# Appendix — United States v. Exxon Corp.

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## Record

- **Collection:** Supreme Court brief
- **Document type:** Appendix
- **Published:** January 1, 1997
- **Citation:** 520 U.S. 1119

## Text

Supreme Court, U.S
FILED

a

Y) 961127 JAN 15 1997,
No.

In the Supreme Court of the United States

OCTOBER TERM, 1996

UNITED STATES OF AMERICA, PETITIONER
Vv.

EXXON CORPORATION AND SUBSIDIARIES

ON PETITION FOR A WRIT OF CERTIORARI
TO THE UNITED STATES COURT OF APPEALS
FOR THE FEDERAL CIRCUIT

APPENDIX TO THE
PETITION FOR A WRIT OF CERTIORARI

WALTER DELLINGER
Acting Solicitor General

LORETTA C. ARGRETT
Assistant Attorney General

LAWRENCE G. WALLACE
Deputy Solicitor General

KENT L. JONES
Assistant to the Solicitor General

BRUCE R. ELLISEN
THOMAS J. CLARK
Attorneys

Department of Justice
Washington, D.C. 20530
(202) 514-2217

TABLE OF CONTENTS

Page
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Appendix B (Court of Federal Claims’ order dated
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Appendix C (Court of Federal Claims’ opinion dated
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APPENDIX A

UNITED STATES COURT OF APPEALS
FOR THE FEDERAL CIRCUIT

95-5116

EXXON CORPORATION AND SUBSIDIARIES,
PLAINTIFFS-APPELLANTS

Vv.

THE UNITED STATES,
DEFENDANT-APPELLEE

DECIDED: June 20, 1996

Before NEWMAN, Circuit Judge, SMITH, Senior
Circuit Judge, and CLEVENGER, Circuit Judge.

CLEVENGER, Circwit Judge.

Invoking our jurisdiction under 28 U.S.C. § 1295
(a)(3) (1994), Exxon Corporation and its subsid-
iaries (Exxon) appeals from the decision by the Court
of Federal Claims in Exxon Corp. v. United States,
No. 89-660T (Fed. Cl., April 11, 1995). In that deci-
sion, the court held that Exxon’s claimed depletion
deduction was based on a legally insufficient repre-
sentative price and, in any event, was unreasonable.
As a result, the court rejected Exxon’s claimed deduc-
tion and affirmed the proportionate profits method
employed by the Commissioner of the Internal Rev-

(1a)

2a

enue Service (IRS) to calculate Exxon’s allowable
depletion deduction. We reverse and remand.

I

Exxon is a fully integrated producer of natural
gas. As such, Exxon engages in all phases of the
business, including exploration, extraction, processing,
and transportation. In contrast, a nonintegrated pro-
ducer sells natural gas immediately after extracting
it, leaving to others the processing and distribution
functions.

In order to support the major capital commitment
required to develop its pipeline system, Exxon entered
into several long-term natural gas sales contracts
from 1953 to 1972, known as the Texas Industrial
Commitments (TIC) contracts. Such contracts were
common during this period because natural gas prices
were stable and low. At the time these contracts were
signed, the price terms were favorable to Exxon.

During the early 1970s, however, increased de-
mand coupled with fears of an energy shortage led
to a rapid escalation in the price of natural gas. The
market price of natural gas doubled in 1973, and
doubled again in 1974. In this seller’s market, pro-
ducers who were not already committed under long
term contracts could practically write their own deals.
In contrast, two thirds of Exxon’s gas production
was committed under the TIC contracts at an average
delivery price of $0.23 per thousand cubic feet (Mcf).’

Although Exxon’s sales were limited by these long-
term contracts, Exxon believed its depletion deduction

1 This price included extraction, processing, and transporta-
tion by Exxon.

3a

for tax purposes was not. For nonintegrated pro-
ducers of natural gas, the depletion deduction is based
on actual gross income, a known figure. Because the
actual gross income of integrated producers includes
revenue from transportation and processing, how-
ever, their depletion deduction is based on a con-
structive gross income derived from the average well-
head market price for similar gas. As explained in
more detail below, the governing regulations refer to
this average price as the representative market or
field price (RMFP).

For its 1974 tax return, Exxon determined that the
“field price” of similar natural gas was $0.36/Mcf.
Because much of Exxon’s gas production was com-
mitted under the TIC contracts at $0.23/Mcf, this
“field price’ exceeded Exxon’s average actual sale
price. Based upon a constructive gross income de-
rived from this figure,” Exxon claimed depletion deduc-
tions totaling $170,094,205 with respect to the prop-
erties in issue.

On audit, the IRS determined that Exxon may not
claim a depletion deduction based on an RMFP in
excess of its actual gross income. Instead of using
an RMFP, the IRS derived Exxon’s depletion deduc-
tion based on Exxon’s actual gross receipts from the
TIC contracts. This methodology yielded a depletion
deduction $11,105,698 lower than Exxon had claimed,
thereby increasing Exxon’s tax obligation for 1974
by $5,330,734. Exxon paid the tax and filed a refund
suit in the Court of Federal Claims.

2 Both the “field price” and the RMFP represent the con-
structive gross income on a per unit basis. As a result, the
constructive gross income equals the RMFP or “field price”
multiplied by the volume of gas produced.

4a

The Court of Federal Claims rejected the IRS’ posi-
tion that the RMFP, as a matter of law, can never
exceed the taxpayer’s actual gross income for pur-
poses of calculating the depletion deduction. The
court noted that nothing in the statute or regula-
tions imposes such a limit. Because some of Exxon’s
data samples were improper, however, the court held
that the RMFP proposed by Exxon was legally in-
sufficient.

Moreover, the court decided that even if Exxon’s
figure was valid, the court had an independent duty
to evaluate the reasonableness of an RMFP on a
case-by-case basis. In the present case, the court
decided it would be unreasonable to allow Exxon to
use an RMFP in excess of its actual gross income.
Accordingly, the court entered judgment in favor of
the IRS.

II

On appeal, Exxon-agrees that the Court of Federal
Claims was correct in deciding that the pertinent
statutes and regulations do not preclude, as a matter
of law, an RMFP that exceeds the price actually
charged for the gas sold. Exxon instead contends
that the Court of Federal Claims erred in holding
that Exxon had failed to prove a valid RMFP on
the facts of this case. In addition, Exxon argues that
the court erred in making an independent assessment
of the reasonableness of Exxon’s RMFP.

While the government defends the ultimate deci-
sion of the Court of Federal Claims, it argues that
the court erred in holding that an RMFP may be used
even if it exceeds the taxpayer’s actual gross income.
Alternatively, the government argues that the court
correctly held that Exxon had failed to prove a valid

a cc si call nana acct ti

5a

RMFP. The government also supports the court’s
determination that it has authority to conduct an
independent assessment of the reasonableness of a
particular RMFP, and that Exxon’s RMFP is unrea-
sonable when so assessed.

The opinion of the Court of Federal Claims explains
at length and with admirable clarity the history of
the depletion deduction in American tax law. We
therefore need not repeat that background informa-
tion and may proceed to the core issue of this appeal.
The outcome of this case turns particularly on three
statutes and one regulation. The Internal Revenue
Code (IRC) provides that:

In the case of mines, oil and gas wells, other
natural deposits, and timber, there shall be al-
lowed as a deduction in computing taxable in-
come a reasonable allowance for depletion and
for depreciation of improvements, according to
the peculiar conditions in each case; such reason-
able allowance in all cases to be made under
regulations prescribed by the Secretary or his
delegate.

ILR.C. § 611(a) (1974).°

Under section 613 of the IRC, the depletion allow-
ance is limited to “50 percent of the taxpayer’s tax-
able income from the property (computed without
allowance for depletion).” I.R.C. §613(a). More-
over, the depletion allowance for oil or gas property
is 22 percent of the “gross income from the property.”

ILR.C. § 613(a), (b).

3 Unless otherwise noted, all cites to the I.R.C. refer to the
1974 version.

6a

There is no statutory definition of the term “gross
income from the property.” Instead, pursuant to the
authority delegated to the Secretary I.R.C. § 611,
he has defined its meaning as follows:

In the case of oil and gas wells, “gross income
from the property”, as used in section 613(c) (1),
means the amount for which the taxpayer sells
the oil or gas in the immediate vicinity of the
well. If the oil or gas is not sold on the premises
but is manufactured or converted into a refined
product prior to sale, or is transported from the
premises prior to sale, the gross income from
the property shall be assumed to be equivalent
to the representative market or filed [sic, field]
price [RMF'P] of the oil or gas before conversion
or transportation.

Treas. Reg. § 1.613-3(a) (1974).*

As the Court of Federal Claims recognized, the dis-
pute in the present case focuses upon the application
of this regulation in the context of depletion allow-
ances for oil and gas.

III

As an initial matter, we address the government’s
contention that the statutes and regulations preclude,
as a matter of law, the use of an RMFP that exceeds
the taxpayer’s actual gross income. The government
first contends that the extant case law has already
answered this question in its favor. Even if that is
not so, the government argues that a proper inter-

* Unless otherwise noted, all cites to treasury regulations
refer to the 1974 versions of those regulations.

a i i ill li

Ta

pretation of the statutory and regulatory provisions
precludes such a result. We disagree on both bases.

A

We turn first to the government’s argument
founded upon case law. In support of this argument,
the government cites United States v. Henderson
Clay Prods., 324 F.2d 7 (5th Cir. 1963), and Pan-
handle Eastern Pipe Line Co. v. United States, 408
F.2d 690 (Ct. Cl. 1969). These cases are best under-
stood in the context of two other cases, Hugoton
Prod. Co. v. United States, 315 F.2d 868 (Ct. Cl.
1963) (Hugoton I), and Hugoton Prod. Co. v. United
States, 349 F.2d 418 (Ct. Cl. 1965) (Hugoton IJ).
We do not find the precedent to be quite as dispositive
as does the government, and conclude that no case
has squarely addressed this issue.

In Hugoton I, the plaintiff was an integrated pro-
ducer of natural gas who claimed that gross income
for depletion purposes should be computed based on
an RMFP.’ Hugoton I, 315 F.2d at 870. The govern-
ment, on the other hand, contended that there was no
representative price for the plaintiff during the tax

5The court referred to the plaintiff’s approach as the
“market comparison approach,” which is equivalent to the
RMFP approach. The RMFP approach is a means of dis-
integrating an integrated producer back into its separate
extracting and processing/transporting entities. Panhandle,
324 F.2d at 15. Under the RMFP approach, the constructive
gross income is that which the hypothetical extracting com-
pany would receive for sale of its products to its processing/
transporting alter ego. Id.

ee

8a

years at issue and therefore a proportionate profits
method should be used.°

The court decided that the RMFP approach must be
used whenever a representative price can be estab-
lished. Id. at 873. The court explained that although
the Commissioner of the IRS could validly embody
the proportionate profits method in regulations, he
had chosen the RMFP approach and had defended
its application when it produced larger revenues for
the government. Jd. at 872-73. Because the Com-
missioner did not include all contracts in his initial
determination that there was no representative price,
however, the court remanded for further findings.
Id. at 877.

In the present case, Exxon’s feet were held to the
fire during the pre-1974 years when the RMFP was
below Exxon’s actual sales; at that time, Exxon ac-
cepted the RMFP approach although the proportionate
profits approach would have been more favorable.
During those years, the RMFP approach worked to
the benefit of the government. Now, when the RMFP
approach would work to the benefit of the taxpayer,
the Commissioner asserts that he is permitted to use
the proportionate profits approach.

The government insists that such a result is per-
missible based on prior case law. Between the times
that Hugoton I and Hugoton II were decided the
Fifth Circuit was faced with a similar case in the
context of depletion deductions for clay mining. In

® Under the proportionate profits method, the gross income
from the property is calculated by taking the gross income
from the sale of the processed gas and subtracting costs at-
tributable to gathering and processing the gas. Hugoton I,
315 F.2d at 870.

9a

Henderson Clay, the plaintiff was an integrated man-
ufacturer that extracted ball clay and processed it
into brick products, which it sold for $8.75 per ton.
Henderson Clay, 324 F.2d at 9. Henderson, however,
claimed a depletion deduction based on a representa-
tive price of $10.50 per ton, which was the price for
shredded ball clay sold in the ceramics market. The
Fifth Circuit stated:

Tax law is law unto itself. There are no equities
in tax law. And there is an area of permissible
illogic in tax law. But when a taxpayer claims
depletion on a fictitious gross income greatly in
excess of its actual gross income, we find the
claim highly indigestible.

Id. at 12.

The government relies heavily on this section for
the proposition that any RMFP in excess of actual
gross income is highly indigestible and therefore
per se impermissible. We do not read Henderson
Clay in such a sweeping manner.

The Fifth Circuit explicitly recognized that “on
principle, it is irrelevant whether, in a particular
case, the Cannelton rule [i.e. using an RM FP] will
give a higher base or a lower base than the gross
income from the finished product will yield.” Jd. at
12. On the facts of that particular case, however,
the Fifth Circuit concluded that the $10.50 per ton
price was not representative. Jd. at 15.

Most importantly, the court noted that although
Henderson claimed an RMFP based on the price for
ball clay in the ceramics market, Henderson did not
compete with nonintegrated clay producers in that

bi‘

10a

market. The higher price of ball clay sold in the
ceramics market was due to advertising, management,
and research costs incurred. See Jd. at 10. As a
young company, Henderson chose not to compete in
this market because it could not afford the associated
costs. Jd. As a result, the court concluded that the
$10.50 per ton price “in no way represents the deple-
tion of the taxpayer’s clay resources and in no way
represents the price which a non-integrated brick
manufacturer would pay for clay with which to make
brick.” 7d. at 15.

In sum, the Fifth Circuit in Henderson Clay did
not impose a cap on the RMFP. Instead, it decided
that the proposed price was not representative of the
price Henderson could have obtained for its ball clay.

We are not the first court to interpret Henderson
Clay in this manner. As explained above, Henderson
Clay was decided between Hugoton I and Hugoton
II. On remand after Hugoton I, the plaintiff was
unhappy with the resulting RMFP and again appealed
to the Court of Claims. This time, the plaintiff con-
tended that the RMFP should be rejected because it
was not representative and that a proportionate
profits method should be applied as was the case in
Henderson Clay. Hugoton II, 349 F.2d at 424-25.

In support of its argument, the plaintiff hypothe-
sized two integrated gas producers, A and B. A ob-
tains $0.15/Mcf for its gas, B obtains $0.05/MCF,
and the RMFP is approximately $0.10/Mcf. Jd. at
424. The plaintiff explained that “in the case of
producer B the hypothetical gross income in each of
the taxable years even though based on actual sales
of other producers at the wellhead would exceed B’s

TF

lla

actual gross income from gathering and processing
natural gas.” Jd.

The court “reject[ed] plaintiff’s somewhat simpli-
fied reasoning that the Fifth Circuit decision resulted
in a sweeping rejection of the market comparison
method simply because, on the facts presented, it pro-
duced results not economically representative of the
taxpayer’s integrated business.” Jd. at 425. Instead,
the court noted that the $10.50 per ton price in Hen-
derson Clay was rejected as nonrepresentative merely
because there was no competition between Henderson
and the other clay miners. 7d. at 426. Hugoton II, it
should be noted, is binding precedent on the decision
of this case, and we thus are not at liberty to reject
the interpretation given to Henderson in Hugoton II.
See South Corp. v. United States, 690 F.2d 1368,
1370 (Fed. Cir. 1982) (in banc).

Finally, the government cites Panhandle in support
of its argument. In Panhandle, the taxpayer entered
into a contract with Consumer Power Company to
sell gas from fourteen wells at a price of $0.325/Mcf.
Panhandle, 408 F.2d at 710. The delivery point for
part of the production from one well, the McPherson
No. 1—35 well, was near the wellhead. The balance
of the production was transported from the wellhead
for delivery to Consumers Power Company at loca-
tions from thirty to forty miles away. Jd. at 710-711.

The court determined that the sale price of
$0.325/Mcf at McPherson No. 1—35 was a valid
market price for wellhead sales. Nevertheless, the
court determined that under the facts of the case,
such a price was not representative of the price that
Panhandle could realize for sales at the wellhead.
See id. at 716. The contract provided that Panhandle

12a

would receive $0.325/MCF whether it sold it at the
wellhead or after transportation. Given the undis-
puted fact that the cost of transportation was
$0.325/Mcf, the court inferred that the $0.325/Mcef
figure represented a blended price to cover all gas
sold under the contract. Jd. at 716-17. Had the gas
been priced separately depending on its delivery point,
it presumably would have sold for a higher price after
transportation and for a lower price at the wellhead.
See id. Therefore, the court concluded that $0.325/
Mcef did not represent the wellhead price.

In sum, the cases cited by the government involve
situations where the courts decided that the proffered
market price was not representative because it in-
cluded transportation or processing (e.g. advertising)
costs. In contrast, the RMFP in the present case
exceeds actual gross receipts because of the effects
of changing market conditions. Our review of the
pertinent case law reveals that no court has ex-
plicitly stated that such an RMFP is impermissible.

B

The government next argues that even if the extant
case law is not dispositive, the statutes and regulation
preclude an RMFP that exceeds the taxpayer’s actual
gross income. We begin our analysis with the lan-
guage of the relevant statutory and regulatory sec-
tions, as they read in 1974. See Johns-Manville Corp.
v. United States, 855 F.2d 1556, 1559 (Fed. Cir.
1988), cert. denied, 489 U.S. 1066 (1989).

Exxon contends that a literal reading of Treas.
Reg. § 1.613-8(a) requires the use of an RMFP
whenever, as is the case here, the natural gas has
been processed and transported away from the prem-

te lll

13a

ises prior to sale. Moreover, Exxon argues, because
the RMFP is a constructed value, actual gross income
is irrelevant. We agree that the plain language of
the tax scheme supports Exxon’s contention.

Section 611 obligates the Secretary to promulgate
regulations that provide for a reasonable allowance.
Pursuant to this delegation, the Secretary promul-
gated only one method of calculating the depletion
allowance for integrated natural gas producers—
the RMFP. Treas. Reg. § 1.613-3(a). Notably, this
regulation contains no language that expressly limits
the RMFP to actual gross income.’

This lack of an express limit on the RMFP takes on
added importance because it is clear that the Secre-
tary was aware of the possibility that the field price
could exceed actual revenues. In the area of hard
minerals, the Secretary promulgated a regulation
creating a rebuttable presumption that such a field
price is not representative. See Treas. Reg. § 1.613-4
(c)(6). Such a limitation is strikingly absent, how-
ever, from the oil and gas regulation.

7 Indeed, the only express limitation on the RMFP is found
in section 613 of the IRC, which limits the depletion allow-
ance to “50 percent of the taxpayer’s taxable income from
the property (computed without allowance for depletion).”
I.R.C. §613 (1974). This independent limitation, however,
does not mean that the RMFP cannot exceed actual gross
income. Instead, it means that 22 percent of the RMFP can-
not exceed 50 per cent of the actual gross income. See id.

Suppose, for example, that actual gross income was
$100,000 and the RMFP was $200,000. The depletion allow-
ance would then be 22 per cent of $200,000, or $44,000. Be-
cause this allowance does not exceed 50 per cent of the taxable
income, $50,000, it would not violate any statutory restric-
tions; and yet the RMFP is clearly in excess of the actual
gross income.

l4a

We note that pursuant to the broad authority dele-
gated to him, the Secretary can amend Treas. Reg.
§ 1.613-3(a) if he so desires to limit the RMFP to
actual gross income. See Hugoton II, 349 F.2d at
430. In fact, the Secretary at one time considered
making such an amendment, but that proposal was
ultimately withdrawn. See 36 Fed. Reg. 19256
(1971) ; 33 Fed. Reg. 10700 (1968). Until the Secre-
tary imposes such a cap in the oil and gas area, we
believe it is not within our judicial powers to legislate
in his stead. See Hugoton II, 349 F.2d at 430.

We nonetheless are mindful that a regulatory pro-
vision must not be read in a vacuum, but instead in
light of the entire law and its object and policy. See
John Mancock Mut. Life Ins. Co. v. Harris Trust &
Savings Bank, 114 S. Ct. 517, 523 (1993); Trustees
of Indiana Univ. v. United States, 618 F.2d 736,
739 (Ct. Cl. 1890). We therefore must ensure that
our interpretation is consistent with the statutory
objective.

The Revenue Act of 1918 allowed oil and gas pro-
ducers a “discovery depletion” deduction based upon
the fair market value of the property on the date of
discovery of the well. Revenue Act of 1918, Pub. L.
No. 65-254, ch. 18, § 234(a) (9), 40 Stat. 1057, 1078-
79 (1919). When enacting this statute, Congress
feared that taxpayers would use the depletion deduc-
tion to offset profits derived from separate and dis-
tinct lines of business. S. Rep. No. 275, 67th Cong.,
Ist Sess. 14-15 (1921). To prevent such abuse, Con-
gress provided that the depletion deduction shall not
exceed the net income from the property, computed
without allowance for depletion. Revenue Act of 1921,
ch. 186, § 234(a) (9), 42 Stat. 227, 256 (1921). In

15a

1924, this restriction was further tightened to cap
the depletion deduction at fifty percent of the tax-
payer’s net income from the property. Revenue Act
of 1924, ch. 234, § 204(c), 43 Stat. 253, 260 (1924).

Calculating the fair market value on the date of
discovery of the well, however, proved to be difficult
to administer and created uncertainty. In response,
Congress simplified administration of the deduction
by basing it upon a percentage of the taxpayer’s gross
income from the property. Revenue Act of 1926, ch.
27, § 204(c) (2), 44 Stat. 9, 16 (1926). Because Con-
gress did not define the meaning of gross income from
the property, several integrated producers claimed a
deduction based upon gross receipts after processing
and distribution. In order to ensure that integrated
producers did not achieve a greater tax deduction
than their nonintegrated competitors, see Hugoton
II, 349 F.2d at 425, Treasury Regulation 74, Art.
221(i) was promulgated stating:

If the oil and gas are not sold on the property
but are manufactured or converted into a refined
product or are transported from the property
prior to sale, then the gross income shall be
assumed to be equivalent to the market or field
price of the oil and gas before conversion or
transportation.

Treas. Reg. 74, Art. 221(i) (1931 ed.). This
regulation is substantially similar to Treas. Reg.
§ 1.613-3(a) at issue in this case.

The legislative history of these provisions therefore
reveals two primary limitations. First, the deduction
should not allow a taxpayer to offset profits earned
from a separate line of business. As explained above,

16a

this does not limit the RMFP to actual gross income.
Second, integrated manufacturers should not be al-
lowed to include in their “gross income from the prop-
erty” any value that was added to the gas after
extraction, such as by processing or transportation.
See Hugoton I, 315 F.2d at 869. Several courts have
referred to this second objective as requiring that an
integrated producer not receive a competitive tax
advantage over nonintegrated producers.

The government seizes upon this second objective
and argues it would be frustrated if Exxon is allowed
to use an RMFP in excess of its actual gross receipts.
The government notes that some nonintegrated pro-
ducers entered into long term contracts at low prices
just as did Exxon; because they are nonintegrated,
however, their depletion deduction would be limited
to their low contractual prices rather than a higher
deduction based on an RMFP. In other words, the gov-
ernment argues that the statutory objective requires
that integrated producers in long term contracts re-
ceive no tax advantage over nonintegrated producers
in long term contracts. We disagree.

Treas. Reg. § 1.618-3(a) and its predecessors were
designed to ensure that integrated producers did not
include in their gross income calculation any value
added by their processing and transportation com-
ponents. See Panhandle, 408 F.2d at 700. The RMFP
in the present case exceeds the actual gross income
based on market forces and not based on downstream
processing. While the legislative history addresses
the effects of downstream processing, it is silent as to
changes in market conditions. Contrary to the gov-
ernment’s argument, therefore, we do not violate this

17a

statutory objective by refusing to limit the RMFP to
actual gross income.

In sum, the legislative history does not reveal an
intent to limit the RMFP to actual gross receipts.
Instead, the legislative history reveals that the RMFP
is employed as an inexact, simplified means of calcu-
lating an integrated producer’s depletion deduction.”
We therefore agree with the Court of Federal Claims
that neither prior case law, nor the language of the
statute, nor its legislative history limits an other-
wise valid RMFP to actual gross income.

IV

After deciding that the RMFP is not limited to
actual gross income, the Court of Federal Claims
nonetheless ruled against Exxon. The court decided
that, based on the facts of this case, Exxon had failed
to prove a valid RMFP.

At trial, Exxon’s pricing expert stated that in 1974,
the RMFP for natural gas was $0.41/Mcf. In sup-
port of this proffered RMFP, Exxon submitted data
concerning 2,228 sales. These sales allegedly repre-
sented over ninety percent of the wellhead sales of
comparable unprocessed gas in Exxon’s market area.
The court determined that many of these sales should
not have been included in the RMFP because they
included either dehydration or transportation costs.
As to the remaining sales, the court professed that:

8 On average, the RMFP “will tend to equalize the deple-
tion allowance as between integrated and nonintegrated pro-
ducers.” Hugoton I, 315 F.2d at 876. Any nonintegrated
producers locked into long term contracts will be included in
the RM¥FP calculus and will tend to lower the RMFP. On
the other hand, nonintegrated producers selling at current
market prices will tend to raise the RMFP.

18a

The court is unable to extract from the 2,228
sales proffered by Exxon those sales clearly estab-
lished to be gas sales in the immediate vicinity
of the wells. The vastness of Exxon’s sample
hindered rather than helped the court determine
the accuracy of the proposed RMFP.

Exxon first contends that all of the sales included
in its $0.41/Mcf RMFP were proper. Exxon next
contends that even if some sales should have been
excluded, the court erred by failing to determine an
RMFP based on the remaining sales. We disagree
with Exxon’s first argument, but agree with the
second.

A

As the Court of Federal Claims recognized, calcu-
lation of the RMFP is a difficult and sometimes oner-
ous task. This difficulty is exacerbated by the fact
that the Secretary has declined to promulgate regu-
lations which could provide guidance to taxpayers and
the courts. In the absence of such guidance, both
the taxpayers and the courts must formulate and
evaluate the RMFP based on a common law approach
that looks to prior adjudications of depletion allow-
ances. Although such an approach does not create a
unitary test for formulating an RMFP, several gen-
eral principles may be discerned.

In reviewing prior case law for guidance, we must
remember that the fundamental goal of the calcula-
tion is to arrive at a price that is representative of
the price which would be realized by nonintegrated
producers. Accordingly, prior cases have stated that
the RMFP of gas is calculated as the weighted aver-
age price of wellhead sales of comparable gas in the

19a

taxpayer’s market area. Panhandle, 408 F.2d at
703; Hugoton I, 315 F.2d at 877. In making this
calculation, prior cases have emphasized the value in
using a large sample size of transactions because the
large sample size “should provide greater assurance
that the price derived is in fact representative.”
Hugoton I, 315 F.2d at 877. The sample set, how-
ever, must be limited to wellhead sales and may not
include sales in which the gas was processed or trans-
ported by the taxpayer. Panhandle, 408 F.2d at 716.
Finally, the RMFP should be calculated based on all
wellhead sales for the given tax year at issue, regard-
less of their contract date. Hugoton I, 315 F.2d at
871.
B

In reliance on this precedent, Exxon compiled data
of 2,228 comparable sales. Based on language in Pan-
handle, Exxon derived most of this data from annual
reports filed by natural gas pipelines with the Fed-
eral Power Commission (FPC) and the Gas Utilities
Division (GUD) of the Texas Railroad Commission.
See Panhandle, 408 F.2d at 704-05 (“[i]t would be
better, in any future litigation of this same kind, if
the parties relied solely upon information contained
in said [FPC] forms”). Exxon also confirmed 1,164
of these transactions by reviewing the actual contracts
of a single pipeline company. As a result, Exxon
arrived at an RMFP of $0.41/Mcf.

1

As an initial matter, the government argues that
Panhandle is limited to situations where the two
parties agree on which transactions should be included

cntheermaase atenesadiamall

20a

in the RMFP calculation. Where the parties dis- '
agree, the government argues, Panhandle does not |
apply and the taxpayer must support its RMFP
calculation with actual contracts. We disagree with
this reading of Panhandle.

Panhandle does not resolve any dispute as to which
transactions should be included in the RMFP calcu-
lations. Instead, Panhondle merely articulates the
form of proof that will suffice to represent those
transactions. When read in context, Panhandle emits
a palpable sense for the need to accommodate the
burdens inherent in calculating the RMFP in deple-
tion cases:

It cannot be seriously disputed that it is imprac-
tical to go behind the Forms 2 in a comprehensive
manner because this would require an unduly
time-consuming and burdensome examination of
all purchase contracts listed in the gas purchase
sections of the forms. In this connection, it
should be noted that during the trial the attor-
neys for both parties stated that if they had
gone behind the forms to any greater extent than
this [sic] had been done by defendant, “[wlJe
would never have tried this case.”

Panhandle, 408 F.2d at 704.

Based on its context, we read Panhandle as creating
a rebuttable presumption that filed annual reports
constitute prima facie proof of the transactions they
represent. Nonetheless, the parties remain free to
rebut this presumption with proof that the forms con-
flict with the underlying contracts. Moreover, the
parties remain free to disagree as to which FPC
transactions should be included in the RMFP
calculation.

scnenieamanaimamnaiieaitalaiiaiilieaiiliiuala

2la

2

In accordance with this approach, the Court of
Federal Claims considered the transactions repre-
sented by the FPC Form 2 but rejected some which
involved sale of gas after transportation. The court
noted that the FPC Form 2 divides gas purchases by
pipelines into two categories. Account 800 purchases
are defined as wellhead purchases “where only the
utility’s [the purchaser’s] facilities are used in bring-
ing the gas from the well head into the utility’s
natural gas system.” 18 C.F.R. part 201, account
800 (1974). In contrast, Account 801 purchases are
defined as field line purchases “where facilities of
the vendor or others are used in bringing the gas
from the well head to the point of entry into the util-
ity’s natural gas system.” 18 C.F.R. part 201, ac-
count 801 (1974). As the court explained, “[t]he
distinction is that in Account 800 sales the purchaser
transports the gas away from the wellhead; whereas
in Account 801 sales, the producer transports the gas
away from the wellhead.”

Exxon’s data included both Account 800 and Ac-
count 801 sales. Because Account 801 sales include
value added by transportation and because Exxon’s
study did not cleanse the Account 801 sales by sub-
tracting the value added by transportation, we agree
with the Court of Federal Claims that such sales
should not play a role in the RMFP calculus in this
ease. Such transactions, however, should not neces-
sarily be excluded altogether, especially in light of
the goal of maximizing the number of transactions
included.’ Instead, it would be preferable for the

® In the present case, the evidence indicates that 723 of the
2,228 transactions represented Account 800 sales. Thus,

22a

taxpayer to cure these tainted transactions by sub-
tracting the transportation cost from the sale price.
Cf. Panhandle, 408 F.2d at 718 (arriving at a price
of $0.29/Mef by subtracting $0.035 as transportation
costs from the sale price of $0.325).

In addition to Account 801 sales, Exxon also in-
cluded in its calculation transactions where the gas
was dehydrated and compressed prior to sale. This
approach is reasonable, Exxon contends, because dehy-
dration is an ordinary production activity as opposed
to a manufacturing activity. In fact, Exxon asserts
that dehydration by the producer is the rule rather
than the exception; and the cost of dehydration, vary-
ing from $0.0025/Mcf to $0.005/Mcf, is quite small.
Because it is easier and more economical for the pro-
ducer to perform this task, the industry views dehy-
dration as the producer’s responsibility. Exxon’s
study, however, did not reduce the price of each sale
by the applicable dehydration cost amount.

The Court of Federal Claims rejected Exxon’s con-
tention that dehydration sales should be included in
the RMFP calculus. The court agreed with the gov-
ernment’s expert who testified that ordinary produc-
tion methods are purely mechanical in nature whereas
dehydration requires a chemical reaction. In addi-
tion, the court noted that some pipelines purchased
gas prior to dehydration. Finally, the court recog-
nized that excluding dehydration was consistent with
the prior case law which considered as comparable
sales only those delivered to the purchaser at the well-
head or separater. Hugoton I, 315 F.2d at 869; Pan-
handle, 408 F.2d at 704; Shamrock Oil & Gas Corp.
v. Commissioner, 35 T.C. 979, 1036-37 (1961), aff'd,

eliminating Account 801 sales altogether would reduce the
sample set by 68 per cent.

23a

346 F.2d 377 (5th Cir.), cert. denied, 382 U.S. 892
(1965). Based on the evidence, the court’s decision
to exclude sales after dehydration from the RMFP
calculus in this case is not clearly erroneous. As with
the transportation costs, however, we note that it
would be preferable, if possible, for the taxpayer to
subtract the dehydration costs from the transactions
rather than force the elimination of those transactions
altogether.
3

Finally, Exxon contends that even if the Court of
Federal Claims properly excluded certain trans-
actions, the court failed in its obligation to determine
an RMFP based on the remaining transactions. Exxon
notes that in calculating its RMFP, Exxon was forced
to make numerous decisions on issues such as market
area, comparability, and which transactions to include.
Given the nebulous character of these issues, Exxon
explains, it was not implausible that the court would
disagree with one or more of its decisions. To accom-
modate this possibility, Exxon’s price study provided
the data in a manner that allowed the court to use
only some of the transactions.

The government does not argue that the remaining
sales constituted an insufficient sample from which an
RMFP could be calculated. See Hugoton II, 349 F.2d
at 420 (indicating that a sample containing twenty
contracts is sufficient); cf. Panhandle, 408 F.2d at
714-15 (suggesting that a sample containing only one
transaction could be used to calculate the RMFP).
Instead, the government argues that the remaining
_gales cannot be used to calculate an RMFP because:
(1) Exxon’s sales data is not presented in a manner
that allows the isolation of wellhead sales; and (2)

24a

the Account 800 sales reported on the FPC forms may
not have been wellhead sales. We disagree with the
government’s arguments.

The government first contends that Exxon’s data
cannot be parsed to reveal pre-dehydration Account
800 sales. On the record before us, however, it
appears that Exxon’s study contains a list and de-
scription of each transaction included in its RMFP
calculation. For example, Exhibit 45 is a list of
pre-dehydration sales; and Exhibit 29 is a list of pre-
compression sales, with the first three pages limited
to Account 800 sales. The overlap between these two
should yield pre-dehydration, pre-compression, Ac-
count 800 sales. Therefore, the data presented by
Exxon can be parsed to reveal pre-hydration Account
800 sales.

Next, the government contends that Account 800
transactions should not be used because they may con-
tain field ine purchases as well as wellhead purchases.
In support, the government points to a “note” appear-
ing under Account 800 which states that “[i]f gas
purchases are made under one contract covering both
well head and field line purchases and such amounts
are not readily separable, the utility may classify
such purchases according to predominant source or
according to a reasonable estimate.” 18 C.F.R. Part
201, Account 800 (1974). As explained above, how-
ever, we presume that the FPC forms are representa-
tive of their underlying transactions. Either party
may rebut this presumption with proof that some of
the transactions listed in the forms are not repre-
sentative. Cf. Panhandle, 408 F.2d at 704 (allowing
an adjustment because gas purchased at the wellhead
was erroneously listed as non-wellhead sales). In the

25a

present case, however, the government has made no
showing of proof to rebut the FPC transactions which
meet the Court of Federal Claims’ criteria. There-
fore, in the present case, the pre-dehydration trans-
actions listed in Account 800 may properly be used
to calculate the RMFP.

In sum, the Court of Federal Claims properly
rejected certain transactions in Exxon’s study because
they did not represent wellhead sales. The court
erred, however, by truncating its RMFP analysis
thus not reaching the issue of whether Exxon’s study
contained any valid transactions from which an
RMFP could be determined. Nonetheless, we need not
remand this case for calculation of the RMFP because
the undisputed evidence of record supports an RMFP
in the amount of $0.39/Mcf.”

10 The first three pages of Exhibit 29 list pre-compression
Account 800 sales. [JA at 7021-7023] Exhibit 45 lists, in
decreasing order of volume, all transactions in which the sel-
ler does not dehydrate the gas. [JA at 7259-7266] Those
transactions which appear on both of these lists satisfy the
Court of Federal Claims’ criteria for wellhead sales. These
qualifying transactions are summarized below, in decreasing
order of volume purchased :

Purchaser Volume (in Mcf) Price per Mcf
Lovaca Gathering Company 9,330,442 $0.16
Lovaca Gathering Company 7,515,106 $0.16
Delhi Gas Pipeline Corp. 2,544,020 $0.71
Delhi Gas Pipeline Corp. 2,073,461 $0.76
Houston Pipe Line Company 1,325,003 $0.97
Houston Pipe Line Company 755,460 $0.87
Houston Pipe Line Company 752,259 $0.17
Houston Pipe Line Company 682,373 $1.02
Houston Pipe Line Company 446,481 $0.91

(Continued)

26a

V

The Court of Federal Claims stated that even if
Exxon had proven its proffered RMFP, the court had
authority to conduct an independent assessment of its
reasonableness. While recognizing that the RMFP
is not limited to actual gross income, the Court of
Federal Claims decided that ‘“‘the test, it seems to
the court, is not whether the RMFP exceeds or is
below the actual sales price of the gas but rather
whether the RMFP is reasonable under the circum-
stances.” In support, the court relied on two factors.
First, the statute provides for a “reasonable allow-

10 (Continued)

Purchaser Volume (in Mcf) Price per Mcf
Delhi Gas Pipeline Corp. 416,520 $0.13
Lovaca Gathering Company 401,636 $1.16
Houston Pipe Line Company 378,131 $1.38
Lovaca Gathering Company 314,700 $0.19
Lovaca Gathering Company 305,128 $0.46
Bi Stone Fuel Company 298,046 $0.49
Lovaca Gathering Company 274,657 $0.24
Houston Pipe Line Company 203,680 $1.18
Arkansas Louisiana Gas Co. 165,326 $0.12
Houston Pipe Line Company 149,239 $0.54
Houston Pipe Line Company 132,599 $0.30
Houston Pipe Line Company 96,654 $0.85
Lovaca Gathering Company 60,750 $1.15
Lovaca Gathering Company 35,220 $0.35
Lovaca Gathering Company 33,414 $0.35

The total price for these transactions is approximately
$11,260,653. This is derived by multiplying the volume of
each transaction by the price for that transaction, and sum-
ming the resulting figures for all transactions. The volume
weighted average price is derived by dividing this total price
of $11,260,653 by the total volume of 28,690,351 Mcf. This
results in a volume weighted average price of $0.39/Mcf.

27a

ance for depletion . . . according to the peculiar con-
ditions in each case.” I.R.C. § 611(a). Second, the
court found support in prior case law. We disagree
that the court’s approach is appropriate.

Section 611 indeed provides for “a reasonable al-
lowance for depletion.” I.R.C. § 611(a). Importantly,
however, the statute also provides that “such reason-
able allowance in all cases [is] to be made under
regulations prescribed by the Secretary or his dele-
gate.” Id. We do not read this broad directive as
allowing the courts to adjudicate the reasonableness
of an allowance on a case-by-case basis. Instead, the
statute directs the Secretary to promulgate regula-
tions which will apply in all cases to yield a reason-
able allowance. Pursuant to this directive, the Secre-
tary has promulgated Treas. Reg. § 1.613-3(a), which
remains of unquestioned validity. See Hugoton I, 315
F.2d at 871. Because Congress has charged the Sec-
retary with the task of promulgating regulations
which yield a reasonable allowance, we hold that a
depletion allowance pursuant to Treas. Reg. § 1.613-
3(a) is per se reasonable, absent a challenge to the
regulation itself.

Our reasoning is similar to that of the United
States Supreme Court in Commissioner v. Portland
Cement Co. of Utah, 450 U.S. 156 (1981), a case
which also involved Treasury Regulations for deple-
tion allowances. The Court explained its basis for
applying the Treasury Regulations at issue in that
ease as follows:

tt TNS ONDE HVS eR he oor —_ —

These regulations command our respect, for Con-
gress has delegated to the Secretary of the Treas-
urv, not to this Court, the task “of administering
the tax laws of the Nation.” ... Treasury Regu-

EE

28a

lations “must be sustained unless unreasonable
and plainly inconsistent with the revenue stat-
utes.” Indeed, our customary deference to Treas-
ury Regulations is particularly appropriate in
this case, for the Court previously has recognized
the necessity of a “broad rule-making delega-
tion” of authority in the area of depletion... .

Id. at 169 (citations omitted). This case demon-
strates that the Secretary is charged with promul-
gating regulations and our scope of review is limited
to the reasonableness of the regulations and not the
reasonableness of any individual allowance.

In support for its approach, the Court of Federal
Claims also relied on the statutory language that the
reasonable allowance be made “according to the pe-
culiar conditions in each case.” I.R.C. § 611(a). This,
the court stated, supported a case-by-case inquiry
into the reasonableness of a particular allowance.
This interpretation, however, has been rejected by
the Supreme Court. The Court has explicitly ex-
plained that “[r]ead in context, ‘in each case’ refers
to the different types of depletable resource [e.g.,
mines, oil and gas, timber, etc.], not to individual
taxpayers.” Portland Cement, 450 U.S. at 171 n.20.
Therefore, the statutory language does not support
the Court of Federal Claim’s case-by-case reasonable-
ness inquiry.

The Court of Federal Claims also stated that Pan-
- handle and Henderson Clay stand for the proposition
that the RMFP must be reasonable. We disagree. As
explained above, in each of those cases, the court de-
cided that the proffered price was not representative.
See Panhandle, 408 F.2d at 716; Henderson Clay,

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29a

394 F.2d at 15. In other words, a representative
market or field price, i.e., RMFP, had not been estab-
lished. If an RMFP is proven, however, nothing in
prior case law requires the court to conduct an inde-
pendent reasonableness inquiry.”

In sum, neither the statutory language nor prior
case law allows, let alone requires, the Court of Fed-
eral Claims to conduct an independent reasonableness
inquiry once an RMFP has been established.

VI

We conclude that prior case law does not preclude
an RMFP that exceeds actual gross receipts. This
is consistent with the statutory scheme which dele-
gates to the Secretary of the Treasury the authority
to promulgate regulations that provide for a reason-
able depletion allowance. Pursuant to this authority,
the Secretary promulgated Treas. Reg. § 1.613-3(a),
which is the only regulation that applies to integrated
natural gas producers. Although the Court of Federal
Claims was correct in deciding that there is no ex-
press limit on the RMF'P, we conclude that the court
erred by engaging in a reasonableness inquiry. If an
RMF? is established, it must govern.

Finally, although the court properly rejected cer-
tain transactions included in Exxon’s RMFP calcula-
tion, the court erred by failing to conclude that
Exxon’s study contained qualifying transactions from

11 Whether a price is representative depends simply on an
objective evaluation of the price being obtained by noninte-
grated producers. In contrast, the determination of whether
a price is reasonable can depend on numerous factors includ-
ing notions of fairness, the taxpayer’s profit margin, etc.

30a

which a valid RMFP could be calculated. The deci-
sion of the Court of Federal Claims is therefore re-
versed. The record supports an RMFP of $0.39/Mcf,
and Exxon is entitled to use that figure in calculating
its depletion deduction for the period in question.
Because we conclude that Exxon is entitled to an
RMFP of $0.39/Mcf, rather tian of $0.36/Mcf “field
price” as originally claimed, we remand the case to
the Court of Federal Claims for entry of a final deci-
sion consistent with our conclusion.

REVERSE AND REMAND

3la

UNITED STATES COURT OF APPEALS
FOR THE FEDERAL CIRCUIT

Appeal No. 95-5116
EXXON CORP.
Vv.
UNITED STATES

July 10, 1996

SECOND ERRATA

Decided: June 20, 1996 Precedential opinion

Please make the following correction:
Page 13: Delete footnote 7.

32a

UNITED STATES COURT OF APPEALS
FOR THE FEDERAL CIRCUIT

Appeal No. 95-5116
EXXON CORPORATION AND SUBSIDIARIES
v.
THE UNITED STATES

June 20, 1996

ERRATA
Decided: June 20, 1996 Precedential Opinion

Please make the following correction:

Page 25, Footnote 10, delete bold bracketed
citations

eee.

33a
APPENDIX B

IN THE UNITED STATES COURT
OF FEDERAL CLAIMS

No. 660-89T
(Filed: June 29, 1993)

EXXON CORPORATION ET AL., PLAINTIFFS
Vv.

THE UNITED STATES, DEFENDANT

ORDER
LYDON, Senior Judge:

The plaintiffs in this action are Exxon and other
subsidiary corporations, who for convenience will be
referred to collectively as Exxon. Exxon seeks to
recover income taxes paid after deficiencies had been
assessed by the Commissioner of Internal Revenue
relating to the 1974 tax year. The issue before the
court is the amount of the percentage depletion de-
duction that plaintiff should be allowed to deduct on
its 1974 tax return. Defendant has moved for judg-
ment on the pleadings and for summary judgment.
Having considered the parties’ submissions and hav-
ing heard oral argument, the court denies both
motions.

34a
I

Exxon Corporation is in the business of exploring
for and producing crude oil and natural gas and
refining, transporting, buying, and selling petroleum
and petroleum products. Because Exxon has the ca-
pacity to transport its raw natural gas away from its
wells through its own pipeline so it can be processed
before sale, it is considered an “integrated producer”.
One must keep in mind the contextual use of the term
“natural gas” in this order. The price or value of the
“natural gas” at issue in this litigation is the price
of the raw product that emerges from the ground,
commonly referred to as the wellhead price. At times,
the term “natural gas” is used to refer to the finished
state of the product after refining, the value of which
cannot form the basis, by itself, of any depletion de-
duction allowance unless modified to eliminate the
increase in value caused by processing after it appears
at the wellhead.

A. Exzxon’s Gas Production in Texas During 1974

During 1974, the taxable year in issue, Exxon
owned economic interests in 504 mineral properties
located in 63 oil and gas fields in east and south
Texas.’ Raw natural gas was produced at each of
these properties and, in most cases, transported away

1 Exxon owned its.economic interests in most of these prop-
erties by way of mineral leases. These leases typically con-
tained provisions requiring Exxon to pay the lessors, as
royalty, from one-eighth to one-sixth of the value of the oil
and gas it produced. Exxon owned the remaining economic
interests by way of mineral fee.

eee mn aye ee, ee

35a

from each producing property prior to sale.” The
natural gas produced from wells on each of these
properties was, in most instances, first passed through
an on-site gravity separator to separate the raw gas
from sand, water, condensates (heavy hydrocarbons) ,
and crude oil. Raw gas that was relatively rich in
liquefiable hydrocarbons, which characterizes most of
the gas in this case, generally was gathered in the
field and transported by pipeline to one of eight nat-
ural gas processing plants operated by Exxon.* At
the plants, the bulk of the liquefiable hydrocarbons
was removed from the gas and manufactured or con-
verted into ethane, propane, butanes, and natural gas-
oline, which were further processed or marketed as
natural gas liquids. What remained after the removal
of the liquefiable hydrocarbons was “residue gas’,
gas that consisted largely of methane, which was
processed to meet industrial use or commercial pipe-
line specifications. Raw gas that was not relatively
rich in liquefiable hydrocarbons was not processed at

2 Natural gas has two primary commercial uses, as a gase-
ous fuel and as a chemical feedstock. It is often economically
attractive to process raw natural gas in order to separate
the lightest component, methane, for use as a gaseous fuel
from the heavier compounds, which have more valuable uses
as liquid fuels or a chemical feedstock.

$Prior to sale, raw natural gas, a variable mixture of
different hydrocarbon compounds in various proportions, is
usually conditioned (to make it suitable for transfer through
the pipeline) and processed (to make it suitable for separate
and distinct requirements of. customers). The gas Exxon
transported in the pipeline system that serves these properties
is almost entirely methane, carefully conditioned to meet
stringent pipeline operating specifications.

——_—_eeereeoeee

36a

a natural gas processing plant.‘ On occasion, a por-
tion of the produced gas may be returned to the
reservoir to increase total hydrocarbon recovery.
Some of the finished products made at the plants
were offered to customers for sale in the ordinary
course of business, such as the heavier natural gas
liquids (ethane, butane, etc.) it sold to third parties

*In 1974, the eight Exxon processing plants converted raw
natural gas into a number of compounds as follows:

1974 Plant Products by Plant (Bbls)

Gas Plant C1/C2 C3 iC4/nC4 iC5/nC5 Heavier

King Ranch 341M 178M 122M 188M 0
Katy 5.7™M 2.2M 1.1M 2.5M 0
Lovell Lake 100K 119K 81K 0 73.5K
Pledged 0 0 112K 0 758K
East Texas 253K 532K 477K 0 332K
Hawkins 72K 915K 1M 0 791K
Anahuac 715K 592K 343K 370K 0
Clear Lake 895K 598K 319K 301K 0
(M=nmillion Bbls ; K=thousands Bbls.)

Hydrocarbon Abbreviated symbol commonly

Name used in gas processing

Methane Cl

Ethane C2

Propane C3

Iso-butane iC4

Normal] butane nC4

Isopentane iC5

Normal Pentane nC5

Hexane C6

Heptane C7

Octane C8

Nonane C9

Decane C10

37a

for money consideration at arm’s-length at the plant.
Some finished products were transported to other
Exxon facilities for Exxon’s own use as an energy
source and as chemical feedstocks. Unlike the sales
to third parties, these intracompany transactions gen-
erated no identifiable “purchase price”. Thus, Exxon
used “constructive prices,” which Exxon called “Exxon
Posted Prices,” for those gas products transferred
from its gas processing plants to its refineries and
pipelines. For methane, processed and conditioned to
meet pipeline specifications and delivered to Exxon’s
own pipeline, the constructive prices were called
“Exxon Field Prices.”

Because of the magnitude of its natural gas pro-
duction, in the 1930s Exxon built its own gas pipeline
transmission system, now known as the Exxon Gas
System (EGS). EGS was built so Exxon could en-
hance the market for its own gas by selling it directly
to industrial consumers and public utilities within
Texas. The system, which by 1974 had grown to a
length of about 1500 miles, consisted of two primary
lines: one line running from a point near Corpus
Christi in south Texas to a point near Tyler in north-
east Texas, and a second line running east from
Houston toward the Louisiana border at Port Arthur.
To support the major capital commitment required
for the extension of EGS, Exxon needed an assured
market for its gas. Exxon secured that market in the
1950s and 1960s by entering into long-term gas sales
contracts, known as the Texas Industrial Commit-
ments contracts (TICs). During the taxable year at
issue here, seventeen of these long-term contracts
were in effect. At oral argument, the parties appar-

38a

ently agreed that the bulk of the gas at issue in this
case was gas sold under these TIC contracts.

Gas delivered to EGS from the tailgates of the
natural gas processing plants (residue gas) or di-
rectly from the producing property via gathering line
or transmission line (non-processed gas). Most of the_
gas that was delivered to EGS was sold to Exxon’s
customers, predominantly under the TIC contracts.
About ten percent of the gas transported through
EGS was-delivered to Exxon’s refinery and chemical
complex at Baytown, Texas. A minor portion of the
gas was used as fuel in EGS operations. At Exxon’s
refineries and chemical facilities, the natural gas
liquids were further refined and processed into prod-
ucts such as gasoline, propylene, and ethylene, which
ultimately were sold to customers.

B. How Exxon Determined the “Gross Income” of
its Gas Properties

For the 1974 tax year, Exxon determined the value
of the residue and non-processed gas produced on the
properties using its “field price” for the gas.° The
field price also represented the “constructive price”
in the case of methane, which was precessed and con-
ditioned by Exxon to meet stringent pipeline specifica-
tions and delivered to EGS. Exxon based its field
price on the volume-weighted average price for which
producers sold gas to pipeline purchasers in the rele-

5 Exxon states that its “field price” was used in 1974 as the
“representative market or field price” for determining its
percentage depletion deduction, and was also used as a basis
for calculating royalty payments, Texas gas production tax,
and the sales price in arm’s-length transactions with third-
party working interest owners.

39a

vant pricing areas. In those cases in which Exxon’s
gas plants supplied its refineries and chemical com-
plexes with heavier liquids as chemical feedstock, the
constructive transfer prices were referred to as
“Exxon Posted Prices.”

_ In determining field prices, the volume-weighted
average prices were calculated for one month in each
calendar quarter on the basis of data from the Form
60-1.50 Purchasers’ Monthly Gas Tax reports filed
with the state of Texas by pipeline purchasers. Exxon
analyzed these severance tax reports, which had been
filed by fifty to sixty large pipeline companies as first
purchasers of gas produced in Texas and represented
more than 85 percent of the gas produced in that
state. Because the tax reports were not available
until three to four months after the relevant pricing
period, the monthly average industry prices were
plotted and projected forward, based on a review by
an Exxon management committee, to set the field
price. According to Frederick Perkins, general man-
ager of Exxon’s gas department and member of the
committee establishing the field prices, Exxon’s field
pricing procedures were designed to ascertain what
pipeline companies were paying for conditioned, proc-
essed, and compressed pipeline quality gas, not what
companies were paying for raw natural gas at the
wellhead. In addition, the judgment of the individual
members of the pricing committee played a role in
fixing the field prices. It is particularly noteworthy
that Exxon did not base its 1974 field price for these
properties on any analysis of sales of raw natural

* Apparently, Exxon no longer has copies of the severance
tax returns for 1974 that it initially used in the process of
establishing Exxon field prices for 1974.

40a

gas at the producing wellheads prior to conversion
or transportation."

Exxon established a field price for each of three
geographical “pricing areas” in which were located
the 504 properties, referred to as South Texas, Gulf
Coast, and East Texas.* For 1974, Exxon established
the following field prices per thousand cubic feet
(mcf) :°

7™Mr. Perkins further testified at his deposition that Exxon
no longer has copies of the severance tax returns from 1974
that it examined, and that it no longer has copies of work-
papers that would be essential to verify the accuracy of the
Exxon field prices from 1974. Having learned that the State
of Texas also did not have copies of these tax returns, the
government commissioned an expert, Kirt Keelan, to analyze
Exxon’s returns. Mr. Keelan is a petroleum consultant from
the firm of Forrest A. Garb & Associates, Inc. He concluded
that the returns he received from Exxon did not indicate that
Exxon reported prices for natural gas transfers that were
similar to the Exxon field prices.

As of December 1990, Exxon apparently still had not made
any analysis of sales of raw natural gas producing wellheads
prior to conversion or transportation with respect to 1974
production in eastern and southern Texas.

®§ The “South Texas” area consists of Texas Railroad Com-
mission Districts 1, 2 and 4. The “Gulf Coast” area consists
of Texas Railroad Commission District 3 plus Jackson,
Lavaca, Milam, Robertson, Angelina, San Augustine, and
Sabine counties. “East Texas” is Texas Railroad Commission
Districts 5 and 6 less the counties listed with the Gulf Coast
area. (By way of explanation, for historical reasons, in
Texas the tracking of the oil and gas industry in maintained
by the Texas Railroad Commission.)

® These prices do not take into account “new” gas, gas that
had been produced from a reservoir discovered by drilling
after 1971 or from a field first connected to EGS after 1971.
“New” gas represents less than two percent of the gas in issue
in this case.

4la

Ist 2nd 8rd 4th

Quarter Quarter Quarter Quarter
South Texas $.25 $.28 $.30 $.33
Gulf Coast .29 382 .40 .50
East Texas .24 27 27 27

On its 1974 federal income tax return, Exxon took
the natural gas depletion deduction allowed in the In-
ternal Revenue Code.” This depletion deduction is
based on a percentage of the gross income generated
by the property." Exxon computed its gross income
from the property attributable to the natural gas
produced from each of the 504 properties by deter-
mining a separate gross value at the wellhead for
each natural gas product sold or used by Exxon, and
adding these values together to derive the total gross
value at the wellhead of the raw gas system.”

As mentioned above, raw natural gas produced at
the wellhead typically becomes one of three types of
gas. Among these is non-processed gas. For the non-
processed gas in issue, Exxon calculated the gross
value at the wellhead by multiplying the applicable
field price by Exxon’s gross working interest gas vol-
ume and reducing the product by the amount (if

10 T.R.C. § 611.
4 T.R.C. § 618.

12 During 1974, Exxon’s share of the raw gas produced
from the 504 properties (net of injections, royalty, and other
working interest shares) was 759,403,949 mcf. Of this
amount, Exxon used its field price to determine its gross
income from the property for 546,360,910 mcf. Defendant
apparently disputes the use of the Exxon’s field price in
determining gross income from the property with respect to
500,226,478 mcf of the gas in issue.

42a

any) of costs incurred for field compression, dehydra-
tion, and gathering of the gas. The “gross income
from the property” calculated for the raw gas stream
that was not processed prior to sale was this gross
value at the wellhead, reduced by the royalties paid
on the raw gas stream.

Processing the natural gas produces natural gas
liquids and residue gas. Exxon calculated the gross
value at the wellhead for the portion of the raw gas
stream converted into natural gas liquids by multi-
plying the market value for each natural gas liquid
product (the sale price or, in the absence of a gas
plant sale, the fair market value at the plant) by
Exxon’s gross working interest share of the volume
of that product credited back to the lease under the
applicable processing agreement. For residue gas, the
gross value at the wellhead was calculated by multi-
plying the applicable field price by Exxon’s gross
working interest share of the residue gas volume and
reducing the product by the amount (if any) of costs
incurred for field compression. The “gross income
from the property” for the raw gas stream that was
processed was the sum of the gross values at the
wellhead for the liquid portion and the residue gas
portion of the raw gas stream, reduced by the roy-
alties paid with respect to that gas.

Through these various formulas, Exxon concluded
that the sum of gross incomes from the property at-
tributable to gas produced from all of the 504 prop-
erties was $272,292,009, and reported this sum on
its 1974 tax return. Exxon also reported gross in-
come from the property, net of royalty and other
working interest owned shares, of $566,298,973, at-
tributable to oil and condensate production. Accord-
ingly, Exxon’s return reported $838,590,982 in total

43a

ss income from the 504 properties, income froin
which the allowable percentage depletion deduction
could be taken.

C. Calculating the § 613 Depletion Deduction

Having calculated the “gross income from the prop-
erty,” Exxon proceeded to calculate its allowable de-
pletion deduction. Section 611(a) of the Internal
Revenue Code provides:

In the case of mines, oil and gas wells, other
natural deposits, and timber, there shall be al-
lowed as a deduction in computing taxable in-
come a reasonable allowance for depletion and
for depreciation of improvements, according to
the peculiar conditions in each case; such reason-
able allowance in all cases to be made under reg-
ulations prescribed by the Secretary.

Section 613 provides that

the allowance for depletion under section 611
shall be the percentage, specified in subsection
(b), of the gross income from the property ex-
cluding from such gross income an amount equal
to the rent or royalties paid or incurred by the
taxpayer in respect of the property. Such allow-
ance shall not exceed 50 percent of the taxpayer's
taxable income from the property (computed
without allowance for depletion).

(b) Percenage depletion rates.—The mines,
wells, and other natural deposits, and the per-
centages, referred to in subsection (a) are as
follows:

44a

(1) 22 percent—
(A) oil and gas wells....

Exxon multiplied its gross income from the property
amounts for each of the 504 properties by the 22
percent rate to compute its deduction with respect to
each property. Exxon further determined the “tax-
able income from the property” limitation for each
of these properties by subtracting all appropriate de-
ductions from each property’s gross income and mul-
tiplying the remainder by 50 percent. To determine
the percentage depletion deduction for each property
under the rule of § 613, Exxon selected the greater
of (a) the “22 percent” figure (subject to the “50
percent limitation”) or (b) the cost depletion amount,
if any. Having made these calculations, Exxon
claimed depletion deductions under these provisions
of $184,093,768 on its return.

Exxon paid its tax. Thereafter, the Commissioner
of Internal Revenue audited Exxon and deter-
mined that on its return Exxon had overstated its
total gross income with respect to the 504 properties
by $50,253,856. The government also maintains that
Exxon, in its computations, failed to exclude certain
royalty payments, which inflated its gross income
from the properties. Deficiencies and interest were
assessed, which Exxon paid.“ These deficiencies re-

18 A deficiency and interest were assessed against Exxon in
the amount of $132,539,584.56 ($52,694,101 in tax and
$79,845,483.56 in interest) on December 30, 1985, $8,155,850.92
($2,665,367 in tax and $5,490,483.92 in interest) on December
22, 1987, $9,008,554.54 ($2,665,367 in tax and $6,343,187.54
in interest) on December 28, 1988, and $16,285,945.54
($6,739,242 in tax and $9,546,703,54 in interest) on December

45a

lated in part to the Commissioner’s audit adjustment
reducing the $184,093,768 in depletion deductions
claimed by Exxon by $11,105,698. As a result,
Exxon’s federal income tax liability for 1974 in-
creased by $5,330,734.

D. The Dispute: The Proper Representative Mar-
ket or Field Price

It seems clear that the Commissioner arrived at
this adjustment by employing a ““net-back” methodo-
logy, under which he subtracted from Exxon’s reve-
nues from the sale of residue and non-processed gas
under the TIC contracts both the transportation costs
incurred by the company in delivering the gas to its
customers and the royalties and payments made to
other working interest owners. The net-back meth-
odology supposedly was used by the Commissioner
for the first time for the 1974 tax year. During the
audit for 1974, the Commissioner also proposed to
use the net-back methodology for the tax years from
1968 to 1973, but changed his mind after receiving
information demonstrating that the net-back meth-
odology for 1968 through 1973 would have yielded
higher, not lower, depletable gross income. The de-
pletable gross income for residue and non-processed
gas as determined by the Commission’s net-back
method and the figures generated by Exxon’s return
method for the tax years 1968-1974 are as follows:

26, 1989. Exxon paid these deficiencies on December 30, 1985,
December 31, 1987, December 30, 1988, and January 8, 1990,
respectively.

46a

Total Royalty Trans- Depletable Depletable
Sales andother portation Income Per Income
Amount Payments Costs Net-Back Per Return

1968 95.3 11.7 6.4 77.2 58.8
1969 102.9 13.2 6.5 83.2 69.8
1970 116.6 14.5 7.0 95.1 77.1
1971 124.1 15.8 7.5 100.8 83.1
1972 136.2 17.5 8.1 110.6 91.3
1973 143.6 19.9 8.7 115.0 99.8
1974 162.4 32.2 11.7 118.5 168.8 4

The Service’s audit was based on its view that for
the purpose of a depletion deduction, “gross income”
from the property cannot exceed actual total sales
revenues, as the table above indicates was the case
in 1974. This, in essence, is the basis for the govern-
ment’s motion for judgment on the pleadings. After
the audit, the Service’s refusal to refund the de:
ficiency, and Exxon’s filing suit in this court, the
government also took the position that even if Exxon
were allowed to base its gross income from the prop-
erty on a representative market or field price, the
field price Exxon used in its 1974 return is not an
appropriate field price with which to calculate a de-
pletion deduction under § 613. This position forms
the basis for defendant’s motion for summary judg-
ment.

II

Before the court are two motions filed by the gov-
ernment—one for judgment on the pleadings and one

** As demonstrated in this table, the “glitch” at bottom in
this matter is that in 1974 Exxon’s depletable income exceeded
its sales revenues, apparently the first time that this had hap-
pened. One can reasonably speculate that the sudden jump in
depletable income between 1973 and 1974 is attributable to the
oil embargo of 1973-74. See Aeron Marine Shipping Co. v.
United States, 26-Cl. Ct. 946, 954-56 (1992).

47a

for summary judgment. The rules of this court pro-
vide that if matters outside the pleadings are pre-
sented to and not excluded by the court on a motion
for judgment on the pleadings, the motion shall be
treated as a motion for summary judgment. The par-
ties have submitted the evidentiary support outside
the pleadings required for a summary judgment mo-
tion, but throughout this litigation the pleadings mo-
tion has had an existence of its own.” Because of
this, and because the court’s conclusions on the plead-
ings motion might make its interpretation of the sum-
mary judgment motion more clear, for the purposes
of this order the two shall be treated as separate
end distinct.

The government’s motion for judgment on the plead-
ings is based on the uncontested fact that plaintiff’s
gross income for the gas generated on these prop-
erties exceeds the actual total sales revenues from this
gas. As indicated above, this reasoning formed the
basis for the IRS’s deficiency assessment. The gov-
ernment argues its contention in this regard is sup-
ported by the basic depletion statute, applicable regu-
lations, and supporting case law. Exxon, on the other
hand, argues that its depletion deduction claim was
calculated in strict compliance with statute, regula-
tion, and precedent.

15 Soon after filing suit, Exxon moved for summary judg-
ment. After an allowed period of discovery, the government
offered its opposition and cross-moved for summary judgment.
Two months later, it moved for judgment on the pleadings,
focusing solely on the legal issue presented by its statutory
interpretation of § 613. Later, admitting to the existence of
a material fact issue that would preclude summary judgment
in its favor, Exxon withdrew its motion. Thus, the govern-
ment’s two motions remain to be decided.

48a

A. Standards for a Motion for Judgment on the
Pleadings

Recently, this court comprehensively reiterated the
standards for deciding a motion for judgment on the
pleadings in J.M. Huber Corp. v. United States, 27
Fed. Cl. 659, 661-662 (1993). For purposes of ruling
on a motion for judgment on the pleadings, the tra-
ditional standard is that a court must assume that all
well-pleaded facts in the non-movant’s pleading are
true, that all controverted assertions of the movant’s
pleadings are false, Hospital Bldg. Co. v. Trustees
of Rex Hospital, 425 U.S. 738, 740 (1976), and the
court must ignore any assertions in the pleadings
that amount to legal conclusions. Olpin v. Ideal Nat’l
Ins. Co., 419 F.2d 1250, 1255 (10th Cir. 1969). The
motion therefore cannot be granted if the non-moving
party has alleged facts that, if proved, would prevent
the movant from prevailing. Austad v. United States,
386 F.2d 147, 149 (9th Cir. 1967). This court’s pred-
ecessor, the Court of Claims, adopted a more rigorous
standard, namely: “A motion for judgment on the
pleadings should be denied unless it appears to a cer-
tainty that plaintiff is entitled to no relief under any
state of facts which could be proved in support of his
claim.” Branning v. United States, 215 Ct. Cl. 949,
950-51 (1977) (emphasis supplied). This more rig-
orous standard has been approved of in this court.
See generally J.H. Huber Corp., 27 Fed. Cl. at 662.
Therefore, the sufficiency of plaintiff’s claim as stated
in its complaint, reframed in its pretrial filings, or
constructed in response to defendant’s arguments will
be judged by measuring all facts thus far identified
against the legal components of a given cause of
action. Id.

49a
B. Construing the Code and its Regulations

The government’s motion turns on the interpreta-
tion of § 618 and a part of a corresponding regula-
tion written by the Internal Revenue Service. In
questions of statutory construction, the starting
point in every case is the language itself. Johns-
Manville Corp. v. United States, 855 F.2d 1556, 1559
(Fed. Cir. 1988) (quoting Greyhound Corp. v. Mt.
Hood Stages, Inc., 487 U.S. 322, 330 ( 1978)). This
is not merely a recitation of the obvious, for there are
instances when the plain language of a statute does
not express the intent of the legislature with the force
of precision. When such an instance arises, the plain
meaning of the statute will prevail absent a very clear
legislative intent to the contrary. Aaron v. SEC, 446
U.S. 680, 697 (1980). If the meaning of a statute
ean be discerned within its words and does not pro-
duce an absurd result, that construction should con-
trol, and no resort should be made to extrinsic aids
such as legislative history. The Federal Circuit has
expressed this directly with respect to tax law, stat-
ing that “‘[w]here the language is plain and admits
of no more than one meaning the duty of interpreta-
tion does not arise and the rules which are to aid
doubtful meanings need no discussion.’” Henry v.
United States, 793 F.2d 289, 293 (Fed. Cir. 1986)
(quoting Caminetti v. United States, 242 U.S. 470,
485 (1917)).

It is possible, though, for a statute to offer a plain
meaning and a not-absurd result, but still not ex-
press the intent of Congress. Although statutory con-
struction should begin and end with the language if
it is clear, the legislative history may be examined
for the purpose of determining whether the “plain”

i

50a

meaning of the text is indeed as clear at first glance
as the language would otherwise evince. Here. the
court follows the Federal Circuit, which in Madison
Galleries, Ltd. v. United States stated:

Where the plain language of the statute would
settle the question before the court, the legisla-
tive history is examined with hesitation to de-
termine whether there is a clearly expressed leg-
islative intention contrary to the statutory lan-
guage. . . . Sometimes the literal language of
some part of a statute may seemingly contradict
the intent of the statute taken as a whole... .
Absent a clear cut contrary legislative intent,
the statutory language is ordinarily regarded as
conclusive.

Madison Galleries Ltd. v. United States, 870 F.2d
627, 629-30 (Fed. Cir. 1989), quoted in J.M. Huber
Corp. v. United States, 27 Fed. Cl. 659, 664 (1993)
(emphasis supplied).

For this case, the court must also note that Treas-
ury regulations, like the Internal Revenue Code they
explain, should be examined by a similar “plain mean-
ing’ standard. If the terms of a regulation are un-
ambiguous, they should be accorded their plain and
obvious meaning. Long v. United States, 10 Cl. Ct.
46, 54 (1986). Treasury regulations must be sus-
tained unless unreasonable and plainly inconsistent
with the revenue statutes. Commissioner v. South
Texas Lumber Co., 333 U.S. 496, 501 (1948).

In its motions, the government urges that the con-
trolling regulation, if interpreted by examining the
plain language alone, produces an absurd result which
does not harmonize with the statute the regulation
was drafted to explain. The court agrees with the

S5la

government that the discrete legal issue to be re-
solved is whether the law permits percentage deple-
tion deductions to be based on figures that exceed
actual sales revenues. The government’s perspective
on this question is influenced heavily by its reading
of the legislative history of § 613, and so to determine
if the regulation as simply interpreted departs from
congressional intent the legislative history of the stat-
ute must be examined.

C. The Background of the Depletion Deduction

1. Congress Provides for Depletion Deductions

Congress first allowed taxpayers to take deductions
for depletion in determining the taxable income gen-
erated from natural resources in 1913, Revenue Act
of 1913, Pub. L. No. 68-16, § II(G) (b), 38 Stat. 114,
172-73 (1918). Depletion is the exhaustion of nat-
ural resources, such as mines, wells, and timberlands
as a result of severance production. The deduction
returns to the owner or extractor of the resources his
capital investment pro rata over the resources’ pro-
ductive life. In addition to allowing the taxpayer to
regain his capital expenditures, the depletion deduc-
tion was based in the belief that it would encourage
“extensive exploration and increasing discoveries of
additional minerals to the benefit of the economy and
strength of the Nation.” United States v. Cannelton
Sewer Pipe Co., 364 U.S. 76, 81 (1960). The deple-
tion deduction first specifically referred to oil and gas
wells in 1916. Revenue Act of 1916, Pub. L. 64-271,
§ 12(a) (Second), 39 Stat. 756, 768 (1916).

_ The depletion deduction was modified soon there-
after in 1918, when Congress allowed oil and gas pro-
ducers to take a deduction based on “discovery deple-
tion,” in which the deduction would be “based upon

52a

the fair market value of the property at a date of the
discovery” of the resource. Revenue Act of 1918, Pub.
L. No. 65-254, § 234(a)(9), 40 Stat. 1057, 1078-79
(1919). The Treasury regulation implementing the
discovery depletion deduction provided that the fair
market value of a mineral property was to be deter-
mined by the present value at the date of discovery
of the reserve’s estimated future value upon produc-
tion. Treas. Reg. 45, art. 206 (1921). But, to protect
against abuses of this depletion allowance, in 1921
Congress provided that the “depletion allowance based
on discovery value shall not exceed the net income,
computed without allewance for depletion, from the
property upon which the discovery is made... .”
Revenue Act of 1921, § 234(a)(9). A Senate Report
on the bill explains that the law was modified “to
make certain that the depletion deduction when based
upon discovery value shall not be permitted to offset
or cancel profits derived by the taxpayer from a sep-
arate and distinct line of business... .” S. Rep. No.
275, 67th Cong., Ist Sess. 14-15. In 1924, this limita-
tion fixed by net income was drawn tighter still as
Congress moved to reduce the allowable depletion de-
duction to 50 percent of the taxpayer’s net income

from the property. Revenue Act of 1924, ch. 234,
43 Stat. 253 (1924).*

2. Percentage Depletion Deductions are Adopted

Discovery depletion, however, quickly produced
problems of administration. A 1926 House Report
remarked that

the administration of the discovery provision of
existing law in the case of oil and gas wells has

16 See infra note 19 and accompanying text.

53a

been very difficult because of the discovery valu-
ation that had to be made in the case of each
discovered well. In the interest of simplicity and
certainty in administration the Senate amend-
ment provides for a percentage depletion method
of calculation.

H.R. Rep. No. 356, 69th Cong., Ist Sess. 31 (1926).
Congress determined that instead of discovery deple-
tion, “the best way to [determine the depletion deduc-
tion] is to provide that an arbitrary percentage on
the gross value of each year’s yield be chalked off for
depletion. We figure it on gross income instead of net
income, because the net income from oil wells varies
greatly.” 67 Cong. Rec. 3762 (1926). The approxi-
mate percentage to be used by producers was fixed
at 27% percent. The new percentage depletion deduc-
tion was enacted by Congress in 1926, Revenue Act
of 1926, § 204(c) (2), ch. 27, 44 Stat. 9 (1926). The
statute provided:

In the case of oil and gas wells the allowance
for depletion shall be 27% per centum of the
gross income from the property during the tax-
able year. Such allowance shall not exceed 50
percentum of the net income of the taxpayer
(computed without allowance for depletion) from
the property, except that in no case shall the
depletion allowance be less than it would be if
computed without reference to this paragraph.

The change in the Code was welcomed “as a means
of simplifying the administration of the ‘discovery
depletion’ allowance under which depletion had been
based on the fair market value of the mineral prop-
erty after the discovery of the valuable resource.”

eee eee re

54a

Hugoton Prod. Co. v. United States, 161 Ct. Cl. 274,
277, 315 F.2d 868, 869 (1963).

Although discovery depletion deductions were phased
out in favor of ones based on the fixed percentages,
the reason for allowing the deduction (providing for
the recovery of capital expenditures) did not change.
Importantly, what did change was the referent upon
which the deduction would be based: the “fair market
value” measure adopted in 1918 was replaced by a
calculation based on “gross income from the prop-
erty.” When the percentage depletion section was
adopted, Congress did not define gross income. The
term had, however, been addressed in Treasury reg-
ulations dating to the adoption of the net income
limitation on depletion deductions in 1921. Treasury
Regulation 62, article 201(h), adopted in connection
with the Revenue Act of 1921, provided the follow-
ing idea for “gross income from the property”: “If
the mineral products are not sold as raw material
but are manufactured or converted into a refined
product, then the gross income shall be assumed to
be equivalent to the market or field price of the raw
material before conversion.” This regulation indi-
cates that even before percentage depletion was
adopted, the deduction was to be pegged to the value
of oil in its most rudimentary state instead of any
refined state, preventing extractors from overrepre-
senting the value of their products due to product
refining of some sort.

This regulation apparently did not stop some com-
panies from reporting figures for purposes of deduc-
tion based on a value of the product in a more refined
state. Having adopted the Revenue Act of 1926 (and
with it percentage depletion), the Congressional Joint

55a

Committee on Internal Revenue Taxation remarked
in a report on the new legislation that “[t]he larger
[gas-producing] companies have probably reported
gross income from sales to the consumer rather than
from the price of gas as delivered from the property.”
Preliminary Report—Depletion—Oil and Gas Reve-
nue Act of 1926, 69th Cong., 1st Sess. 23 [hereinafter
1926 Report]. Accordingly, the report determined
that to prevent abuses of this sort,

[i]n the case of taxpayers who are operators,
refiners, transporters, etc., the gross income from
the property must be computed from the produc-
tion and posted price of oil, as the gross receipts
from a refined and transported product cannot
be used in determining the income as relating to
an individual tract or lease.

Id. at 12-13. The Joint Committee’s thoughts were
expressed in Treasury regulation 74, article 221(i),
promulgated pursuant to the Revenue Act of 1928,
which provided the following rule for computing gross
income from a refined oil or gas product sold away
from the wellhead:

If the oil and gas are not sold on the property
but are manufactured or converted into a refined
product or are transported from the property
prior to sale, then the gross income shall be as-
sumed to be equivalent to the market or field
price of the oil and gas before conversion or
transportation.

Slight amendments were made to this regulation in
1933 and 1936. When the 1939 Internal Revenue
Code was adopted, adjustments were made to the
regulation once again, but the substance of the pro-
vision did not change.

56a

With the statute and the new regulation in place,
oil and gas producers could take percentage depletion
deductions based on income generated by the property,
with the income pegged to the value of the resource
in its unrefined state at the wellhead. Producers of
hard minerals were not allowed to take a similar de-
duction. The Treasury was hesitant to extend per-
centage depletion to mineral producers because it was
even harder to determine the value of hard minerals
in their unrefined state than it was toe determine the
value of unrefined gas. The Treasury discussed the
administrative differences between oil and gas and
hard minerals through the testimony of 4.H. Bartho-
low, Special Assistant to the Secretary of the Treas-
ury, who testified before Congress that

while the bureau is having difficulty in admin-
istering the percentage depletion provisions in
the case of oil and gas wells, the Treasury be-
lieves that the problem of administering like pro-
visions in the case of mines would be infinitely
greater. The foremost reason is that the field
price of the oil or gas at the well indicates the
income from the property, while in the mining
industry, where there is no general field price for
the ore at the mine and where the larger taxpay-
ers do their own concentrating, smelting, refining,
transporting, and marketing, all that is known
is that the refined o» fabricated product was sold
for a certain amoui.:. There is thus presented the
insuperable difficulty of dividing up the resulting
income among all those various activities—
marketing, thansporting, smelting, refining, min-
ing, etc.—and then allocating the proper portion

ee

—_—

57a

to the mining uperation which would be the in-
come from the mine.

Hearings before the Joint Committee on internal
Revenue Taxation, 71st Cong., 3d Sess. 111 (1930).

Percentage depletion was extended to metal, coal,
and sulphur mines in 1932. As with oil and gas prop-
erties, the deduction was to be calculated as a per-
centage of “gross income from the property.” In
Treasury Regulation 77, article 221(g), adopted in
1933, gross income was defined as

the amount for which the taxpayer sells (a) the
crude mineral product of the property or (b) the
product derived therefrom, not to exceed in the
case of (a) the representative market or field
price ... or in the case of (b) the representative
market or field price... of a product of the kind
and grade from which the product sold was
derived, before the application of any processes.

The depletion deduction statute in effect in 1974 pro-
vided, in pertinent part:

[Tjhe allowance for depletion under section 611
shall be the percentage, specified in subsection
(b), of the gross income from the property ex-
cluding from such gross income an amount equal
to the rent or royalties paid or incurred by the
taxpayer in respect of the property. Such allow-
ance shall not exceed 50 percent of the taxpayer’s
taxable incoine from the property (computed
without allowance for depletion ).

I.LR.C. § 613(a).

58a

3. Treasury Reguiation § 1.613-3

The relevant statutory provisions and regulations
for the 1974 taxable year which govern the present
dispute have changed only insignificantly since the
1930s. The limitation confining the deduction to fifty
percent of “net income from the property” was
changed to “taxable income from the property” in
1954. The governing language of § 613 was adopted
by the Public Debt and Tax Rate Extension Act of
1960, Pub. L. No. 86-564, 74 Stat. 290. Thus, for the
1974 taxable year, the determination of gross income
from oil and gas producing properties was made with
reference to Treasury Reg. § 1.618-3(a) :

In the case of oil and gas wells, “gross income
from the property”, as used in section 613(c) (1),
means the amount for which the taxpayer sells
the oil or yas in the immediate vicinity of the
well. If the oil or gas is not sold on the premises
but is manufactured or converted into a refined
product prior to sale, or is transported from the
premises prior to sale, the gross income from the
property shall be assumed to be equivalent to the
representative market or field price of the oil or
gas before conversion or transportation.

The language of this regulation, governing the sale
of oil and gas away from the well premises, did not
change significantly for years. Still, there was some
concern that the field price of a produced resource
could be greater than the price actually received by
the producer for the resource under a pre-existing
contract for sale, concerns that first arose in the
1920s. Recognizing that a field price could in fact be
higher than a price based on actual revenues from off-

59a

premises sales, the Treasury promulgated a regula-
tion, applying to hard minerals only, establishing a
rebuttable presumption that such a market price is
not representative. Specifically, Regulation § 1.613-4
(c) (6), put into its current form in 1972, provides:

It shall be presumed that a price is not a repre-
sentative market or field price... if the sum of
such price plus the total of all costs of the non-
mining processes (including nonmining transpor-
tation) which the taxpayer regularly applies to
his ore or mineral regularly exceeds the taxpay-
er’s actual sales price of his product. ... In
order to rebut the presumption . . . it must be
established that the loss on nonmining operations
is directly attributable to unusual, peculiar, and
nonrecurring factors rather than to the use of
a market or field price which is not represen-
tative.

As is apparent, this regulation applies to hard min-
erals only, and not to oil and gas production. At one
point the Secretary of the Treasury proposed extend-
ing the regulation to cover oil and gas as well, but the
proposal was withdrawn, leaving the language in
§ 1.613-3(a) unchanged. 36 Fed. Reg. 19256 (1971);
33 Fed. Reg. 10700 (1968).

The foregoing summarizes the history of the Code
language and Regulation § 1.613-3(a) through 1974,
the taxable year in issue. In its brief, Exxon urges
that the plain meaning of the regulation is supported
by an analysis of its life in the Code. The court
agrees with Exxon that the regulation’s plain mean-
ing is indeed supported by its evolution. Here, the
legisiative history clearly indicates that the foca] point
of a depletion deduction was to be the price of the re-

60a

source at the wellhead, deemed to be the representa-
tive market or field price. There is no persuasive
indication that Congress intended sales prices of the
gas to be determinative or that sales prices constituted
a ceiling above which no deduction could be allowed.

a. Defendant’s Motion

Exxon pleads and admits that the price at which
it sold its gas was less than the representative market
or field price, and that it used a representative market
or field price as the measure of its gross income from
the property in computing its depletion deduction.
Reduced to its core, the government’s motion for judg-
ment on the pleadings contends that Congress intended
the field price to limit gross income for calculating
depletion deductions, and therefore gross income from
the property cannot in any circumstance exceed the
gross revenue from a producer’s sales of the gas.

b. Exxon’s Interpretation of the Regulation
(and Applicable Precedent)

Exxon’s argument in response to the government’s
motion for judgment on the pleadings is essentially
the set of three contentions. The first is that the plain
language of the regulation insists on the use of a
market comparison method. Section 611 of the Code
allows for a deduction representing depletion to be
taken, and that the deduction is to be calculated as
provided by the regulations. Regulation 1.613-3(a)
establishes the now-familiar definition that the deduc-
tion shall be based on gross income, which in turn
shall be assumed to be the representative market price
of the resource. Court must turn to the regulations
promulgated by the Treasury if the language of the
statute does not operationally define key terms, and

6la

the plain language of a regulation should control as
it is assumed that a regulation means what it says.
Regulations have the force and effect of law, and here
the court examines a regulation that states clearly
that “the gross income from the property shall be as-
sumed to be equivalent to the representative market
or field price ....” (emphasis supplied). Under the
standards that have been approved in this circuit for
interpreting Treasury regulations, the court is in-
clined to accept Exxon’s interpretation.

That the plain language of the regulation produces
a rational, intended tax rule is supported by what can
be called Exxon’s second contention: its interpreta-
tion of the regulation, as opposed to the government’s,
makes more sense in the context of depletion deduc-
tions. As the discussion of the legislative history of
the depletion deduction indicates, those who shaped
this area of the law felt that the best indication of the
true “value” of a resource is what the resource is
worth before it is refined. One recalls the 1926 Joint
Committee report, which stated that gross income
must be calculated from the production price of oil
instead of from the receipts generated by the refined
product. As Exxon notes, the regulation specifically
provides for this method of valuation to peg the value
of the oil or gas to its worth at the wellhead. The
very purpose of a depletion deduction is to return to a
well operator the value of his capital investment, an
investment that is returned over the useful life of the
resource base. The value at the wellhead, if it can be
determined, should control. That the wellhead price
should be examined is supported by the shift from
discovery depletion to percentage depletion described
above: Congress found that percentage depletion
would be an easier way of calculating the depletion of

62a

the resource because the Treasury would no longer
need to determine the value of the well’s resource on
the date of its discovery.

Exxon’s third contention is that its interpretation
of the regulation has found approval in the courts.
T'wo cases in this court’s predecessor, the Court of
Claims, considered the propriety of using a represen-
tative market or field price to determine the taxpay-
er’s depletion deduction. The government correctly
asserts neither Hugoton Production Co. v. United
States, 161 Ct. Ct. 274, 315 F.2d 868 (1963) [Hugo-
ton I], Hugoton Production Co. v. United States, 172
Ct. Cl. 444, 349 F.2d 418 (1965) [Hugoton II], nor
Panhandle Eastern Pipe Line Co. v. United States,
187 Ct. Cl. 129, 408 F.2d 690 (1969) [Panhandle]
resolved whether a taxpayer who sells gas away from
the wellhead can calculate its depletion deduction
using a market price if the market price were to ex-
ceed the gross revenue actually received from the
buyer. These cases, however, do examine the law of
depletion deductions generally and the regulation
specifically and provide instruction that must be
heeded even if we are not now examining the precise
issues that were once before the Court of Claims.

In Hugoton I the taxpayer, an integrated gas pro-
ducer, contended that its gross income for depletion
purposes should be computed by multiplying the quan-
tity of gas which it processed and sold in a year by
the representative market or field price at the well-
head (the “market comparison” method). The gov-
ernment responded that since there was no represen-
tative price for the gas, the gross income should be
calculated by taking the gross proceeds from the sale
of plaintiff’s processed gas and subtracting therefrom

63a

all costs attributable to gathering and proeessing the
gas (the “proportionate profits method”). (The court
notes that this is the method the IRS used to compute
the depletion deductions it allowed plaintiff in this
case.) The court turned first to the applicable regula-
tion, 1.613-3(a), and noted that this regulation was
“of unquestioned validity, and [is] thus binding upon
both parties.” Hugoton I, 161 Ct. Cl. at 279-80, 315
F.2d at 871. The regulation had “remained substan-
tially unchanged through a series of enactments[, and
‘Jregulations and interpretations long continued with-
out substantial change, applying to unamended or sub-
stantially reenacted statutes, are deemed to have re-
ceived congressional approval! and have the effect of
law.’” Id. at 280 n.14, 315 F.2d at 871 n.14 (quoting
Helvering v. Winmill, 305 U.S. 79, 83 (1938) ).

Although the Court of Claims approved the use of
a market comparison method for calculating gross
income, it did so notwithstanding a recognition that
the method had “inherent uncertainties.” The govern-
ment contended that there was no representative or
field price for the raw gas at the wellhead, and the
court found in its findings that “[b]ecause there are
a variety of factors causing differences in the value of
natural gas located within the same or nearby fields,
because relatively small proportions of gas are sold
at the wellhead, and because almost all such sales are
under long-term contracts ,” id. at 280, 315 F.2d at
871, constructing a market price is difficult. Never-
theless, the court was compelled to accept the plain-
tiff’s approach and use the calculation method that
best reflected the mandate of the governing regulation.
The court stated:

We do not say that as an original matter the pro-
portionate profits method might not prove more

64a

appropriate or feasible than the market compari-
son approach, or that the Commissioner of In-
ternal Revenue could not validly embody this
method in its regulations. Indeed, we recognize
that despite its complexities, the proportionate
profits method has the advantage of being related
directly to the taxpayer’s own income and of al-
lowing computation of tax liability by reference
only to the taxpayer’s books. Nonetheless, the
CIR—not without realizing the possible alterna-
tives and their relative advantages and disad-
vantages—has chose the market comparison
method, and he has defended its application when
productive of larger revenues. On the basis of the
record compiled in this case, we are convinced
that the problem of determining a representa-
tive market or field price for this taxpayer’s gas
is not of such unusual or inordinate difficulty as
to preclude use of the method prescribed as the
norm by the applicable regulations.

Hugoton I, 161 Ct. Cl. at 282-83, 315 F.2d at 872-73.

The Court of Claims remanded the case to the trial
commissioner to determine the representative market
price based on the average of all contracts in effect
in each year under which comparable gas was sold.
Plaintiff objected to the later determination on the
ground that the government’s figures incorrectly used
interstate sales of gas—a problem (plaintiff averred)
because it had only sold gas intrastate. Plaintiff’s
idea was to except to these findings and call on the
court to decide that no comparative sales could be
determined and that therefore a proportionate profits
formula should be used instead of a market compari-
son. Noting that this was the very idea it had rejected

65a

in Hugoton I, in Hugoton II the Court of Claims held
that a market comparison had to be used. The court
referred to United States v. Cannelton Sewer Pipe
Co., 364 U.S. 76 (1960), which held that the deple-
tion allowance is intended to be based on the construc-
tive income from a raw product if marketable in that
form and not on the value of the finished article. Ac-
cordingly, the court in Hugoton concluded that per-
mitting the plaintiff to use a proportionate profits
formula would violate the spirit of Cannelton. Under
Cannelton, “for purposes of depletion, integrated pro-
ducers are to be treated on the same footing as those
of his [sic] competitors who choose not to integrate.
Having established a wellhead price, those processes
increasing the value of the gas must necessarily be
held to be of no consequence.” Hugoten II, 172 Ct.
Cl. at 458, 349 F.2d at 426-27. Further, Hugoton II
reiterated that if a representative price can be deter-
mined for the oil or gas, then that price must be used
in a market comparison. Unlike hard minerals, for
which a taxpayer can choose the alternative propor-
tionate profits valuation if no field price can be deter-
mined, “[n]o such choice has been prescribed by the
Commissioner in the oil and gas field. As can be seen
clearly from the Regulation quoted earlier in the opin-
ion, [the Commissioner] has chosen to embody in it
only one concept—‘representative market or field
price.’” Id. at 459, 349 F.2d at 427.

As noted in the Hugoton opinions and in Panhan-
dle, fixing a representative price for a market com-
parison valuation can present difficulties. Before ad-
dressing the specific reasons why the government says
the regulation cannot be used by plaintiff in this case,
the court reiterates that it is bound to follow the letter
of the regulation unless the result is patently absurd.

66a

The court notes that, importantly, the regulation
(along with its substantially similar predecessors)
could have been revised on a number of occasions since
the 1920s to effect a result that would perhaps more
perfectly represent Congressional intent. This, how-
ever, has not been done, and the court notes that in
the nine years that elapsed between Hugoton II and
the taxable year at issue here the Commissioner did
not feel compelled to change the regulation in any
way.”
ec. The Government’s Counterargument

As noted earlier, the assertion driving the govern-
ment’s argument on its motion for judgment on the
pleadings is that the Code does not allow a depletion
deduction to be based on a field price if that field price
exceeds the actual price obtained by sale. The govern-
ment contends that the very reason why Congress
enacted depletion deduction was to prevent the deduc-
tion from being calculated from anything but the net
income from the gas producing property. This was
manifested by the “net income” limitation, originally
providing that a deduction could not exceed 100% of
taxable income from the property. This particular
limitation, however, expressed in the second sentence
of $613, stands apart from the first sentence of the

17 No doubt the Commissioner of Internal Revenue is well
aware of litigation in this area. If for some reason he
finds that the market comparison method is not generally
workable then he would be within the ambit of his statu-
tory powers to amend the applicable Regulation to pro-
vide some alternative method. Until that time we feel
that it is not within our judicial powers to legislate in his
place.

Hugoton II, 172 Ct. Cl. at 463, 349 F.2d at 420.

a ,

67a

section which allows for the deduction to be based
on “gross income from the property.” *

The government further contends that Congress
sought to prevent deductions that contained in their
calculations post-extraction additives such as refine-
ments away from the wellhead, transportation, and the
like, a concept embodied (says defendant) in the rep-
resentative market price. In its words, “[t]he repre-
sentative market or field price is the tool used to cut
back actual revenues received by taxpayers from the
sale of manufactured or transported oil and gas pro-
duced in order to calculate percentage depletion de-
ductions with respect to applicable properties.” The
court cannot agree that such a tool exists. The court
agrees with Exxon that the government’s construction
of the statute allows the government to ignore the de-
pletion calculation rules when post-production factors
away from the wellhead decrease the value of the gas.
In Exon’s words, “the Secretary easily could have pre-
scribed use of the ‘representative market or field
price’ only as a ceiling on gross income from the prop-
erty, but instead he adopted a regulatory definition
that operates as a two-way street.” (emphasis in
original ).**

18 Section 613 provides in pertinent part:

[T]he allowance for depletion under section 611 shall be
the percentage, specified in subsection (b), of the gross
income from the property excluding from such gross
income an amount equal to the rent or royalties paid or
incurred by the taxpayer in respect of the property.
Such allowance shall not exceed 50 percent of the tax-
payer’s taxable income from the property (computed
without allowance for depletion).

#® The court is quite mindful of the general appeal of the
government’s fundamental argument in this case, viz., it is

68a
Finally, the government draws the court’s atten-
tion to a table it has drawn up to illustrate that if
gross income based on a very high representative mar-

“absurd” to allow a taxpayer to claim a deduction based on
income that isn’t actual income, that is, income not pocketed
from sales of the product. Allowing deductions based on
“representative” prices may not be the clearest example of
common sense for the reasonable person. Tax provisions,
however, are not accidental, and the court finds that § 1.613-3,
intended to implement a tax policy that encourages drilling
and most accurately reflects the true value of the natural
resource, cannot be massaged to avoid larger than anticipated
deductions. Consider in this regard Cohen v. United States,
No. 92-5013, slip op. at 10 (Fed. Cir. June 4, 1993): ‘“Taxa-
tion, perhaps more so than all other relationships between
government and the governed, operates within a belief on both
sides that the rules should be clear and uniformly applied... .
It is rare that tax law bears any recognizable relationship to
common sense, but this one does.”” Unlike the court in Cohen,
the present case does not afford the luxury of presenting a
tax law that clearly comports with common sense. But, as
the court has tried to show, the law, which has remained
largely unchanged for years, has not suddenly become so
ridiculous that it must be rejected out of hand.

Continuing on this thought, the government argues that
“gross income from the property,” as set out in § 618, should
be interpreted in a manner not inconsistent with the term
“gross income” as defined in § 61 of the I.R.C., the section
that generally defines what “income” is. In other words, the
government urges that gross income must have the same
meaning in both sections to avoid what it sees as an unin-
tended result. At oral argument, the government supported
this argument with a reference to Commissioner v. Keystone
Consolidated Industries, Inc., 61 U.S.L.W. 4481, 4483 (U.S.
May 24 ,1993), which stated: “It is a ‘normal rule of statu-
tory construction,’ that ‘identical words used in different parts
of the same act are intended to have the same meaning.’
Atlantic Cleaners & Dyers, Inc. v. United States, 286 U.S.
427, 433 (1932).” As applied to this case, the court notes

CC

69a

ket or field price happened to greatly exceed actual
taxable income based on sales revenues, the percentage
depletion deduction as calculated and allowed could
far exceed the taxpayer’s actual income. The court
understands that such a circumstance might fly in the
face of the limitations on deductions enacted as early
as 1916, but if the deduction was intended to repre-
sent a return of the captial expenditure, to be based
on the value of the resource (which the legislative

that the general income definition and the depletion deduction
rules, though both revenue laws incorporated into Title 26,
are not parts of the same act; they were adopted at different
times by different statutes. The Supreme Court has recog-
nized the impact that context has on definition in, among other
cases, Atlantic Cleaners. As the Court put it:

Most words have different shades of meaning and con-
sequently may be variously construed, not only when they
occur in different statutes, but when used more than once
in the same statute or even in the same section. Un-
doubtedly, there is a natural presumption that identical
words in different parts of the same act are intended to
have the same meaning. But the presumption is not rigid
and readily yields whenever there is such a variation in
the connection in which the words are used as reasonably
to warrant the conclusion that they were employed in
different parts of the act with different intent. Where
the subject matter to which the words refer is not the
same in the several places where they are used, or the
conditions are different, or the scope of the legislative
power exercised in one case is broader than that in an-
other, the meaning well may vary to meet the purposes
of the law, to be arrived at by a consideration of the
language in which those purposes are expressed, and of
the circumstances under which the language was em-
ployed.

Atlantic Cleaners & Dyers, Inc. v. United States, 286 U.S.

427, 4383 (1932) (citation omitted).

aig

70a

history of the depletion deduction shows was the in-
tention of Congress), the result is not so illogical. Ap-
parently, the Commissioner agrees: the regulation is
much the same as it was sixty years ago, and the
court does not feel compelled to rewrite it at this
time.”

*0 In its motion the government urges that adopting Exxon’s
interpretation of the applicable regulations would allow inte-
grated producers to use the depletion allowance to offset
unrelated income, rendering meaningless the provision hold-
ing the deduction to 50% of taxable income. Regulation
§ 1.613-5(a), drafted by the Treasury to implement the tax-
able income limitation, provides:

The term “taxable income from the property (computed
without allowance for depletion) ,” as used in section 613
and this part, means “gross income from the property”
as defined in section 613(c) and §§ 1.613-3 and 1.613-4,
less all allowable deductions (excluding any deduction for
depletion) which are attributable to mining processes,
including mining transportation, with respect to which
depletion is claimed.
This regulation clearly states that for the purpose of calculat-
ing the taxable income limitation, the gross income from the
property shall be that figure provided by § 1.613-3, which is
the representative market or field price (if such a market
figure can be determined). Of course, Exxon responds by
urging the court to apply the regulation literally and to reach
a result that comports with the reading of § 1.613-3(a) it
would prefer. Exxon states the application of § 1.613-5 played
no part on the determination of the deficiency and was raised
by the government for the first time in this litigation. As a
result, Exxon questions whether the court even has jurisdic-
tion to determine the effect of the taxable income limitation
in this case. See Ottawa Silica Co. v. United States, 699 F.2d
1124, 1137-39 (Fed. Cir. 1983). The court need not enter
this thicket for it has not been shown that the 50% limitation
would be violated if the court were to accept, arguendo,
Exxon’s position as advanced herein. Exxon maintains that

-iiiiaileaanaaiaail

Tila

In concluding, the court must reach back to the
standards described earlier in this order. The plain
language of the statute provides that the deduction
shall be based on the gross income from the property,
and the regulation says that gross income shall be as-
sumed to be the representative market or field price
before conversion or transportation. Since the plain
language of this statute would clearly settle the issue
on this motion, the legislative history must be exam-
ined to determine whether this language produces an
absurd result. The court cannot say that an absurd
result is reached. Further, the possibility that the
representative price might on occasion exceed the in-
come realized from the property was recognized by
Treasury officials. Yet, the regulation at issue re-
mained unchanged with respect to oil and gas and was
modified with respect to hard minerals.”' In the case
at bar, the gross income from the properties for 1968-
1973 was greater than the market value of the gas.
In 1974, though, the gross income from the properties
was less than the representative market value of the
gas. The bearing of the seventeen long-term contracts
Exxon had with various third parties, together with
the effect of the OPEC oil embargo in the 1970s, see
Aeron Marine Shipping Co., supra note 14, may well
have contributed to this result. On balance, the con-
clusion that the regulation’s plain meaning should pre-

no such violation of the 50% limitation would occur; defend-
ant cannot say whether any such violation would in fact occur.

*1 See Helvering v. Mountain Producers Corp., 303 U.S.
376, 382 (1938) (“The gross income [from a property] from
time to time may be more or less than market value {of the
oil and gas] according to the bearing of particular con-
tracts.’’)

72a

vail does not produce such an absurd result that it
should be ignored or discarded. Although the govern-
ment has identified sections of the legislative history
of this provision that suggest that the depletion deduc-
tion can never exceed actual revenues for the prop-
erty, there is no clear cut legislative intent that this
was to be the statutory rule.”

For the foregoing reasons, the government’s mo-
tion for judgment on the pleadings is denied.* The
next question is whether Exxon’s depletion deduction
computation was based on an appropriate representa-
tive market or field price.

22 Cf. Mobil Exploration and Producing North America,
Inc. v. United States, 27 Fed. Cl. 463, 468 n.6 (1993) :

Inevitably, the parties and the court must construe the
meaning of the words in question and attempt thereby
to arrive at what Congress meant. The legislative body
is presumed to mean what it says, and only if literal
meaning makes too great a departure from reason should
we resort to our own speculations from evidence of con-
cealed intent reflected in secondary materials.

23 The government has presented other related arguments
in support of its motion for judgment on the pleadings, but
none changes the court’s conclusions. For example, the gov-
ernment points to an Internal Revenue Service Revenue Rul-
ing that concludes that the representative market or field
price should be disregarded if that price happens to exceed
the price for which the gas is actually sold. See Rev. Rul.
90-62, 1990-2 C.B. 158. This ruling, however, does not analyze
1.613-3(a) and makes no reference to the Court of Claims’
analysis in Hugoton or Panhandle. The court finds the ruling
unpersuasive. In any event, while they may be helpful in
interpreting a statute, revenue rulings do not have the effect
of a regulation or a Treasury Decision and are not binding on
the court. Xerox Corp. v. United States, 228 Ct. Cl. 406, 426
n.6, 656 F.2d 659, 671 n.20 (1981).

73a

II]

Before the government filed its motion for sum-
mary judgment presently under consideration, Exxon
itself moved for summary judgment. The govern-
ment filed its response to the motion a year later, af-
ter its motion to suspend a decision on the motion
was granted so that there could be some more dis-
covery. Along with its response to plaintiff’s motion,
the government filed its cross-motion for summary
judgment. Further factual developments relevant to
the summary judgment motion (but not directly rele-
vant to the motion for judgment on the pleadings)
must be related. As indicated earlier, Exxon there-
after withdrew its motion for summary judgment,
asserting that the issue of representative market or
field price involved disputed issues of fact which pre-
cluded summary judgment for either party. The gov-
ernment, however, forged ahead in seeking summary
dismissal of plaintiff’s claim.

A. The Government’s Challenge to Exxon’s Field
Prices

Along with its motion for Summary judgment,
Exxon filed its proposed findings of fact, including
the assertion that “[t]he price at which Exxon sold
the natural gas to purchasers away from the produc-
ing properties was less than the ‘representative mar-
ket or field price’ for the gas, as that term is defined
by Treas. Reg. § 1.613-3.” In its statement of gen-
uine issues filed with the court, the government ar-
gues, inter alia, that: |

1. Exxon has never determined the “representative
market or field price” for the gas as that term is
defined in Regulation § 1.613-3(a). This assertion

eee

74a

is based on deposition testimony given by Fred
Perkins, who stated that the field price generated by
Exxon represents not the fair market value of the
resource that comes out of the wellhead, but instead
represents value of the gas at the tailgate of a proc-
essing plant. It is generally conceded that processes
away from the wellhead, such as dehydration and
compressing, add value to the gas. The government
asserts that if Exxon did not calculate the value of
raw natural gas at the wellhead before conversion
and transportation, Exxon cannot survive a summary
judgment motion because it cannot satisfy the re-
quirements of the regulation.

2. Exxon used revenue figures instead of raw ma-
terial figures. Purportedly, Exxon made its tax cal-
culations from the property-by-property revenue data
assembled by its natural gas department accounting
group. The form this group used attributes to each
property its net revenue share from each sale or other
disposition of product made from the raw natural gas
produced from the property. For actual sales of the
numerous finished products, the revenue share was
developed from applicable actual sales prices; but for
gas delivered to the EGS pipeline and for other in-
stances in which product was transferred inside the
company, the revenue share was developed from con-
structive transfer prices, i.e., Exxon field prices for
me

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40386013_0108%3A2. Public record. Not legal advice.