would contract with CRC, receiving the total contract price (cash and note portions) plus the completion option for its (Elpac's) assumption of the obligations under the lease purchase and turnkey drilling agreement. Elpac *549 would then assign the cash portion of the total contract price plus the completion option to an operator. 58 In return, the operator would promise to drill the test wells. Elpac agreed to pay 50 percent of any cost overruns on the drilling to the operator. Moreover, the obligation of the operator to Elpac was not as broad as Elpac's obligation to CRC under the no-out turnkey drilling contract. From *124 CRC's point of view, the Elpac transactions were similar to other transactions since CRC received the leases and a no-out turnkey drilling obligation for a fair and reasonable price.
Nonetheless, respondent contends that the Elpac transactions prove that the notes lack economic substance. Specifically, respondent argues that these transactions show that the operators were willing to undertake to drill the test wells for just the cash portion of the drilling contract price and the completion option. As a corollary, respondent asserts that the fact that only net operating loss carryover companies were willing to contract under this format establishes the lack of economic substance in CRC's format.
We are unpersuaded by respondent's arguments. In the Elpac-McMoRan *125 transactions, McMoRan agreed to drill the test wells for only the cash portion of the drilling contract price, Elpac's risk-sharing contract, and the completion option. Similarly, in the Elpac-Gibraltar and Elpac-Sinclair transactions, the operators agreed to drill the wells for the cash portion, the completion option, the risk-sharing contract, and a production payment equal to 15 percent of the note which Elpac had received from the investors. However, we do not conclude from these facts that the notes were shams. Rather, we conclude that the operators' actions are understandable in light of (1) the lesser obligation they undertook in their drilling contracts with Elpac, and (2) the context in which the Elpac transactions arose. Combined, these factors illustrate the economic substance of the notes and their role in these transactions.
In the first place, Elpac's obligation to the investors was the no-out turnkey drilling obligation which all other operators which contracted with CRC assumed. This no-out obligation was absolute and binding -- Elpac had to deliver the test wells and *550 logs to the investors no matter what the cost and no matter what drilling problems were encountered. *126 Elpac promised to hold the investors harmless from any and all claims, to furnish all logs necessary to evaluate the test wells, and to conduct the drilling at its "sole cost, risk and expense." Included in Elpac's liability were all environmental costs, which could be great, as well as all drilling costs of any nature. Moreover, Elpac was liable to the investors regardless of whether the operators performed their drilling obligations. In contrast, in the Elpac transactions, the operators' obligations to Elpac were somewhat less broad in scope. Specifically, the operators merely promised to perform the drilling, to furnish Elpac with one induction electric log, and to pay the costs thereof. The practical significance of this distinction is not determina

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Source: Frix Law Library, https://www.frixlaw.com/law-library/cases/4592528. Public record. Not legal advice.