# Appendix — Hewitt v. Strickland

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## Record

- **Collection:** Supreme Court brief
- **Document type:** Appendix
- **Published:** January 1, 1983
- **Citation:** 461 U.S. 929

## Text

° . 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
CWE nc cc cccsccnsccussusanecesswereveeeusupananae Al
Judgment of the United States Court of Appeals for the First
CE on ceccveccciccvenscavecedaurvustcesvepaneue A24
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
CE nccccccvsecccesncévencesecnddceanacassauaieea A27
Judgment of the United States Court of Appeals for the Third
COE nckccectvcvusccveussutsscecvseasdel eaaneenen A33
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 (includ

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385010_0625%3A2. Public record. Not legal advice.