Appendix — Hewitt v. Strickland

° . a Office-Supreme Court, U.S.

FIlLE OD

MAR 10 1983

Nos.

ALEXANDER L. STEVAS,

CLERK

IN THE

Supreme Court of the United States

October Term, 1982

PAUL P. and LYNN T. BROUNTAS,

Petitioners,

v.

COMMISSIONER OF INTERNAL REVENUE,

Respondent.

CRC CORPORATION,

Petitioner,

v.

COMMISSIONER OF INTERNAL REVENUE,

Respondent.

CONSOLIDATED APPENDIX TO

PETITIONS FOR WRITS OF CERTIORARI TO THE

UNITED STATES COURTS OF APPEALS

FOR THE FIRST CIRCUIT (BROUNTAS)

AND

FOR THE THIRD CIRCUIT (CRC CORP.)

Tuomas B. RuTTer

RvutTTer, TURNER, STEIN & SOLOMON

872 Public Ledger Building

Independence Square

Philadelphia, PA 19106

(215) 925-9200

Counsel for Petitioners

International Printing Co., 711 So. 50th St., Phila., Pa, 19143-— Tel, (215) 727-6711

TABLE OF CONTENTS

Page

Opinion of the United States Court of Appeals for the First

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Judgment of the United States Court of Appeals for the First

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Order of the United States Court of Appeals for the First

Circuit Denying Rehearing ..............sseeeseeeees A25

Opinion of the United States Court of Appeals for the Third

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Judgment of the United States Court of Appeals for the Third

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Order of the United States Court of Appeals for the Third

Circuit Denying Rehearing ................seeeeeeees AA

Opinion of the United States Tax Court ..............0065 A35

Supplemental Opinion of the United States Tax Court ...... Al77

United States Court of Appeals

For THE First Circuit

No. 81-1840

PAUL P. BROUNTAS, ET AL.,

Petitioners, Appellees,

o.

COMMISSIONER OF INTERNAL REVENUE,

Respondent, Appellant.

No. 81-1877

PAUL P. AND LYNN T. BROUNTAS,

Petitioners, Appellants,

v.

COMMISSIONER OF INTERNAL REVENUE

Respondent, Appellee.

Cross-APPEALS FROM THE UNITED STATES TAX Court

[Hon. Cynthia H. Hall, Judge]

[73 T.C. 491 (1979) ]

[74 T.C. 1062 (1980)

(Al)

AQ C.A.(1) Opinion

Before Campbell and Breyer, Circuit Judges, and

Pettine,°® Senior vistrict Judge.

George L. Hastings, Jr., Attorney, Tax Division, Depart-

ment of Justice, with whom Glenn L. Archer, Jr.,

Assistant Attorney General, Michael L. Paup and Ann

Belanger Durney, Attorneys, Tax Division, Depart-

ment of Justice, were on brief, for Commissioner of

Internal Revenue. Thomas B. Rutter, for Paul P.

Brountas, et al.

September 28, 1982

Breyer, Circuit Judge. In this “tax shelter” case, we

are asked to determine the propriety of certain deductions

taken by a limited partner in an oil-and-gas drilling part-

nership. There is little question that subsequent changes

in the law have made deductions similar to those at issue

here improper for individual taxpayers. See 26 U.S.C.

§ 465 (Supp. IV 1980) (the “at risk” provisions). But,

under the law as it stood when the deductions were taken,

which is the law we must apply, the propriety of the de-

ductions is a complicated and unsettled question. The

Tax Court’s opinion from which this appeal was taken

holds that the deductions were proper. See 73 T.C. 491

(1979). Yet, the Fifth Circuit, in a different case but on

nearly identical facts, determined that they were not.

Gibson Products Co. v. United States, 637 F.2d 1041

(1981). Having reviewed both of these decisions, as well

as the briefs filed and various cases and authorities, we

® Of the District of Rhode Island, sitting by designation.

C.A.(1) Opinion A3

find as did the Fifth Circuit (but for somewhat different

reasons ) that the deductions here were improper.

I

This case arises out of the activities of a Texas limited

partnership known as “Coral I.” The partnership was

organized in 1972, and was set up to explore and develop

“oil and gas” property. The case involves two investors

in Coral I. One is CRC Corp., which was both a limited

and general partner. The other is Paul Brountas, one of

several limited partners in Coral I. Brountas contributed

$10,000 in 1972 and $1,000 in 1973. He and his wife

(who filed a joint return with her husband) filed a peti-

tion in the United States Tax Court contesting a notice

of deficiency in their return for 1972. The Tax Court

found in favor of the petitioners. The Commissioner has

appealed. Brountas has also appealed from one part of

the Tax Court’s decision. The appeals in this circuit con-

cern Brountas and his wife but not CRC.

The Coral I partnership worked in essentially the

following manner: At the outset, partners would contribute

money (as Brountas did in the amount of $10,000). This

money would then be used to buy participations in what

looked like promising “oil and gas” ventures. These

ventures were invariably set up by CRC officials, and then

sold in fractional interests to various CRC-managed part-

nerships (such as Coral I) and to CRC on its own account.

In each case, a venture encompassed a package of several

(typically three) oil and gas leasehold interests, or “pros-

pects.” These prospects (leaseholds) were owned by an

“operator’—an entrepreneur unrelated to CRC who

wanted to develop the prospects but lacked the money

to do so. The investors had the money at a time when

it was apparently difficult to obtain in the oii and gas

A4 C.A(1) Opinion

industry; they were in a position to strike advantageous

bargains.

The bargains followed a uniform pattern. The opera-

tor would agree to convey to the investors a set of “oil

and gas” leaseholds and would agree to drill a test well

on each. The test well was often an expensive under-

taking because CRC officials insisted that the operator

agree to complete the well no matter how difficult this

proved to be. In return, the investors agreed to pay the

operator a “total” contract price. This price consisted of

a “lease purchase price” and a “drilling contract price,”

corresponding to the two parts of the operator’s agree.

ment. Each of these cormponent prices was apparently

negotiated separately with the operator by someone on

CRC’s behalf. The Tax Court found, and the government

does not contest, that the two prices were each the result

of arms-length bargaining and represented reasonable

charges for the leaseholds and obligations in question.

The investors, however, did not pay the total price

in cash. Rather, they paid the contract price with what

the Tax Court found amounted to 40 percent in cash and

60 percent in a “nonrecourse” note. The “nonrecourse”

note bore interest and was payable “on demand” after a

certain time (usually about five years). It was “secured”

by a percentage of oil and gas production from the under-

lying prospects, by a percentage of the leaseholds them-

selves, and by some of the equipment used. And, it

provided that payment on the notes would be made out of

production once production began. Despite these assur-

ances, however, it was quite clear to all concerned that

neither principal nor interest on a note would ever be paid

if the prospects in a given venture all proved to be non-

producers. The investors were not personally liable on

the notes; the operators could look to no property other

than that securing the notes for payment; and all or that

C.A.(1) Opinion A5

property would be essentially worthless if the wells

proved to be dry. As a practical matter, the notes would

be paid out of production or not paid at all.

The agreement between the investors and the oper-

ator provided the operator with one further potential

source of compensation for drilling the test wells—a “de-

velopment option.” If a well proved successful, the agree-

ment allowed the operator to gain an “equity” interest

in its production by entering into a “completion joint

venture” with the investors. To exercise this “develop-

ment option,” the operator would have to agree to “com-

plete” the test well to obtain production and to reimburse

the investors for certain previous expenses. The operator

and investors would then share all future costs and pro-

duction in a specified ratio (subject to certain additional

restrictions and conditions not relevant here ).

The limited partners believed they had invested in

a leveraged “tax shelter.” This type of shelter provides

an investor with tax deductions greater in amount than

the cash that he initially provides for the investment.

These extra deductions can be subtracted from the in-

vestor’s ordinary income, thus “sheltering” some of his

ordinary income from tax. Of course, these extra deduc-

tions may some day be offset when the investor must

recognize “income” though he receives no payment. But

this day of reckoning is in the future, and in the meantime

the government has provided the investor at least with

what is effectively an interest-free loan of the dollars that

it otherwise would have taxed away. See Harrell &

Stricoff, Overview of an Oil and Gas Tax Shelter, 28 Oil

& Gas Tax Q. 496, 496 (1980).

We can illustrate how the promoters and investors

thought this shelter would work by using the facts of

this case in simplified form. Assume the operator con-

veys a package of prospects to investors for $250,000 and

A6 C.A.(1) Opinion

agrees to drill test wells on each prospect for another

$750,000. The investors, in turn, agree to pay the “total

contract price” of $1,000,000 with $400,000 in cash and

$600,000 in a nonrecourse note payable out of production

and secured (as indicated above) by production, lease-

holds, and equipment. The operator and the investors

further agree to allocate $100,000 of the cash and $150,-

000 of the note to the “purchase price” of the prospects,

and $300,000 of the cash and $450,000 of the note to the

“drilling contract price.” In short, they agree that the

same note/cash ratio as applies to the total price shall

also apply to the two component prices. For simplicity,

assume that there is only one investor, a partnership

called Coral I, and that a (hypothetical) limited partner

called Brountas has contributed cash equal to one percent,

or $4,000, of the partnership's initial cash capital. As-

suming these numbers, Brountas’ argument amounts to a

claim that he is entitled to deduct $7,500 as expenses.

This figure—$7,500—equals one percent (Brountas’

share) of the total “drilling contract” price.

Brountas’ argument begins with the fact that the cost

of drilling an oil well is an immediately deductible ex-

pense. This is so because the Internal Revenue Code

allows taxpayers (who make the proper election) to de-

duct all “intangible drilling and development costs” (or

IDC’s) in the year incurred. 26 U.S.C. § 263(c) (Supp.

IV 1980); Treas. Reg. § 1.612-4(a)(1965). The Code

treats other expenses less favorably. The cost of ma-

chinery and equipment must be capitalized and depreci-

ated. The cost of acquiring leaseholds is not immediately

deductible, but instead becomes part of the investor's tax

“basis” and must be recovered gradually through the de-

pletion allowance or on final disposition of the property as

an offset against “amount realized.” But unlike these

costs, the “intangible” costs of drilling and developing a

C.A.(1) Opinion A7

well, such as “wages, fuel, repairs, hauling, supplies . . .

[and] the cost to [the investors here] of any drilling or

development work . . . done tor them by contractors under

any form of contract,” Treas. Reg. 1.612-4(a) (1965)

are immediately deductible.

Brountas thus claims that the partnership incurred

what (in our example) amounts to $750,000 in IDC’s in

its first year. This expense consists of its payment to the

operator (in return for a promise to drill) of $300,000

cash and $450,000 in nonrecourse notes. Brountas be-

lieves that the partnership, an accrual base taxpayer, can

accrue as an expense in 1972 the future obligation to pay

money that the notes represent. And, as a one percent

partner, Brountas seeks to deduct one percent of the part-

nership’s total IDC expense, or $7,500.

Brountas is aware that he must first demonstrate that

he has a “basis” in the partnership of at least $7,500.

The Internal Revenue Code limits the share of partner-

ship losses that a partner may deduct to the extent of the

partner's “basis” in the partnership. 26 U.S.C. § 704(d)

(1976). This basis includes the money or other property

that the partner has contributed to the partnership. 26

U.S.C. §§ 705 & 722 (1976). But, in our example, that

amounted only to $4,000. How then can Brountas deduct

$7,500? Brountas points to § 752(a), which states that

“la]ay increase in a partner's share of the liabilities of a

partnership . . . shall be considered as a contribution of

money .... The nonrecourse notes, he explains, are

liabilities of the partnership. Hence, his basis increases

by his share of the notes, or $6,000, and thus § 704 does

not limit his right to deduct his proportionate share of

the IDC expense.

The Commissioner of Internal Revenue disagrees

with Brountas. His major point of disagreement concerns

treatment of the nonrecourse notes. The Commissioner

A8 C.A(1) Opinion

argues that the notes do not represent liabilities suffi-

ciently certain and definite to warrant their accrual as

IDC expenses of the partnership or to warrant counting

them as a “liability"of the partnership for “basis” purposes

under §752(a). The Fifth Circuit essentially accepted

the Commissioner's views in Gibson, supra.

Brountas, the taxpayer, can prevail only if 1) his

partnership basis increased sufficiently to allow him to

deduct his full proportionate share of partnership ex-

penses, and 2) the partnership's accrual for tax purposes—

and hence the partners’ deduction—of the total (cash plus

noncash) “cost” of the drilling contract were proper. We

shall address each of these issues in turn,

As previously mentioned, a partner's basis in a part-

nership is defined to be the amount of money he con-

tributes to the partnership, 26 U.S.C, §§ 705, 722 (1976).

But since “[a]ny increase in a partner's share of the lia-

bilities of a partnership . . . shall be considered as a con-

tribution of money,” 26 U.S.C, § 752(a)(1976), it is clear

that when the partnership itself incurs a liability, a part-

ner’s basis ordinarily rises by his share of the liability,

See generally 1 W. McKee, W. Nelson & R. Whitmire,

Federal Taxation of Partnerships and Partners § 7.01[1}

(1977). In an ordinary (i.e., nonlimited ) partnership with

recourse indebtedness, partners are personally liable for

partnership debts, For this reason, “the practice generally

has been to treat the indebtedness of the partnership as

the indebtedness of each member of the partnership ac-

cording to his proportionate share of the debt. Theoreti-

cally, each partner (other than a limited partner) is liable

for the entire partnership indebtedness. However, be-

cause of the right of contribution among the partners, the

partners have been considered as economically burdened

C.A(1) Opinion A9

only with their share of the partnership debt. The share

of partnership debt was treated under the 1939 Code as a

contribution by the partners and included in the bases of

their partnership interests. Section 752 of the 1954 Code,

in substance, continues [this] practice.” 6 Mertens Law

of Federal Income Taxation § 35.45 (1968); See 1 W.

McKee, W. Nelson & R. Whitmire, supra, at § 8.01[1).

A limited partner, however, is liable for debts of the

partnership only to the extent of the money he has con-

tributed or is obligated to contribute. Thus, regulations

provide that “a limited partner's share of partnership lia-

bilities shall not [in general] exceed the difference be-

tween his actual contribution . . . and the total contribu-

tion which he is obligated to make... .” Treas, Reg.

§ 1.752-1(e)(1956). But, where no partner is personally

liable on a partnership liability (e.g., nonrecourse in-

debtedness ), the regulations provide that “all partners,

including limited partners, shall be considered as sharing

such liability . . . in the same proportion as they share

the profits.” Id. The question before us here is whether

the nonrecourse indebtedness in this case amounts to “lia-

bility” for purposes of § 752(a). We believe that it does

not,

A

Were it not for a special “production payment” sec-

tion of the Code, § 636, which we shall discuss in subpart

B below, this question would not be difficult. The liabilities

that investors typically are allowed to include in basis are

relatively definite liabilities such as those upon which a

lender might rely when he advances money to a bor-

rower. In a typical loan transaction, a lender advances

money or property only when either the borrower has

personally promised to pay him back, or when there is

adequate security to guarantee repayment, or both, Thus,

Al0 C.A.(1) Opinion

the borrower does not take the loan into income, for it is

offset by the obligation to repay. And, the amount of

this obligation constitutes all or part of the borrower's

“basis” in the property to which the repayment obligation

attaches. See generally Fielder, Drilling Funds and Non-

recourse Loans—Some Tax Questions, 24 Oil & Gas L. &

Tax Inst. 527 (1973). As long as the obligation is se-

cured by property of at least equivalent value, courts

have been willing to treat even “nonrecourse” liabilities

as sufficiently likely to be paid to warrant their inclusion

in an investor's basis. “[T]he reality [is| that an owner of

property, mortgaged at a figure less than that at which

the property will sell, must and will treat the conditions

of the [nonrecourse] mortgage exactly as if they were his

personal obligations.” Crane v. Commissioner, 331 U.S,

1, 14 (1947).

When, however, an obligation to pay is both non-

recourse and not secured by property of at least equivalent

value, courts have been reluctant to consider it a liability

that increases an investor's basis. Thus, cases subsequent

to Crane have found it proper to include nonrecourse

debt in basis only insofar as the value of property secur-

ing the debt is equal to or greater than the face amount

of the debt. See, e.g., Estate of Franklin v. Commissioner,

544 F.2d 1045, 1048-49 (9th Cir, 1976); Gibson Products

Co. v. United States, 460 F. Supp. 1109, 1117-19 (N.D.

Tex. 1978), aff'd on other grounds, 637 F.2d 1041 (5th

Cir. 1981); see also Rev. Rul. 77-110, 1977-1 C.B.58;

Adams, Exploring the Outer Boundaries of the Crane

Doctrine; An Imaginary Supreme Court Opinion, 21 Tax

L. Rev. 159, 165-66 (1966); cf. Crane v. Commissioner,

331 U.S. at 14, n.37 (“if the value of the property is less

than the amount of the mortgage, . . . a different problem

might be encountered”). A further line of decisions holds

that highly contingent or speculative obligations are not

C.A(1) Opinion All

includible in basis before the tncertainty surrounding

them is resolved. Thus, in Lemery v. Commissioner, 52

T.C. 367, 377-78 (1969), aff'd on other grounds, 451 F.2d

173 (9th Cir. 1971), the court held that an obligation to

pay part of the purchase price of a business out of “net

profit” was too contingent to be included in the pur-

chaser’s basis. Similarly, in Denver & Rio Grande West-

ern Railroad Co, v, United States, 505 F.2d 1266, 1269-70

(Ct. Cl. 1974), the court refused to allow the railroad

taxpayer to include in its basis advances by a customer

(used to build a “spur line”) which were repayable only

out of proceeds from shipping above a certain annual ton-

nage for ten years.

These decisions are consistent, for payment of a non-

recourse obligation is unlikely to be speculative to the

extent that it is secured by property with a determinable

value. Moreover, these decisions cannot be based upon

a belief that the value of a nonrecourse note is limited to

the value of the property that secures it, for a $1 million

nonrecourse note secured by a $200,000 building is, other

things being equal, considerably more valuable than a

$200,000 note secured by the same building. (The note’s

value will reflect the fact that the building's value might

rise, in which case the holder of the first note will receive

more money than the holder of the second.) Therefore,

these decisions must reflect an administrative fact—

namely, the fact that it is simpler, when faced with obli-

gations to pay that are highly uncertain, to wait and see

if the contingency occurs. If it does not occur, the obli-

gations need never enter basis, for they do not represent

any obligation to pay. If it does occur, the extent of the

monetary obligation will be reasonably capable of calcu-

lation, and any change in basis (where appropriate) can

then be determined.

Al2 C.A.1) Opinion

Given these cases and their apparent rationale, it is

not surprising that the district court, facing this issue in

Gibson Products Co. v. United States, 260 F. Supp. 1109,

1115-17 (N.D. Tex. 1978), held that notes virtually iden-

tical to those at issue here were too contingent to be in-

cluded in basis. Similarly, the Tax Court in the case at

bar wrote that, leaving aside § 636 (the special section

to be discussed in subpart B below), it is “highly doubtful

that [the nonrecourse notes] . . . or any similar nonre-

course highly contingent obligation would be a ‘liability’

for purposes of section 752(a) [governing basis in a part-

nership].” 73 T.C. at 559. The obligations here, unlike

recourse notes, represented (as a practical matter) a

promise to pay only if oil was found. They seem less like

the repayment obligation that typically accompanies a

recourse loan than like a device for sharing business risks

—the risks that accompany oil explorations.

In sum, if these obligations are too contingent or

speculative to warrant inclusion in an individual investor's

basis, we see no reason here why they should nonetheless

count as basis increasing § 752 partnership “liabilities.”

Rather, we believe the views of the Commissioner, the

Tax Court, and the Gibson district court to the contrary

are correct.

B

We now turn to the question of whether § 636 re-

quires a different result. That section states in subsection

(a) that a “production payment that is carved out of a

mineral property shall be treated . . . as if it were a pur-

chase money mortgage loan and shall not qualify as an

economic interest in the mineral property.” See also 26

U.S.C. § 636(b)(1976)(retained production payment).

Brountas and the Tax Court reasoned as follows: 1) The

nonrecourse obligations here amounted to “production

C.A.(1) Opinion Al3

payments.” 2) Under § 636 production payments are to

be treated like “loans.” 3) True loans involve a lender

who expects the borrower's obligation to be paid and are

typically treated as a liability that increases partnership

basis. 4) Hence, the obligations here should be added to

Brountas’ basis.

To understand the flaw in this reasoning, one must

understand both what a production payment is and the

purpose underlying § 636. Essentially, a production pay-

ment is a limited right to receive revenue from the pro-

duction of mineral in place. The right may be limited

by a dollar amount, by an amount of the mineral, and by

a period of time. See Treas. Reg. 1.636-3(a) (1) (1973);

Berry, Section 636—Production Payments, 25 Inst. on Oil

& Gas L. 389 (1974). Thus, a production payment might

consist, for example, of a right to receive revenue from

one-half annual production from a specified property for,

say, ten years, or, say, until receipts total $100,000. It

might consist of a right to receive the revenue from the

first four hundred thousand barrels of oil produced. But

a right that is not so limited—a right to receive revenue

in perpetuity or until the mineral is exhausted—would be

a “royalty,” not a “production payment.”

An obligation must meet several other technical re-

quirements to qualify as a “production payment.” See

Treas. Reg. § 1.636-3(a)(1)(1973); Berry, supra. In

fact, the Fifth Circuit in Gibson Products Co. v. United

States, supra, resolved the § 636 problem we face here by

holding that notes like these failed to meet one of these

other requirements—namely, the requirement that the

obligation be payable solely out of production. See

Anderson v. Helvering, 310 U.S. 404, 412-13 (1940), It

reasoned that the obligations were secured not only by

production but also by the leaseholds themselves and by

the salvage value of equipment used on the property.

Al4 C.A.(1) Opinion

The Tax Court in the case at bar, however, found that

these other sources of security lacked economic signifi-

cance. And, the circuits appear to be split on the question

of whether the existence of other security that is economi-

cally insignificant deprives an obligation of its status as a

“production payment.” Compare Christie v. United States,

436 F.2d 1216 (5th Cir. 1971) with Standard Oil Co.

(Indiana) v. Commissioner, 465 F.2d 246 (7th Cir. 1972);

see also Treas. Reg. § 636-3(a)(2)(1973). We believe

that it is not necessary to enter this controversy, for even

if the obligation here at issue is a production payment,

we do not believe that § 636 changes the result.

Next, it is important to understand the purpose of

§ 636. When it enacted § 636, Congress feared that by

creating “production payments,” owners of oil wells could

secure certain unjustified tax advantages. The precise

way in which production payments achieved these ad-

vantages varied, depending, for example, on whether the

payment was “carved out” by the property owner and

transferred to one who in return provided services, money,

etc., or whether it was “retained” by the seller when he

sold the property. But, one can intuitively grasp the sort

of problem that Congress saw by considering the fol-

lowing:

Suppose that Smith assigns to Jones the butcher (in

return for meat) a ‘right’ to $20 worth of Smith’s future

income. That income, when received by Smith, despite

the ‘assignment is first taxed as Smith’s income and then

again as Jones’. Suppose that Smith assigns $100,000 of

future rents in Smith’s apartment house to Jones in return

for services. Again, the $100,000 rent is taxed as Smith’s

income first. Suppose Jones has sold the apartment house

to Smith for $1 million taking $900,000 in cash and the

remainder in the form of a ‘right’ to the first $100,000 of

rent. Again, the rent is taxed as Smith’s income, for

C.A.(1) Opinion Al5

Jones is considered to have loaned Smith the extra $100,-

000 needed to pay the full $1 million and Smith is con-

sidered to be paying back this loan out of the apartment

house rent. See Helvering v. Eubank, 311 U.S. 122

(1940); Helvering v. Horst, 311 U.S. 112 (1940). These

examples would have worked out differently, however,

before § 636 if we were dealing with oil, rather than apart-

ment houses, for an assignment of what might have looked

like future income (or rents) or a retained right to that

income—if properly characterized as a “production pay-

ment”—was considered to be the income only of the per-

son who received (or retained) the payment. That

person was considered to possess an “economic interest”

in the producing property; the income that it produced

(that went to him) would be considered his income alone,

not that of others who might possess “ec ‘nterests”

in the property. Hence, if Smith paid jones for services

with an oil “production payment” (rather than a right to

a share of apartment house rents) the payments, as they

flowed in, would not be considered part of Smith's in-

come. And, if Jones sold Smith for $1 million an oil

property (rather than an apartment house), retaining a

$100,000 production payment (instead of a right to $100,-

000 of rents), the $100,000 as it flowed in would not be

considered Smith’s income; that is to say, it would not

be treated as if Jones had loaned Smith $100,000 which

wa’ being paid back out of income that went to Smith.

These examples illustrate the essence of what Con-

gress felt was wrong. Congress felt that the oil property

owner or buyer should be treated basically like the apart-

ment house owner or buyer. He should not be allowed

to pay for services or pay for his property (by creating a

production payment) with what Congress viewed as

“pre-tax” dollars. Indeed, Congress noted that tax ad-

visors were taking advantage of the comparatively favor-

Al6 C.A(1) Opinion

able tax treatment given production payments to structure

what were known as “ABC transactions.” An oil property

owner (A) would sell the property to B for some cash,

reserving a production payment for the rest of the pur-

chase price. A would then sell the reserved payment to

C, a financial (or preferably a tax exempt) institution.

A would thus receive the whole price in cash at once,

while the buyer B, in effect, would pay off the loan from

C to A with “pre-tax” oil revenue dollars (taxed as income

to C and not taxed as income to B). See generally H.R.

Rep. No. 91-413 (part 1), 91st Cong., Ist Sess. 140

(1969); Berry, supra, at 403.

The way Congress dealt with this problem in § 636

was to require that some (but not all) production pay-

ments be treated like “loans.” See 26 U.S.C. § 636(a)

(carved-out exploration or development production pay-

ment not treated as a loan). That treatment simply re-

moved what had previously made the production payment

unique, the special “income attribution” that went with

it. As the Tax Court explained in this case:

When a production payment is treated as a loan, it

is treated “as if” the recipient (holder) of the pro-

duction payment loaned money, equipment, or serv-

ices to the creator of the production payment, in

return for which the recipient received rights under

the production payment. When production is

realized and the holder of the production payment

is paid, the payments are treated as repayment of the

liability created by the loans.

73 T.C. at 569-70. Thus, after § 636, the transferor of the

production payment or buyer of the property (Smith in

our examples) will normally be charged with the income

used to satisfy the production payment.

C.A.(1) Opinion Al7

Congress, then, was concerned with the special “in-

come attribution” effect of production payments. _ It

changed that effect in § 636 so that, for example, the

buyer of the oil property would be treated like the buyer

of the apartment house. This was its object in saying that

a “production payment” should be treated as a “mortgage

loan” (§ 636(a)) or a “purchase money mortgage loan”

(§ 636(b) ).

Given this background, the Tax Court and Brountas

cannot draw from 1) § 636’s use of the word “loan” and

2) the fact that loan repayment obligations are normally

not highly contingent or speculative, the conclusion that

§ 636 prohibits treating any production payments for basis

purposes as highly contingent or speculative. For one

thing, the “income attributive” purposes of § 636 do not

require treating highly speculative or contingent payment

obligations as if they were not highly speculative or con-

tingent. Rather, those purposes have nothing to do with

the effect that the speculative or nonspeculative quality

of the obligations has on basis. And, treating highly

speculative or contingent payment obligations in the pres-

ence of § 636 just as they would be treated in its absence

would not, as far as we know, interfere with any of § 636's

stated purposes.

For another thing, the language of § 636 is broad

enough to allow this result. That language states that a

“production payment” is to be treated as a “mortgage

loan” or as a “purchase money mortgage loan.” The lan-

guage is general, rather than precise. As pointed out by

the Tax Court, it means that the right to money under

the payment is viewed as if it were received under an

obligation to repay a loan. Thus, the language is best

taken as a general instruction to view the whole transac-

tion in a way that carries out the section’s purpose. In

any event, one can consider the notes—the payment obli-

°aG

Al8 C.A.(1) Opinion

gations—at issue here as if they were “loan repayment”

obligations (for income attributive purposes) and at the

same time consider them as highly speculative or con-

tingent payment obligations (for basis purposes). The

Fifth Circuit has specifically held that what it char-

acterized as a “mortgage loan” is not “an indebtedness

within the meaning of the Code.” Guardian Investment

Corp. v. Phinney, 253 F.2d 326, 331 (5th Cir. 1958).

Further, the Treasury Regulations offer mild support

for our interpretation of § 636. Treas. Reg. 1.636-1(a)

(1)(i)(1973) states in part that:

[I|n the case of a transaction involving a production

payment treated as a loan pursuant to this’ section,

the production payment shall constitute an item of

income (not subject to depletion), consideration for

a sale or exchange, a contribution to capital, or a

gift if in the transaction a debt obligation used in

lieu of the production payment would constitute

such an item of income, consideration, contribution

to capital, or gift, as the case may be.

This regulation suggests that the “debt obligations”

(which production payments are to be “treated as”)

should continue to be treated differently in different cir-

cumstances, just as they were before § 636. Indeed, there

is simply no reason to believe that Congress in using

§ 636 to close what it saw as one tax loophole wished to

open another by erasing the tax distinction between those

payment obligations that are highly contingent or specu-

lative and those that are not. The Fifth Circuit refused

to interpret § 636 “to produce such an absurd result.”

Gibson Products Co. v. United States, 637 F.2d at 1052.

Finally, the single argument that gives us pause con-

sists of the clair that where production payments are at

C.A.(1) Opinion Al9

issue, highly contingent or speculative repayment obli-

gations should not be distinguished from others because

production payments are always speculative. One can

never be certain whether there is sufficient oil to meet the

payment. We do not consider this argument determina-

tive, however, because one can still distinguish among

degrees of uncertainty; a right to collect funds from a

property where oil has not yet been found would seem

far more speculative than rights secured by the production

of existing wells. (In fact, the Tax Court wondered how

a right payable from a yet unexplored property could even

qualify as a § 636 production payment given the Treasury

Regulation’s requirement that the “right must have an

expected economic life (at the time of its creation) of

shorter duration than the economic life of one or more of

the minéral properties burdened thereby,” Treas. Reg.

§ 1.636-3(a)(1)(1973). But, the Commissioner did not

argue this point. )

In sum, we do not believe that § 636 changes the tax

basis treatment that Brountas’ nonrecourse notes would

receive without it. Without that section, Brountas’ basis

in the partnership would not increase to reflect the value of

the nonrecourse notes. Hence, in this case he did not

have the right to make certain of the deductions he

claimed on his tax return.

III

We turn now to the second question that the Com-

missioner has raised, namely, whether the partnership's

accrual for tax purposes (and hence the deduction by the

partners) of the total “cost” of the drilling contract was

proper. In our vicw, the partnership could not accrue for

tax purposes the noncash portion of that “cost.” We be-

lieve that the Fifth Circuit dealt with this issue correctly

in Gibson, and we adopt its reasoning, set forth at 637

F.2d at 1046-47.

A20 C.A. (1) Opinion

In essence, the same facts that make the nonrecourse

notes too speculative or contingent to enter Brountas’ basis

in the partnership make it improper for the partnership to

accrue the expense that it claims transfer of the notes to

the operator represented. That is to say, because Coral I’s

note would effectively be paid only from the proceeds of

any oil and gas delivered, “all the events” necessary to

determine the fact and amount of liability had not yet

occurred. Accordingly, the accrual of the liability as an

expense was not yet proper. See Brown v. Helvering, 291

U.S. 193, 200-01 (1934); United States v. Anderson, 269

U.S. 422, 441 (1926); Subscription Television, Inc. v.

Commissioner, 532 F.2d 1021, 1027 (5th Cir. 1976);

Denver & Rio Grande Western Railroad Co. v. United

States, 505 F.2d at 1270 (Ct.Cl. 1974); Treas. Reg.

§ 1.461-1(a) (2) (1957).

The fact that the Tax Court found that the notes had

economic substance, see 73 T.C. at 545-46, does not

change our result. A note may have economic substance

yet be so contingent as not to warrant its accrual as a

present expense. See Brown v. Helvering, 291 U.S. at

201 (accrual of expense improper where amount was un-

certain, even though “[e|xperience taught” that there was

“strong possibility” that some expense would be incurred ) ;

Mooney Aircraft, Inc. v. United States, 420 F.2d 400, 410

(5th Cir. 1969). Nor is our result affected by the Tax

Court's finding that the combined value of the cash, notes,

and development options transferred by Coral I were at

least equal to the total contract prices, see 73 T.C. at

577-78, for the option could not be exercised unless oil

was found; thus the development options were fully as

contingent as the notes. An expense may be accrued only

when the fact and amount of the liability can be deter-

mined “with reasonable accuracy,” Treas. Reg. § 1.461-

1(a)(2)(1957); the fact that the notes and options had

C.A.(1) Opinion A2l

a fair market value of “at least” a given amount does not

show whether (and if so, how much of) the liability they

represent will ever be paid.

IV

The Commissioner raises two other issues in his ap-

peal. First, he argues that Breuntas should not be allowed

to deduct on his tax return amounts representing the in-

terest charge accruing on the nonrecourse notes. Our

decisions in parts II and III thus far controls this matter.

The accrued interest charges on the notes, insofar as rel-

evant here, must receive the same tax treatment as the

notes, for the reasoning of parts II and III applies to them,

mutatis mutandis. Second, the Commissioner seeks re-

view of the Tax Court's supplemental opinion, see 74 T.C.

1062 (1980), concerning the recognition of lease abandon-

ment losses. However, the Commissioner states in his

brief that, if this court agrees with his position on the

“basis” and “deductibility” issues, his challenge to the

supplemental opinion becomes moot. Hence, we do not

consider it.

Vv

Finally, we turn to taxpayer Brountas’ appeal from a

separate part of the Tax Court’s decision. Evidently, the

individual leaseholds were divided into separate parts

called “horizons.” When a test well was drilled and

turned out dry, a geologist would recommend whether to

abandon the horizon or to abandon the entire leasehold.

When an entire leasehold was abandoned, the taxpayer

stopped paying “delay rentals” and presumably lost his

right to the property. When only some horizons and not

the entire leasehold were abandoned, however, the tax-

payer continued to pay “delay rentals,” presumably so

that he would not lose his right to drill elsewhere on the

A22 C.A.(1) Opinion

leasehold. The taxpayer nonetheless sought to deduct as

a loss that part of his investment in a leasehold accounted

for by abandoned horizons. The Tax Court refused to

allow this deduction. And, since some of the investment

was in cash, our previous discussion does not make the

issue moot.

We reject the taxpayer's claim and we agree with

the government and the Tax Court: it was improper to

take abandonment !»sses for mere pieces of a leasehold.

The law is clear. To be entitled to an abandonment loss,

a taxpayer must show “an intention ‘to abandon the prop-

erty, coupled with an act of abandonment... .'" Massey-

Ferguson, Inc, v. Commissioner, 59 T.C, 220, 225 (1972)

(emphasis added). Where “delay rentals” were no

longer paid, the Tax Court found such an “act” and al-

lowed the loss deduction. Where the taxpayer continued

to pay “delay rentals,” however, the court found no such

“act.” The Tax Court in the case at bar noted:

We believe that a geological determination of total

worthlessness, coupled with the objective cessation

of the payment of delay rentals, establishes that a

mineral lease has been abandoned. There may be

other ways in which an act of abandonment could

have occurred—such as delivery to the lessor of a

legally binding instrument disclaiming further rights

under the lease—but we need not decide this be-

cause there is no evidence here of any irrevocable,

definitive act of abandonment prior to letting the

delay rental due date lapse without payment.

73 T.C, at 585.

We believe the Tax Court's decision on this point is

correct. The mere determination that a stratum is worth-

less, even if made on the advice of geological experts,

does not necessarily show abandonment. As long as the

C.A.(1) Opinion A23

investors continued to pay the delay rentals, they had the

right to test other strata and even the purportedly aban-

doned stratum. “In a case such as this it would be more

reasonable to fix the date of worthlessness as being the

date when the parties refused to pay further rents... .”

A.T. Jergins Trust v. Commissioner, 22 B.T.A. 551, 561-

62 (1931), rev’d on other grounds, 61 F.2d 92 (9th Cir.

1932), rev'd sub nom. Burnet v. A.T. Jergins Trust, 288

U.S. 508 (1933); see also Macon Oil & Gas Co. v, Com-

missioner, 23 B.T.A. 54 (1931); ef. Thor Power Tool Co.

v. Commissioner, 439 U.S, 522, 545-46 (1979) (disallow-

ing a deduction for “excess” but not yet scrapped inven-

tory with the comment: “There is also no reason why

Thor should be entitled, for tax purposes, to have his

cake and eat it too.” ).

In asserting their right to take “partial abandonment”

losses, taxpayer refers us to the case of A.J. Industries,

Inc. v. United States, 503 F.2d 660 (9th Cir. 1974). But

we see nothing in that case which conflicts with the Tax

Court's decision. To be sure, the Ninth Circuit indicated

in AJ. Industries that the “subjective judgment of the

taxpayer . . . as to whether the business assets will in the

future have value is entitled to great weight... .” Id. at

670. But it did not say that a “business judgment” of

worthlessness obviated the need for an affirmative act of

abandonment. To the contrary, it referred to that re-

quirement as settled law. See id. at 670-72. And, it

upheld the challenged deductions (relating to the aban-

donment of a mine) because there was such an act (the

execution of a salvage contract). Id. at 674.

The decision of the Tax Court is vacated and the

cause is remanded for proceedings consistent with this

opinion.

C.A(1) Judgment

UNITED STATES COURT OF APPEALS

For tHe Finst Crincurr

No, 81-1840.

PAUL P. BROUNTAS, ET AL.,

Petitioners, Appellees,

v.

COMMISSIONER OF INTERNAL REVENUE,

Respondent, Appellant.

No, 81-1877,

PAUL P. anon LYNN T. BROUNTAS,

Plaintiffs, Appeilants.

v.

COMMISSIONER OF INTERNAL REVENUE,

Defendant, Appellees.

JUDGMENT

Entered September 28, 1982

This cause came on to be heard upon cross-appeals

from the United States Tax Court and was argued by

counsel,

Upon consideration whereof, It is now here ordered,

adjudged and decreed as follows: The decision of the Tax

Court is vacated and the cause is remanded for further

proceedings consistent with the opinion filed this day.

Each party to bear its own costs.

By THE COURT:

/s/ Dana H. Gatvup,

Clerk.

a

C.A.(1) Order Denying Rehearing A25

UNITED STATES COURT OF APPEALS

For THe Finst Cracuit

No. 81-1840

PAUL P. BROUNTAS, ET AL.,

Petitioners, Appellees,

v,

COMMISSIONER OF INTERNAL REVENUE,

Respondent, Appellant.

No, 81-1877

PAUL P. ann LYNN T, BROUNTAS,

Petitioners, Appellants,

v.

COMMISSIONER OF INTERNAL REVENUE,

Respondent, Appellee.

Before Corrin, Chief Judge, Camppett, Bownes &

Breyer, Circuit Judges, Permne*, District Judge.

ORDER OF COURT

Entered November 17, 1982

Upon consideration of the “Petition for Rehearing

or Rehearing En Banc”, which document was submitted

to the members of the panel and to the judges of the

Court who are in regular active service; and

F Of the District of Rhode Island, sitting by designation.

A26 C.A.1) Order Denying Rehearing

The judges of the panel having voted to deny the

petition for rehearing, and the judges of the Court who

are in regular active service having voted against the re-

hearing en banc,

It is ordered that said application for hearing en banc

is hereby denied.

By THE COURT:

Dana H. Gauwup, Clerk.

By: Francis P. Scigliano

Chief Deputy Clerk.

C.A(3) Opinion AQT

UNITED STATES COURT OF APPEALS

For THE Tuirp Cracurr

No, 82-3009

CRC CORPORATION,

Appellant

v.

COMMISSIONER OF INTERNAL REVENUE

No. 82-3010

CRC CORPORATION

v.

COMMISSIONER OF INTERNAL REVENUE,

Appellant

(Tax Court No. 8497-96 )

On APPEAL FROM THE UNITED STATES TAx Court

Argued: September 15, 1982

Before: Gipsons, Weis and SLoviter, Circuit Judges

(Opinion Filed: November 16, 1982)

THOMAS B. RUTTER, ESQ. (Argued)

THOMAS B. RUTTER, LTD.

872 Public Ledger Building

Philadelphia, PA 19106

Attorney for CRC Corporation

A28 C.A.(3) Opinion

GLENN L. ARCHER, JR.

Assistant Attorney General

MICHAEL L. PAUP

ANN BELANGER DURNEY

GEORGE L. HASTINGS, JR. (Argued )

Attorneys

Tax Division

Department of Justice

Washington, D.C. 20530

Attorneys for Commissioner

of Internal Revenue

OPINION OF THE COURT

Giszons, Circuit Judge.

The Commissioner of Internal Revenue appeals from

a decision of the United States Tax Court with respect

to the federal income tax liability of CRC Corporation

for the calendar year 1972. The taxpayer cross-appeals

from that decision to the extent that it disallowed deduc-

tion of certain abandonment losses. At issue in the Com-

missioner’s appeal is the tax treatment of deductions by a

limited partner in an oil and gas drilling partnership. The

Tax Court held that the deductions taken by the taxpayer

were proper under the law applicable in 1972.’ 73 T.C.

491.

We reverse that holding. The Tax Court also held

that the taxpayer could deduct abandonment losses for

abandonment of only parts of an oil and gas leasehold.

We affirm that holding.

The Tax Court decision which we review disposed

of the tax liability of CRC Corporation and that of

1. The deductions would now undoubtedly be improper. See

26 U.S.C. § 465 (Supp. IV 1980).

C.A.(3) Opinion A29

another limited partner, Paul P. Brountas. Brountas ap-

pealed to the Court of Appeals for the First Circuit,

which, on September 28, 1982, concluded that the Tax

Court erred in permitting the deduction of drilling ex-

penses in excess of the limited partner's actual investment

in the partnership, but did not err in disallowing claimed

abandonment losses. Brountas v. Commissioner, Nos. 81-

1840, 81-1877, Slip op. (1st Cir. Sept. 2, 1982). The

facts in Brountas are identical with those in this case.

In Gibson Products Co. v. United States, 637 F.2d 1041

(5th Cir. 1981), the court, dealing with a different

limited partnership, but a fact pattern otherwise indis-

tinguishable, reached the same conclusion with respect to

deductibility of partnership expenses in excess of a limited

partner’s investment.

Brountas, Gibson Products, and this case all involve

so-called leveraged leases. Under these arrangements

an oil and gas operator assembles a package of leasehold

interests, which he conveys to a limited partnership, for

a cash payment and a nonrecourse note secured by a

mortgage on the leaseholds and equipment used in re-

sulting wells. Simultaneously, the operator enters into a

fixed price no-out turnkey contract to drill wells, at no

further cost to the investors. The operator also simul-

taneously obtains a completion joint venture option under

which the operator can recover an interest in a completed

well by remitting to the limited partners a portion of the

cash consideration which they paid.

On its 1972 return this taxpayer and Brountas de-

ducted their pro rata share of expenses of the limited

partnership, in excess of their respective cash investments,

up to the full purchase price, including the nonrecourse

notes. There is no question but that a taxpayer which

has made a proper election may deduct all “intangible

drilling and development costs” in the year incurred. 26

A30 C.A(3) Opinion

U.S.C. § 263(c) (Supp. IV 1980); Treas. Reg. § 1.612-

4(a)(1965). Also, an accrual basis partnership can

accrue as an expense future fixed obligations. Such de-

ductions from income, for a partnership, flow through it

to the partners. Thus the limited partners contend that

they can deduct from other income losses resulting from

whatever expense the limited partnership may accrue.

The Internal Revenue Code, however, limits the

share of partnership losses a partner may deduct to the

amount of his basis in the partnership. 26 U.S.C. §§ 705,

722 (1976). Another provision of the Code states that

“[a]ny increase in a partner’s share of the liabilities of a

partnership . . . shall be considered as a contribution of

money.... 26 U.S.C. §752(a). The taxpayer is not

liable on the nonrecourse note. It contends, however, in

reliance on Crane v. Commissioner, 331 U.S. 1 (1947),

that when property is acquired subject to a nonrecourse

obligation secured by a mortgage on property acquired,

the mortgage is the equivalent of a personal obligation,

and the obligation will be recognized as part of the tax-

payer's basis. Alternatively, the taxpayer contends that

in any event 26 U.S.C. § 636 authorizes the contested

deduction because the nonrecourse note is a “production

payment that is carved out of a mineral property.”

The Tax Court rejected the taxpayer's argument

that 26 U.S.C. § 752(a) authorizes the deduction, holding

that Crane v. Commissioner does not apply to liabilities

that are both nonrecourse and essentially contingent.

Here, as a practical matter, the payment of the non-

recourse note is contingent upon the discovery of recover-

able amounts of gas or oil. The security is otherwise of

little value. The Brountas and Gibson Products courts

adopted the same position.

The Tax Court concluded, however, that 26 U.S.C.

§ 636 authorized the deduction. The court reasoned: (1)

C.A(3) Opinion A31

that the nonrecourse payments amounted to production

payments; (2) that under section 636 production pay-

ments are treated as loans; and (3) that treating the pay-

ments as loans from the operator, who expected those

loans to be paid, required that they be treated as liabilities

increasing the taxpayer's basis. The Brountas and Gibson

Products courts rejected this interpretation of section 636.

The essential flaw in the Tax Couii’s reasoning, recog-

nized by both courts, is that section 636 does not by its

terms make any change in the rule that speculative or con-

tingent liabilities may not be accrued and deducted.

The taxpayer’s cross-appeal presents a different issue.

It took a deduction for losses for abandonment of parts

of individual leaseholds. While leaseholds were not in

production the leasehold owners owed “delay rentals.” If

these payments ceased, the limited partnership presuma-

bly lost its leasehold interest. The leaseholds were, how-

ever, divided for drilling purpose into “horizons” or seg-

ments. When a test well produced a dry hole a geologist

would recommend whether to abandon the segment where

the dry hole was drilled or the entire leasehold. Deduc-

tions were taken for abandonment of some segments, even

though the entire leasehold was not abandoned . and the

limited partnership continued to pay delay rentals.

The Tax Court held that so long as the investors con-

tinued to pay delay rentals they still had the right to

explore all strata in the leasehold, and thus there was no

“intention to abandon coupled with an act of abandon-

ment.” Massey-Ferguson, Inc. v. Commissioner, 59 T.C.

220, 225 (1972) (emphasis supplied). The Brountas

court affirmed this finding.

The Brountas and Gibson Products opinions analyze

at length the two reasons relied upon by the taxpayer for

deductibility of the expenses of the limited partnership

represented by the nonrecourse notes. Brountas, more-

A32 C.A.(3) Opinion

over, discusses in detail the abandonment issue. The

appeals were argued before both courts hy the same at-

torney. Detailed treatment by us of any of these issues

would serve no useful purpose. It suffices to observe that

the Court of Appeals for the First Circuit properly dis-

posed of the companion appeal arising out of the same

trial record.

The decision of the Tax Court shall be affirmed as to

the issue appealed by the taxpayer, but reversed as to the

issue appealed by the Commissioner, and the case re-

manded to the Tax Court for further proceedings.

C.A(3) Judgment A33

UNITED STATES COURT OF APPEALS

For THE Tuirp Criacuit

Nos. 82-3009/82-3010

CRC CORPORATION,

Appellant in No. 82-3009

vs.

COMMISSIONER OF INTERNAL REVENUE,

Appellant in No. 82-3010

(T.C. No. 8497-76)

On APPEAL FROM A DECISION OF THE UNITED STATES

Tax Court

Present: Gispons, Weis and S.oviter, Circuit Judges

JUDGMENT

This cause came on to be heard on the record from

the United States Tax Court, ard was argued by counsel

on September 15, 1982.

On consideration whereof, it is now here ordered,

adjudged and decreed by this Court that the decision of

the said Tax Court in this cause be, and the same is hereby

affirmed with respect to the issue appealed by the tax-

payer and reversed with respect to the issue appealed by

the Commissioner and the cause remanded to the said

Tax Court for further proceedings.

ATTEST:

/s/ M. Evizapetu Fercuson

Chief Deputy Clerk

November 16, 1982

A34 C.A.(3) Order Denying Rehearing

UNITED STATES COURT OF APPEALS

For THE THirp Circuit

Nos. 82-3009 and 82-3010

CRC CORPORATION,

Appellant

vs.

COMMISSIONER OF INTERNAL REVENUE

SUR PETITION FOR REHEARING

Present: Serrz, Chief Judge, Avoisent, ADAMS, G1BBONS,

Hunter, Weis, GARTH, HiGGINBOTHAM, SLOVITER

and Becker, Circuit Judges

The petition for rehearing filed by appellant CRC

Corporation in the above entitled case having been sub-

mitted to the judges who participated in the decision of

this court and to all the other available circuit judges of

the circuit in regular active service, and no judge who

concurred in the decision having asked for rehearing, and

a majority of the circ’.’+ judges of the circuit in regular

active service not having voted for rehearing by the court

in banc, the petition for rehearing is denied.

By the Court,

/s/ Joun J. Grepons

Judge

Dated: Dec. 10, 1982

Tax Court Opinion A35

73 T.C. No. 42

UNITED STATES TAX COURT

PAUL P. BROUNTAS and LYNN T. BROUNTAS,

Petitioners

v.

COMMISSIONER OF INTERNAL REVENUE,

Respondent

CRC CORPORATION,

Petitioner

v.

COMMISSIONER OF INTERNAL REVENUE,

Respondent

Docket Nos. 8231-76, 8497-76

8698-77, 6255-78 '

Filed December 26, 1979.

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 geol-

ogy 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 lease-

1. These cases have been consolidated for purposes of trial,

briefing and opinion as to the issues decided herein.

A36 Tax Court Opinion

hold 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 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 respon-

sibility 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 section 636 and Regulations sec-

tion 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 inclucible, in the case of partnership purchases, in

the basis of the partners’ partnership interest, as liabilities

under section 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

of the notes at face value for purposes of section 752(c).

Tufts v. Commissioner, 70 T.C. 756 (1978), on appeal

(5th Cir., Apr. 23, 1979), followed.

Tax Court Opinion A37

Held, further, the partnerships were entitled to de-

ductions for intangible drijling 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 obliga-

tion, under Regulations section 1.636-1(a)(3), Example

1.

Held, further, respondent properly disallowed de-

ductions 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 inter-

ests were acquired from the operators by purchase and

not by lease.

Held, further, respondent properly disallowed de-

ductions 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 aban-

donment losses of capitalized leasehold acquisition ex-

penses of unproductive leases for periods 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 indebted-

ness income generated in the case of nonrecourse indebt-

edness secured only by non-productive leaseholds.

A38 Tax Court Opinion

Thomas B. Rutter, for the petitioners.

Bernard Nelson, M. Kevin Phalin, David Johnson and

Bob Hollohan, for the respondent.

Hatu, Judge: Respondent determined deficiencies,

plus additions to the tax for fraud under section 6653(b )*

and accumulated earnings tax under section 531, as

follows:

Docket

Petitioner Year No. Defwiency = J 531 J 6653(b)

Paul & Lynn

Brountas 1972 8231-76 $ 6,283.35 $ none $ none

Paul & Lynn

Brountas 1973 6255-78 19,006.43 none none

CRC Corporation 1972 8497-76 238,826.00 152,485.00 195,656.00

CRC Corporation 1973 8698-77 272,821.00 none 136,411.00

Petitioner Paul Brountas was a limited partner in a

“leveraged” oil and gas drilling venture (“Coral I”), and

petitioner CRC Corporation (“CRC”) was both the gen-

eral partner and a limited partner in Coral I and in an-

other “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 considera-

tion (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 deduc-

tions 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,’ the issues

for decision at this time are:

2. All statutory references are to the Internal Revenue Code of

1954, as in effect during the years in issue.

3. The following adjustments in the notices of deficiency have

been severed for trial at a later date:

Tax Court Opinion A39

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 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 inter-

ests. 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 basis, 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 non-

recourse notes.

3. Whether Coral I, Coral II and CRC are entitled to

claimed deductions for advanced royalties.

4. Whether Coral I and Coral II are entitled to

claimed deductions for management fees.

3. (Cont'd. )

Petitioner Docket No. Adjustments severed

Paul & Lynn

Brountas 8231-76 No adjustments severed

Paul & Lynn

Brountas 6255-78 Adjustment (a) (re Special 342-1973

Drilling Venture 1)

CRC Corporation 8497-76 Accumulated earnings tax

CRC Corporation 8698-77 Adjustments (d), (e), (f), (g), (i),

and section 6653(b) addition to tax

A40 Tax Court Opinion

5. Whether Coral I, Coral I1 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.

7. Whether any part of petitioner CRC’s underpay-

ment of tax for 1972 was due to fraud.

FInpINGs 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, Massachusetts. Lynn

Brountas is a party solely by virtue of the fact that she

filed joint returns with her husband Paul Brountas (here-

inafter Brountas ) for the years in issue.

Petitioner CRC Corporation (“CRC”) is a Delaware

corporation. At the time it filed its petitions, CRC’s prin-

cipal office was located in Jenkintown, Pennsylvania.

Brountas was a limited partner in Special Coral 1972

Drilling Venture I (“Coral 1”) during the years in issue.

During these years, CRC was both the general partner

and a limited partner in Coral I and in Special Coral 1972

Drilling Venture If (“Coral If’). Coral I and Coral Il

are duly .rganized 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

4. By order dated December 26, 1979, we have requested

supplemental briefs from the parties with respect to this issue,

which will be addressed in a supplemental opinion.

Tax Court Opinion A4l

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 per-

cent 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.

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 of CRC,

and the oil and gas industry in general will assist in under-

standing 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, Texas, and Jenkintown,

Pennsylvania. Scoggins headed the office in Corpus

Christi, and he was responsible for the selection of attrac-

tive 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 Geo-

A42 Tax Court Opinion

Dynamics Oil and Gas, Inc. (“GeoDynamics”) which

acquired the assets of GeoDynamics Investors, Ltd. in ex-

change for its stock. Concurrently, the partnership, Geo-

Dynamics Investors, Ltd. was dissolved. After this ex-

change, 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 geo-

graphical 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 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 sufficient funds of its own, will attempt to have

the cost of drilling a test well on the prospect paid for by

others.” 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.

5. An operator would prefer to use its own money to drill

prospects, since it would then have a larger interest in the property

if successful. As a practical matter, however, most operators do

not have the financial resources to fund their own exploratory

drilling.

Tax Court Opinion A43

Once financing has been obtained, the next step is

the drilling of the prospect. The drilling is usually per-

formed 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."

There is no “standard” financing arrangement by

which an operator and outside investors develop a pros-

pect; 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.’ 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 person (other than

the operator) would put up one-third of the drilling cost

and would receive a one-quarter interest in the well. The

operator's quarter interest in the well is its reward for

6. For this reason, operators are loath to sell their entire in-

terest in a prospect they have created; in contrast, lease brokers

obtain leases, sell them, and profit thereby.

7. For an explanation of these different interests, see F. Burke

& R. Bowhay, Income Taxation of Natural Resources par. 2.01-2.08

(1979).

A44 Tax Court Opinion

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 Corporation and Intramerican Drilling Fund

1969 (“Intramerican Fund”). Intramerican Fund was a

Pennsylvania partnership organized for the purpose of in-

vesting in oil and gas exploration. In its operations with

Intramerican Fund, GeoDynamics provided the people

who ran Intramerican Management Corporation (“In-

tramerican Management” ), which acted as a general part-

ner for Intramerican Fund. GeoDynamics owned 49 per

cent 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 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 speci-

fied unfavorable conditions are reached. Among the con-

ditions usually specified in a Gulf Coast Clause are high

or low pressure, impenetrable subsurface formations, loss

of mud circulation * and salt.

oe a ee eee - 2 ~~ ae een ms =e a wee ee eee _ — -— -

8. Loss of mud circulation refers to the drilling mud which is

pumped down the drilling pipe, through the bit, and returns along

the walls of the shaft of the drilled hole. The mud simultaneously

cools the drilling bit, removes drilling cuttings and seals the walls

of the shaft.

Tax Court Opinion A45

For example, if a high pressure subsurface area is

encountered, a “blow out” can result. If a blow out occurs

the well can easily catch on fire; in any case, consider-

able amounts must be spent to bring the well under con-

trol. Off-shore the costs and dangers are multiplied.

(The record does not disclose whether any of the pros-

pects in issue were offshore.) On the other hand, if a

low pressure subsurface area is encountered, the well can

“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 mil-

lion 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 va-

rious operators for the purpose of conducting exploration.

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 Re-

A46 Tax Court Opinion

sources Corporation (“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.” 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 indus-

try in which the operator served as the general partner.

Soter felt that Comprehensive could better serve the in-

vestors’ interests.'”

Soter and Dauber incorporated in the partnerships

two other important changes in the format of oil and gas

exploration programs.'' 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

9. Prior to this time, most oil and gas exploration was con-

ducted through joint ventures, although some groups (such as

Intramerican) had begun to use the limited partnership format.

10. In pre-1970 ‘transactions using limited partnerships, the

operator usually served as the general partner. The operator would

both raise money from outside investors and drill the well. If

drilling difficulties were encountered, the operator would request

additional funds from the limited partners. If no additional funds

were forthcoming, the investors could be left with an uncompleted

well, There existed a potential for a conflict of interest for the

operator, since he represented both himself (in drilling) and the

investors (who were paying).

11. These changes were devised jointly since Comprehensive

and GeoDynamics were functioning as co-general partners at this

time.

Tax Court Opinion A47

eliminated. From the investor's (limited partner's) point

of view this was important since the investor was guaran-

teed (to the extent of the operator’s assets) that all wells

which were contracted for would be drilled regardless of

difficulties encountered and, moreover, that the investor

would not have to contribute additional drilling funds.

All the financial risks of drilling were placed on the oper-

ator. 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 was illustrated by the

Boyken Church Prospect which Patrick Petroleum Com-

pany 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 three times. The first time the well was drilled,

there was a blow out when a high pressure reservoir was

encountercd. 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 paid to the operator for the no-out

turnkey drilling contract was represented by a non-

recourse note. The importance of leverage in these trans-

actions 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, al-

lowing the promoters to hold out the expectation to poten-

tial limited partners of deductions beyond the cash con-

tributed.

A48 Tax Court Opinion

In 1970 Comprehensive and GeoDynamics formed

limited partnerships employing this format. A limited

partnership (with Comprehensive and GeoDynamics as

co-general 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 con-

tract obligated the operator to furnish to the limited part-

nership 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 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, usu-

ally by an electronic (sic) induction log. This log fur-

nishes information on the basis of which a decision is made

whether to complete the well. If the Jogs 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 part-

nership 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 lim-

ited partnership would then reconvey the amount “bor-

rowed” ($71,000) to the operator in payment of the un-

puid 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 produc-

tion.'* The note was cross-collateralized, that is, was pay-

12. The partnerships would also “borrow” 71 percent of the

lease purchase price. The note also covered this amount, so the

Tax Court Opinion A49

able out of any production from several prospects, rather

than one.

In addition, as part of the package of rights trans-

ferred 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 comple-

tion option entitled the operator, after casing point had

been reached, to complete the well and pay all costs re-

lated thereto.” In return, the operator received an in-

terest in the mineral property equal to the ratio of com-

pletion costs to total drilling costs (completion plus drilling

to casing point) actually incurred.'* For example, if total

12. (Cont’d.)

operator received for the leases which it conveyed to the partner-

ship 29 percent of the lease purchase price in cash and the remain-

ing 71 percent of the lease purchase price via the note.

13. Completion costs are costs incurred after an apparently

productive well has been drilled and logged. They include, inter

alia, the cost of production pipe (called casing pipe, which is dif-

ferent from drilling or protective pipe) and surface facilities neces-

sary to place a well under production. The cost of completion

after casing point is often as much as 40 per cent of the total cost

(through completion) of a test well. In other words, if the cost of

drilling to casing point and testing a well were $60,000, completion

might cost an additional $40,000. When a decision to attempt com-

pletion is made on the basis of information obtained from the elec-

tronic logs, there is no guarantee that a commercially productive

well will result. For example, fresh water produces test results

identical to oil and gas, so a well can be completed and produce

only fresh water. Additionally, even if oil or gas is present, the

pressure or the quantity of minerals may be insufficient to justify

production. In short, the completion option gave the operators a

chance to earn an interest in the well, but there were considerable

risks of loss attached.

14. Specifically, if the operator elected to complete, a “com-

pletion joint venture” would be formed and the operator's and the

partnership's respective interests in the well would be determined

by their partnership interest, which was established by this formula,

—

A50 Tax Court Opinion

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 comple-

tion costs from production (“pay out”), one-quarter of

the operator’s interest so earned would revert to the in-

vestors under a so-called “back-in.” In the above example,

one-quarter of the operator’s 40 percent interest—10 per-

cent 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 in-

vestors’ interest, calculated after the operator exercised

the completion option but before the back-in. Using the

above example, under the completion option the oper-

ator’s and investors’ interests were, respectively, 40 per-

cent and 60 percent of production. If the operator exer-

cised 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. Accord-

ingly, 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 pay out one-quarter of the interest which

the operator received under the completion option, or 10

percent of production, would revert from the operator to

the investors. In this example, the interests of the oper-

ator and the investors would thus become after pay out 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 con-

version right and a completion option. As consideration,

tke operator undertook a no-out turnkey drilling contract,

with its attendant risks.

Tax Court Opinion A51

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 with-

out 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, Louisiana (“McMoRan”) was a major

one. Scoggins and McMoRan, for example, followed a

basic pattern in which McMoRan’s estimated turnkey

price was increased 20 per cent over a “Gulf Coast” con-

tract 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 per-

cent 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 partner-

ships, in oil and gas exploration projects with various op-

erators. 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 three 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 incom-

A52 Tax Court Opinion

petence and dishonesty, and gave Scoggins’ position to

Bill Floyd, who had worked as an exploration manager

for Gulf Oil Company before he joine¢d GeoDynamics in

1969. Second, in late 1970 a new corporation, Geo-

Resources Management Corporation (“GeoResources” )

was formed. The stock of GeoResources was owned

equally by GeoDynamics and Comprehensive. Geo-

Resources was formed to function as the general partner

in future publicly-offered leveraged drilling funds."

Third, in July 1971 CRC was organized to effect a busi-

ness combination. CRC acquired all of the outstanding

stock of Comprehensive and GeoDynamics, each of which

owned 50 per cent 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 re-

ferred to collectively as CRC, irrespective of which cor-

porate 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.’” First, the conversion right

with respect to the note was climinated. Second, the

completion right was changed so that the interest in the

well earned by the completing operator was no longer

15. In 1970 the limited partnerships were not “publicly offered”

and were not registered with the Securities and Exchange Com-

mission. In contrast, beginning in 1971 GeoResources functioned

as the general partner for drilling funds for which prospectuses

were registered with the SEC.

16. Since the 1972 contract format, which was very similar to

the 1971 format, is explained in detail infra, we set forth only a

rough description of the changes at this point. Minor changes are

not detailed here. A more detailed examination of the 1970 and

1971 programs is not necessary since they merely provide back-

ground for the 1972 program which is in issue in this case.

Tax Court Opinion A53

determined by the ratio of completion expenses to total

expenses, but became a fixed percentage—usually 40 per-

cent.'". 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 con-

tract price, with the remainder of the price represented by

the nonrecourse note.'* This increased cash was ap-

parently 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 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. Invest-

ment capital totaling approximately $25 million was placed

through two registered limited partnerships, Geo-

Resources Drilling Fund 1972 Annual Program and

GeoResources Drilling Fund 1972 Year End Program.

Additional investment capital totaling approximately $10

million was raised and placed in 1972 through twenty

unregistered limited partnerships, including Coral I and

17. This change simplified the determination of each party's

interest upon completion, since an exact accounting of the amounts

expended was not necessary. It also guaranteed that the operator

could not, due to the completion option, earn a larger interest in

the well than the partnership had.

18. Apparently 40 percent of the lease purchase price was also

paid in cash, with the remainder of the lease price represented by

the nonrecourse note.

A54 Tax Court Opinion

Coral II. CRC served as the general partner for Coral I

and Coral II.

In 1972 CRO, either on its own behalf or on behalf

of the limited partnerships (such as Coral I and Coral II),

entered int. 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 oper-

ator. 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 pack-

ages was generally shared by various limited partnerships.

A limited partnership invested in many packages, receiv-

ing 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 II in 1972:

Coral I Coral Il

Package Partnership Partnership

Number Name of Operator —_ Participation Participation

72-1 McMoRan ( Elpac ) 3395 A405

2 Powers (Poco) 11632 11788

3 Western States 38517 39033

4 McMoRan ( Elpac) 38517 39033

5 McMoRan ( Elpac) 38517 39033

6 McMoRan (Elpac) 38517 39033

7 McMoRan (Elpac) 0516 .0520

8 Gibraltar ( Elpac) 0516 0520

9 Dynamic 0516 0520

10 Emerald 0779 0785

ll Gibraltar ( Elpac) 0779 0785

12 McMoRan (Elpac) 0779 0785

Tax Court Opinion A55

Coral I Coral Il

Package Partnership Partnership

Number Name of Operator __ Participation Participation

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 MeMoRan (Elpac) .0097 .0088

32 Patrick .0188 0172

96 Arriba .0169 0172

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 CRC

Number Name of Operator Participation

72-35 Emerald .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 aos 0394

72 McMoRan ( Elpac) 0401

75 Nor-Am 0394

76 acoupies 0394

77 McMoRan ( Elpac 0042

78 McMoRan ( Elpac 0401

79 McMoRan ( Elpac 0401

80 McMoRan ( Elpac 0401

A56 Tax Court Opinion

Package CRC

Number Name of Operator Participation

81 McMoRan Epes} 0401

82 McMoRan ( Elpac 0401

83 McMoRan (Elpac) .0401

84 McMoRan tee 0401

85 McMoRan ( Elpac 0401

86 Tech-Sym .0394

87 McMoRan 0401

88 Gibraltar ( Elpac) 0401

2. The “Standard” Package. The transactions which

CRC and the limited partnerships entered into, as well as

the documentation thereof, were standardized to a signifi-

cant degree.'” 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 oper-

ator agreed to drill a test well on each prospect at a speci-

fied location to a specified depth. The operator's obliga-

tion 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 per-

form 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

19. A major exception—the transactions involving Elpac—is

discussed infra.

Tax Court Opinion A57

encountered. If any well were a dry hole, 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 agree-

ment 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 part-

nership an agreed-upon sum to be used by the partner-

ship 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 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 con-

tract were $100,000, the loan (hereinafter the “note por-

tion”) 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 part-

nership by the operator bore interest at the rate of 6%

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 evi-

denced by the Note and secured by the Mortgage. The

collateral for the debt was set forth in the Loan Agree-

ment. In a typical Loan Agreement, the collateral for

the debt was as follows:

Tax Court Opinion

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 succes-

sors and assigns, under the agreement; and,

(ii) 75% of all personal property and equipment

in, on, used in connection with, or attribut-

able to such rights, titles, properties and

interests; and,

(iii) 534% of 75% of the production from and

attributable to all of borrowers rights, titles,

properties and interests ° ° ° , and the pro-

ceeds thereof; ° ° °

subject, however, to the terms and provisions of any

instruments or agreements referred to or described in

the Agreement which affect such rights, titles, prop-

erties 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 Mort-

gage, 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 con-

tinue until such indebtedness is fully paid, or until

Tax Court Opinion A59

the maturity date of such note or notes if such in-

debtedness 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 per cent 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.*” The Loan

Agreement expressly provided that the borrower ( partner-

ship) 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 pro-

duced from (or out of the sale of ) any and all leaseholds

or other rights and property interests subject to the mort-

gage; they were not selectively payable out of the oil and

gas produced from (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 twenty-four hours after a well

20. For example, in one package the collateral was 534% of

75% of production (or 40%) for two wells, while the collateral for

the third well was 66%4% of 75% of production (or 50%).

A60 Tax Court Opinion

on a prospect had been logged and tested. The comple-

tion 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 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, production

casing, and any costs if the well were to be plugged and

abandoned.” It also had to indemnify and hold harmless

the Investors from any and all costs, expenses and liabili-

ties 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. Finally, it was to reimburse the Investors

for all tangible equipment installed in the wel! 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

costs were to be borne by the parties to the joint venture

in the same ratio (ie., 40 percent by the operator, 60 per-

cent by the Investors). If the completion attempt failed

21. The joint venture for subsequent development wells, if re-

quired, was based on different terms discussed infra.

22. This amount would be the lease purchase price for the

prospect, as set forth in the Lease Purchase and Turnkey Drilling

Agreement, less the portion of the loan which was allocable to the

lease. The operators repaid the Investors the amount of cash con-

tributed by the investors towards the purchase of the lease. The

operators also cancelled the portion of the debt which related to

the lease purchase price.

Tax Court Opinion A61

to produce a commercial well, the completing operator

would be entitled to all equipment on the property. Addi-

tionally, 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% percent of 75 percent of the Investors’

interest, or 40 percent of production. If the Investors

received the Joint Venture Agreement a 60 percent inter-

est 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 accord-

ingly.

All of the above terms and conditions were contained

in the basic documentation executed for each package.

Additional terms regarding the parties’ rights after “pay

out,” which is the point at which the operator has recov-

ered from his share of production all of his costs incurred

in conipleting a well, were contained in further, concur-

rently executed agreements. Prior to pay out the partner-

ship and the operator usually divided revenues according

to a 60/40 ratio; *" the general partner (CRC or its sub-

sidiary ) was not entitled to any share of the partnership’s

share of production. After pay out, several changes oc-

curred. First, in both the registered and unregistered

limited partnerships the general partner became entitled

to % of a partnership’s share, of 15 percent of production.

22a. Of course, the limited partners’ share was subject to pay-

ment of the nonrecourse note. As a result of the collateral substi-

tution described above, the repayment would usually require 24

percent of revenues.

A62 Tax Court Opinion

Second, in the registered limited partnerships, the general

partner also became entitled to % of the operator’s in-

terest under the Joint Venture Agreement, or 13’ per-

cent of production.” The unregistered limited partner-

ships 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 % of the interest of other

operators. The share of one of the largest operators,

McMoRan, was subject to a % back-in. The operator's

share thus taken by the limited partners would be subject

to the general partner's % share.

The following charts illustrate the shares taken by

the various parties in this contractual framework, both

before and after pay out 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 lim-

ited partnership in which the limited partners were not

entitled to a portion of the operator’s interest after pay

out, (3) an unregistered limited partnership in a McMo-

Ran package, and (4) an unregistered limited partnership

in which the limited partners were entitled to % of the

operator's interest after pay out:

23. This shift after pay out is called a “back-in.”

Relative percentages Relative percentages

of revenue of revenue

Recipient ___ before payout after payout

Before After Before After

payment of paymentof payment of payment of

nonrecourseé nonrecourse nonrecourse nonrecourse

Notes Notes Notes _ ___Notes_

(1) aregistered limited partners 36% 60% 27% 45%

limited general partners 0% 0% 221% 281%

partnership operator 40% 40% 264% 2654%

operator/lender ** 24% 0% 24% 0%

(2) unregistered limited partners 36% 60% 27% 45%

limited partnership general partners 0% 0% 9% 15%

with no operator 40% 40% 40% 40%

back-in operator/ lender 24% 0% 24% 0%

(3) unregistered limited partners 31% 55% 25 27% 45%

limited partnership _ general partners 0% 0% 9% 15%

with % operator 45% 45% 40% 40%

back-in (i.e., operator/lender 24% 0% 24% 0%

McMoRan)

(4) unregistered limited partners 36% 60% 367%4% 55%

limited partnership general partners 0% O% 12%% 184%

with 4% operator 40% 40% 267% 2674%

back-in operator/lender 2A% 0% 24% 0%

24. The interests of the operator and the operator/lender are shown separately due to the Elpac trans-

action discussed infra.

25. The investor/operator ratio for McMoRan was 55/45 rather than the standard 60/40 ratio.

uouidg j4N0D xv],

cov

A64 Tax Court Opinion

The above discussion of costs and percentages of pro-

duction in the joint venture refers only to the initial test

well on each prospect. If the initial test well were success-

ful and if additional development wells were required,

both the expenses of and production from such develop-

ment wells were usually shared in a 70/30 ratio; the In-

vestors 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, aii the income from the development wells was

subject to the lien of the nonrecourse Notes, so the In-

vestors’ shares would be reduces) accordingly.” In ad-

dition, the partnership income from the development wells

was also subject to reallocation among the partners after

pay out. In both the registered and unregistered limited

partnerships, the general partner was entitled to 4 of the

limited partners’ share of production, or 17.5 per cent,

after pay out. Additionally, at least in the registered

limited partnerships, the general partner (CRC) was also

entitled to '4 of the operator’s share of the production

from development wells after pay out.

3. Negotiation and Closing of Transactions in the

1972 Program. Bill Floyd represented the limited partner-

ships and CRC in negotiations with the operators in 1972.

As various operators became aware of CRC’s drilling pro-

gram," they brought to Floyd so-called prospect data

sheets. A prospect data sheet normally provided a pros-

pect’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

26. E.g., if the Note was to be paid : from 40 per cent of the

Investors’ share of production, the holder of the Note would receive

28 per cent of production.

27. The operators usually became aware of CRC through word-

of-mouth within the oil and gas industry.

Tax Court Opinion A65

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 rec-

ords, 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 ex-

pected 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 pros-

pect. Floyd’s review involved study of the geological

maps, seismic data, etc., submitted with each prospect.

As a consequence of this review, Floyd accepted, as to

geology, only 5 to 10 per cent 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 pur-

chase price and the cost of the no-out turnkey drilling con-

tract, 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 approxi-

mately 30 per cent of the prospects approved geologically.

When Floyd negotiated prices with the operators, he

did not receive an anticipated cost breakdown from the

various operators.*" The operators believed that the

method by which they priced prospects was solely their

28. In the oil and gas industry, these cost breakdowns are

normally referred to as authorizations for expenditure, or AFE’s.

Floyd did not receive AFE’s from the operators.

A66 Tax Court Opinion

concern, not Floyd’s. The operators were aware, how-

ever, 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 transac-

tions 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

costs, 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 per-

cent 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 In-

vestors.”” Of course, if problems arose in drilling a well,

such as a blow out or an encounter with impenetrable

material, it was unlikely that the cash portion would suf-

fice to cover the operator's costs. Additionally, none of

the operators expected the cash portion of the contract

rrice to cover their costs if a completion were attempted.

There was no established pattern by which the vari-

ous operators determined the lease purchase prices, but

the operators all believed they were entitled to a consid-

erable markup on the leases. The operators made sub-

stantial investments in the leases before they were con-

veyed to the partnerships, including a geological workup

29. At least one operator, Buttes Gas and Oil, calculated its

total contract price as set forth on the prospect data sheet under a

formula which made it unlikely that the cash portion would cover

its cost and yield a profit. Buttes, however, did hope to recover its

out-of-pocket costs from the cash portion.

Tax Court Opinion A67

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

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 re-

garding 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 rea-

sonable.” 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 con-

tract 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 length.” In each case the terms were

commercially negotiated and were within a reasonable

range of commercial practice. Due to the apparent pau-

city 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 ex-

cessive compensation for the added risk. There was much

sincere testimony that the price was fair even without re-

30. When, in rare instances, Soter negotiated on behalf of

CRC, he followed a similar negotiation policy.

A68 Tax Court Opinion

gard to the contingency, but due to lack of comparable

deals, such testimony was largely conclusory in nature.

However, at least when the nonrecourse Note is dis-

counted for its contingent payability, it is clear that con-

siderations on both sides for the drilling terms were com-

mercially 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 drill-

ing 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 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 In-

vestors 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 com-

pletely in cash * but without the completion rights. More-

over, at least two” of the operators did not consider the

31. E.g., the operator would receive $100,000 in cash, rather

than $40,000 in cash plus a note for $60,000, but no completion

rights.

32. Only two operators (one of whom was a witness called by

respondent) directly addressed this question. Another operator

believed that the notes were important, but he did not specifically

consider whether he would have entered into a transaction without

the notes. A fourth operator, called as a witness by respondent,

Tax Court Opinion A69

transaction acceptable if they received only the cash por-

tion plus the completion rights, but not the Note.”

In trades in the oil field, operators regularly demand

large markups over their estimated cost. This was par-

ticularly 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. More-

over, because CRC was the moneyed party, Floyd 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 the drilling contract via a

nonrecourse note because of this bargaining position. The

operators were primarily concerned that the entire con-

sideration which they received from CRC—cash, the Note

and the completion option—was fair and reasonable com-

pensation 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." After CRC

32. (Cont’d.)

also stated that the notes were of value to him and that he wanted

the notes as part of the transaction. On the other hand, in the

Elpac transactions, discussed infra, some operators gave up the

notes to a third party who assumed some of the risks of the no-out

drilling obligation.

33. E.g., the operator would have received $40,000 in cash

plus the completion rights, but not the $60,000 note.

34. These letters also served as verification to CRC’s auditors

that the prices paid were fair and reasonable.

A70 Tax Court Opinion

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 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 terrns 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 ap-

proval. 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. 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 $100,000, went through the following steps.

First, the operator would obtain, usually through a one-

day loan from a bank, the note portion (¢.g., $60,000)

of the contract price. The operator would then “loan”

this $60,000 to the partnership; in return, the operator

Tax Court Opinion A7l

would receive the Loan Agreement, the Note, the Mort-

gage and the Joint Venture Agreement. Next, the opera-

tor would deliver the Lease Purchase and Turnkey Drill-

ing 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.” 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 obliga-

tion.

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 ac-

countants 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 fol-

lowed 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 be-

lieve that either the check swap or the “loan” format had

any cconomic significance, nor did it; this form was fol-

lowed merely to satisfy its accountants. CRC understood

that, in substance, it was giving the operator the cash

35. In the transactions involving CRC and Emerald Petroleum

or Emerald Producing, the operators did not follow this pattern in

that the operators never “loaned” money to the Investors. Rather,

the operators simply received the nonrecourse Note, the Mortgage,

the Loan Agreement (including the completion option) and the

cash, and gave to the partnership the leases and the no-out turnkey

drilling obligation.

A72 Tax Court Opinion

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 CKC in the traditional sense.

The operators were aware that, in substance, they received

the cash portion of the toial contract price plus the non-

recourse 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.” Normally the holder of the

production payment has no right to foreclose on the prop-

erty if not paid; in this case, the holders (i.e., the opera-

tors) 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."’ 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. Ac-

cordingly, 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

36. For tax purposes, “production payments” are defined in

section 1 636-3, Income Tax Regs.

37. Security for the Note was a perce:.tage (usually 75% of

the Investors’ mineral interest plus a percentage (usually 75%) of

the value of the equipment remaining on the prospect. If a pros-

pect yielded a dry ho'e, both this equipment and the mineral inter-

est were of minimal, if any, value. If a completion were attempted,

the equipment on the prospect would have value, but under the

Joint Venture Agreement the completing operator had the first

lien on this equipment.

I —

Tax Court Opinion A73

completion option) for the leases and their no-out turn-

key drilling obligation.”

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” * role in the transaction. The transactions in

which Elpac participated involved three operators—

McMoRan, Gibraltar Oil Corporation (“Gibraltar”) and

Sinclair Development Company (“Sinclair”).

Elpac was a publicly-held California corporation. In

1969 and 1970 it underwent a reorganization in bank-

ruptcy, and as a result F. 1. 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 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, Cap-

paert 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 McMo-

38. The operators were bullish on their prospects. They ex-

pected to be paid on these Notes and they expected such payment

to be made from the reserves found. If reserves of the magnitude

set forth on the prospect data sheet were discovered, it was likely

that the Notes would be paid before exhaustion of the reserves.

38a. The “lender” is the party who receives the nonrecourse

Note used in these transactions.

A74 Tax Court Opinion

Ran decided it did not want to act as the lender in its

transactions with CRC, although it still wanted to do busi-

ness 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 non-

recourse Notes. Accordingly, in order to continue work-

ing 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 ar-

rangement under which Elpac agreed to be the “lender”

in transactions with CRC. Elpac entered into the trans-

actions not for the benefit of McMoRan but, rather, for

its own benefit.”” 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 operat-

ing loss carryover company could afford to acquire these

nonrecourse Notes, since receipt of the Notes was be-

lieved to generate substantial income for income tax pur-

poses without generating cash to pay those income taxes.

Accordingly, Elpac believed that acceptance of the Notes

would enable it to participate in the exploration program

of a successful operator, McMoRan, and benefit from

39. CRC played no role whatsoever in the introduction of

Elpac into these transactions.

Tax Court Opinion A75

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 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 indistinguish-

able from the agreements entered into with other op-

erators.“” After McMoRan and CRC reached an agree-

ment, 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 con-

tract 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 comple-

tion 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 there-

under, McMoRan (which was obligated to drill the test

40. In at least one Elpac transaction the operetor’s share under

the Joint Venture Agreement was based on a ratio of costs incurred

similar to the ratio used in the 1970 drilling program.

A76 Tax Court Opinion

wells) had received the cash portion of the Lease Pur-

chase and Turnkey Drilling Agreement price plus the com-

pletion 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” trans-

action. As in the “standard” transaction, in the Elpac

transactions the lease purchase and drilling contract terms

were within a reasonable range of commercial practice.

Elpac was required by a separate agreement with

McMoRan to share with McMoRan any cost overruns."

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 per

cent of such excess. In essence, even through McMoRan

promised to drill the wells for Elpac, Elpac still had sub-

stantial risk, including particularly its promise to share

any cost overruns with McMoRan and Elpac’s total liabil-

ity 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 drill-

ing 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 induc-

tion electric log. In contrast, Elpac’s agreement with

41. Originally, Elpac did not agree to share any cost overruns.

In 1972, however, the agreements between Elpac and McMoRan

were modified to provide for such sharing. This change was made

at the request of CRC. This change was made to conform to

CRC’s belief that the Elpac-McMoRan agreement provided for cost

sharing rather than constituting a double turnkey.

cot ERD

Tax Court Opinion AT77

CRC not only required Elpac to drill the well but, addi-

tionally, specified in great detail the site preparation,

environmental costs,‘ related drilling costs, etc. which

Elpac was required 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 ob-

ligation 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 drilling agreement with

CRC and then brought Elpac into the transaction.” 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 was one

substantial modification in the Gibraltar and Sinclair deals.

In addition to assigning the completion rights to those op-

erators, Elpac also assigned to them a production pay-

ment, usually equal to 15 per cent of the note portion of

the total contract price, which was payable out of receipts

4la. These environmental costs included all crop and surface

damage. Additionally, if any problems were encountered in drill-

ing a well, the environmental costs could be enormous, particularly

if the well were offshore. The record does not disclose whether

any Elpac wells were offshore.

42. As in the Elpac-McMoRan transactions, it was the opera-

tors, not CRC, who contacted Elpac. Elpac was introduced to

Sinclair and Gibraltar by individuals connected with McMoRan.

A78 Tax Court Opinion

production payment which it gave to Gibraltar and Sin-

clair 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 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 busi-

ness 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

Company (“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 pro-

posed that it retain a 1/16th working interest for bearing

1/16th of the costs. In other words, Kiowa could obtain

15/16th 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;

Tax Court Opinion A79

TNT reserved the protections of a Gulf Coast Clause.

Taylor believed this was a minimal price, but he pro-

posed 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 litile money

in 1972. In order to obtain funds to test the Singer pros-

pect, Freel contacted CRC and negotiated with it.’ 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 arrange-

ment. Charles Stokley, an independent petroleum engi-

neer, issued a credible albeit conclusory opinion that the

price was fair, and there was no credible evidence intro-

duced 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 be-

tween Freel and Taylor. At first Taylor objected, but

eventually he agreed to dril! the well on a “no-log, no pay

contract” basis for $75,000." Taylor was willing to ac-

43. Taylor played no part in the negotiations with CRC; he

was not aware of the terms of the agreement negotiated by Freel

and CRC. Taylor's only contact with CRC was at the closing for

this transaction. Taylor did not originally attempt to contract

directly with CRC because he knew that CRC did not know who

he was; later, after Freel contacted CRC, Taylor believed that it

would have been unethical for him to deal directly with CRC.

44. A no-log, no-pay contract is different than a no-out turnkey

contract; in a no-log, no-pay contract the operator can simply walk

away from the prospect and not get paid, while in a no-out turnkey

A80 Tax Court Opinion

cept 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 sat’sfy this drilling con-

tract 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, and could

not drill the well, and [Freel] did not pay [TNT], then

[Freel] would have been stuck ° ° ° . So [Freel] would

have had to 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 three 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 non-

recourse Note."’ Accordingly, Freel contacted Leonard

Carr of Duquesne Natural Gas Company (“Duquesne”).

Duquesne was a Pennsylvania corporation with offices in

Houston, Texas; it was primarily engaged in the manu-

facture 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 sub-

stantial net operating loss carryover.

In this transaction, Duquesne assumed the “lender”

role which Elpac had performed in transactions with

44. (Cont'd. )

contract the operator must continue drilling until casing point is

reached, no matter what the cost.

45. We do not know the reason why Freel did not want the

Note; respondent subpoenaed Freel as a witness, and he appeared

at the trial, but respondent did not call him. The record does not

disclose whether Kiowa had any net operating loss carryovers.

Tax Court Opinion A81

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 trans-

actions in which the “lender,” Elpac, shared half of the

operators’ risks, in the Duquesne-Kiowa transaction the

contractual risks were expressly assumed by Kiowa. How-

ever, there was no novation of the Duquesne-CRC con-

tract, 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 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 con-

tractual obligations of TNT 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."

In the transaction with CRC, TNT assigned to

Duquesne the Singer lease, which in turn Duquesne as-

signed 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

46. Louisiana corporate tax law does not provide for net oper-

ating loss carryovers.

S CN athe ag,

A82 Tax Court Opinion

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 as-

sumed Duquesne’s no-out turnkey drilling obligation and

received the $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

three-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 op-

erators drilled and tested all wells as required under the

Lease Purchase and Turnkey Drilling Agreements entered

into in 1972. All the operators hoped to cover their drill-

ing costs, including overhead, with the cash portion of

the drilling contract prices received from the Investors;

some were successful in satisfying their drilling obligations

for only the cash portion, others were not. The record

does not disclose how many were not.

Tax Court Opinion A83

Of the twenty-four packages participated in by Coral

I and Coral II, eleven of the packages resulted in all dry

holes which were plugged and abandoned. Of the

twenty-eight packages participated in by CRC individ-

ually, thirteen 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 $35,000,000 in cash

and $52,000,000 in nonrecourse Notes.“ As of July 1,

1976, proven reserves in the ground from the 1972 pro-

gram had a value in excess of $68,000,000. This amount is

in addition to all oil and gas extracted before July 1, 1976.

Out of this amount, production taxes and transportation

costs of approximately $4,000,000, operating costs of

approximately $11,300,000, and other deductions of

$2,500,000 could be expected to be paid by 1990. Addi-

tionally, payments of principal and interest on the Notes

in the amount of approximately $9,000,000 would be made

from total production. Accordingly, after all of these de-

ductions, proven reserves as of July 1, 1976, which would

be payable to the partnerships, had a value in excess of

$40,000,000. 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.

46a. The typical mixture of cash and nonrecourse note for a

given package of prospects is discernible from the table below.

The packages listed are those comprising the Coral I and Coral II

limited partnerships as well as those packages in which CRC par-

ticipated as an individual investor. (See pages 24 and 25 supra.)

These represented only a portion of CRC’s 1972 portfolio:

Name of Operator —

McMoRan (Elpac)

Powers (Poco)

Western States

McMoRan eee

McMoRan ( Elpac

McMoRan ( Elpac

McMoRan ( Elpac

Gibraltar ( Elpac)

Dynamic

Emerald

Gibraltar (E re)

McMoRan (Elpac)

Sinclair ( Elpac)

Powers ee)

Gibraltar ( nae)

McMoRan (Elpac)

McMoRan ( Elpac )

McMoRan ( Elpac )

Emerald

Birthright

Gibraltar (Elpac)

McMoRan (El “ime

Patrick

Arriba

Coral I and Coral II

Cash Portion

$ 182,160

417,200

182,160

654,800

487,200

208,225

1,085,184

99,600

417,097

Nonrecourse Note

1,042,742

(‘PauoD) “egF

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CRC’s Individual Investments

Name of Operator Cash Portion Nonrecourse Note

Emerald $581,800 $ 872,700

Duquesne 423,275 634,912

Gibraltar ( Elpac) 422,000 633,000

Cane 390,337 555,855

Cane 316,209 444,664

Patrick 458,300 687,450

Patrick 543,200 814,800

Nor-Am 193,144 277,938

Triton 192,800 289,200

Gibraltar ( Elpac) 349,250 523,875

Nor-Am 488,662 703,194

Sinclair ( Elpac) 256,500 384,750

Corpening 101,875 152,812

McMoRan (Elpac ) 576,550 864,825

Nor-Am 927,641 1,334,905

Scoggins 185,461 278,191

McMoRan ( Elpac 496,660 744,990

McMoRan ( Elpac 493,168 739,752

McMoRan ( Elpac 401,120 601,880

McMoRan ( Elpac 429,400 644,100

McMoRan ( Elpac 283,140 424,710

McMoRan tEiPae 437,600 656,400

McMoRan ( Elpac 120,000 180,000

McMoRan (Elpac 109,500 164,250

McMoRan ( Elpac 115,000 172,500

Tech-S 225,530 338,295

McMoRan 193,159 289,723

Gibraltar ( Elpac) 273,800 410,700

(‘pauog) “egP

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A8&6 Tax Court Opinion

An example of a successful operation under CRC’s

1972 drilling program was that of Patrick Petroleum Com-

pany (“Patrick”). In 1972 CRC invested approximately

$7,800,000 with Patrick, which amount includes 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,-

000,000, and the reserves in the ground discovered by

Patrick had an estimated value of $40,000,000. 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 Develop-

ment. Coral J, Coral If and CRC claimed intangible

drilling and development cost deductions for 1972 as

follows:

Coral I $1,533,87]

Coral II 1,543,614

CRC 662,454

Each Coral partnership and CRC validly elected, pur-

suant 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 I1 and CRC had

direct interests. The portion of the total cost of the

—_-

Tax Court Opinion A87

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 re-

ceived as part of these transactions called for interest at

the rate of 6% 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 1, Coral If and CRC

claimed deductions in 1972 for “advanced royalties” as

follows:

Coral I $ 66,319

Coral II 66,066

CRC 55,775

The “advanced royalties” were equal to the note portions

of the stated lease purchase prices under the Lease Pur-

chase and Turnkey Drilling Agreements which were en-

tered into with various operators. 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

A88 Tax Court Opinion

of the cash portion of the lease purchase price. If such

reimbursement of the note poxtion of the lease cost were

made, then the accountant for CRC or the limited part-

nerships 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 informa-

tion returns (Forms 1065) for 1972, Coral I and Coral II

claiined 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 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 per-

cent of the limited partners’ subscriptions. This fee was

in lieu of any allocation of overhead expenses of the gen-

eral partners to the 1972 program and entitled the part-

nership 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 pro-

gram (i.e., % of the partnerships’ interest after pay out).

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 part-

nerships 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 part-

nership interests in Coral I and Coral II. Such brokerage

commissions amounted to 8 percent of the investor sub-

scriptions in Coral I and Coral II.

Tax Court Opinion A89

4. Abandonment Losses. Coral I, Coral Il 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 geolo-

gist 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 be-

cause of the possibility of drilling another well or farm-

ing out the prospect to a third party.

After this geological determination was made, the

geologist (usually Floyd) would contact CRC’s account-

ing 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 indi-

cated percentage of the leases to be abandoned would

A90 Tax Court Opinion

then be transferred from the capital account to the ex-

pense account as an abandonment loss. Such abandon-

ment 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 “aban-

doned” entirely, the nonrecourse Note which was secured

by the leaseholds was considered as worthless by the part-

nerships. 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 “cancelled.” A Note

would be considered cancelled, and cancellation of in-

debtedness 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 in-

debtedness 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 re-

turns 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.

Tax Court Opinion AQ]

In his statutory notices, respondent disallowed 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 re-

spondent consisted of the amounts attributable to the note

portions of the drilling contact prices. Respondent dis-

allowed 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 deduc-

tions of $866,371 for Coral II, of which $20,814 was al-

locable 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 I] 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 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 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! Coral I T

Brountas 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 $20,814.00

interest 722.00 722.00

abandonment losses 6,320.00 6,314.00

advanced royalties 1,463.00 1,445.00

management fees 2,003.00 2,000.00

$31,376.00 $31,295.00

A92 Tax Court Opinion

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 re-

spect to Coral II respondent determined income from

forgiveness of indebtedness of $27,871. Respondent fur-

ther determined CRC’s income from forgiveness of in-

debtedness 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 deter-

minations was that if this or some other court should hold

that the nonrecourse loans had economic substance, then

the loans had

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