Appendix — United States v. Exxon Corp.

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Supreme Court, U.S

FILED

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)

enue Service (IRS) to calculate Exxon’s allowable

depletion deduction. We reverse and remand.

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.

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.

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.

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

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.

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

pretation of the statutory and regulatory provisions

precludes such a result. We disagree on both bases.

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.

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.

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

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.

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.

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.

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.

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.

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

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.

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

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-

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,

al SAR

at nit

Yas het RIBS Ah ee rt

satis eel ROGERS POMP A Rad EL. ttle Ante Sat A ERNE FS Be

i hl shill Bene i

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.

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

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

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.

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”

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

—_—

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

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

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

methane deliveries to EGS and Exxon posted prices

for the liquids.

In response to the government’s challenges, Exxon

retained David B. Marks (Marks), president of the

oil and gas consulting firm EnerPro, Inc., to conduct

a study of 1974 wellhead sales of natural gas in

Texas. Marks compiled a list, for the relevant pro-

ducing areas, of 1974 sales of unprocessed natural

75a

gas that occurred before the gas was transported

from the leased premises that he could jocate. Among

the records he examined were information concerning

such sales on file with the State of Texas General

Land Office and the Texas Railroad Commission,

Exxon’s monthly gas tax reports filed with Texas,

and Exxon’s natural gas sales contract files. In an

affidavit filed with Exxon’s reply brief, Marks con-

cluded that the gas sold in the 1974 transactions “is

representative of the gas produced in Railroad Com-

mission Districts 2 through 6 and sold at the well-

head during 1974 in terms of location, availability,

quality, and type of sales contract.” The volume-

weighted average representative market or field price

for each District was as follows:

Railroad Volume-Weighted

Commission Average Price

District (Cents/mcf)

2 32.720

3 43.154

4 44.161

5 21.183

6 82.366

Better still for Exxon, Marks concluded that because

Exxon’s gas was of generally better quality, avail-

ability, and location than the gas sold in wellhead

sales, it would have had a slightly higher market value

per mcf at the wellhead than the gas reflected in his

compilation. Further, Marks found that the weighted

average prices computed in his study “are representa-

tive of, and perhaps slightly lower than, the prices

Exxon would have received for its gas in the appli-

cable Railroad Commission District if it had sold

that gas at the wellhead during 1974 under the well-

76a

head gas sales contracts then in effect in that dis-

twiet,”"™*

In its reply brief in support of its motion for sum-

mary judgment, the government argues forcefully

that Marks’s newer interpretation of the relevant

data still does not satisfy the requirements of Regu-

lation 1.618-8. The government deposed Marks soon

after his affidavit had been taken and, using this

deposition testimony, explains that Marks may have

examined the tax reports and public records described

in his affidavit, but in fact examined only one actual

Exxon contract. The contract, referred to by the gov-

ernment as the Duncan Slough contract, was a

twenty-year gas purchase agreement dating from

1968 between Humble Oil (Exxon’s predecessor in

interest), the producer, and Lo-Vaca Gathering Co.,

the gatherer and purchaser, calling for delivery from

Exxon to Lo-Vaca of pipeline quality gas after sep-

aration and dehydration by the producer and transfer

of ownership from the producer to the purchaser of

the methane contained in the gas after helium and

liquefiable hydrocarbons were removed from the gas

processing at a Dow Chemical Company gas process-

24 Because the prices computed by Marks were higher than

the prices on which Exxon based its refund claim, Exxon

asserts, through the affidavit of Freddie W. Watson, an

Exxon Gas Accounting Advisor, that had Exxon valued its

wellhead volume of gas at the weighted average prices com-

piled by Marks, its depletable gross income from the property

for gas transported prior to sale would have been $53.6

million more than the amount on which Exxon’s refund claim

is based. The “new” 1974 gross income would have been

$325,849,211 (instead of $272,292,009) ; the allowable deduc-

tion would be $195,962,501 (up from the $184,093,768 claimed

on the tax return).

77a

ing plant. Judging from the submissions before it,

at this stage the court would be inclined to agree

with the government that this contract was not for

the sale of raw natural gas in the vicinity of the

wellhead.

The government argues that because Marks looked

at no other contracts, the only evidence Exxon sub-

mits to prove that representative market or field price

for gas-producing properties in issue exceeds actual

net revenues from off-premises sales is Marks’ analy-

sis, created from a search of state records based on the

unsubstantiated assumption that his precedure would

identify sales of unprocessed natural gas prior to

transportation from the leased premises from which

the gas was produced. The procedure, it is said, does

not permit anyone to identify arms-length transfers

at ascertainable locaticns on known dates for speci-

fied valuable consideration of unprocessed natural gas

prior to transportation from the leased premises from

which the gas was produced. The government con-

cludes that its indictment of Marks’s analysis, com-

bined with the law in Hugoton and Panhandle that

a field price must be calculated on the basis of

weighted average sales prices for the applicable mar-

ket area for comparable raw natural gas, compel the

entry of summary judgment in its favor. As a lode-

stone for determining whether such a judgment can

indeed be compelled at this stage of the litigation,

the governing law on summary judgment motions

must be examined.

78a

B. Plaintiff's Burdens in Overcoming Summary

Judgment

The United States Supreme Court explained in

Celotex Corp. v. Catrett, 477 U.S. 317, 322-23 (1986),

that

the plain language of Rule 56(c) mandates the

entry of summary judgment, after adequate time

for discovery and motion, against a party who

fails to make a showing sufficient to establish the

existence of an element essential to that party’s

case, and on which that party will bear the bur-

den of proof at trial. In such a situation, there

can be “no genuine issue as to any material fact,”

since a complete failure of proof concerning an

essential element of the nonmoving party’s case

necessarily renders all other facts immaterial.

The moving party’s burden to show an absence of a

genuine triable factual issue may be discharged by

showing that there is an absence of evidence to sup-

port the nonmoving party’s case. Id. at 325.

This standard does not itself described when the

necessary supporting evidence is ‘‘absent”. According

to the Court in Anderson v. Liberty Lobby, Inc., 477

U.S. 242, 250 (1986), the court must make the thres-

hold inquiry of whether there are any genuine factual

issues that properly can be resolved only by a finder

of fact because they may reasonably be resolved in

favor of either party. “[T]his standard mirrors the

standard for a directed verdict under Federal Rule

of Civil Procedure 50(a), which is that the trial judge

must direct a verdict if, under the governing law,

there can be but one reasonable conclusion as to the

err toe

79a

verdict.” In Adickes v. S.H. Kress & Co., 398 U.S.

144 (1970), the Court used this standard and held

that the trial court’s entry of summary judgment was

inappropriate because the moving party’s submissions

“had not foreclosed the possibility of the existence of

certain facts from which “it would be open to a jury”

to conclude that an essential element of plaintiff’s case

could be proven. Anderson, 477 U.S. at 249 (citing

Adickes, 398 U.S. at 158-59).

Bearing these procedural standards in mind, the

court’s function at the summary judgment stage is

not for itself to weigh the evidence and determine the

truth of the matter but to determine whether there

is a genuine issue for trial. Jd. If the possibility

exists that a reasonable jury considering the evidence

could return a verdict for the non-movant, summary

judgment should be denied. “The evidence of the non-

movant is to be believed, and all justifiable inferences

are to be drawn in his favor[, and the Supreme Court

does not suggest] that the trial court may not deny

summary judgment in a case where there is reason to

believe that the better course would be to proceed to

a full trial.” Jd. at 255.

C. Whether Exxon’s Data Are Sufficient

If the court were to accept the government’s argu-

ment that the Marks price analysis is the only evi-

dence Exxon has presented that demonstrates the

existence of an available field price, and that his

methodology in deriving this price is fundamentally

flawed, then Exxon could be faulted for failing to

present an esential element of its case which it would

have the burden of demonstrating at trial, and penal-

ized by an entry of summary judgment against it.

80a

Although the government has developed a substantial

indictment of what Marks says represents the 1974

field prices, if the court were at this point to dismiss

entirely the worth of his affidavit and data it would

be engaging in a determination of witness credibility

and weighing of the evidence that it can only do at

trial. The resolution of this tax refund suit depends

substantially on the court’s comprehensive apprecia-

tion of how Exxon generated the field prices it claims,

and whether these purportedly representative prices

have been developed in a manner that comports with

this court’s precedents guiding this matter. In a

statement filed with the court, the parties agreed that

they had reached an impasse on at least one (but

particularly important) relevant fact: whether there

were wellhead sales from 1974 that can be used in

calculating a representative market or field price for

the gas at issue in this case. Referring to Marks’s

work, Exxon answers yes; the government says no. A

factual dispute of such complexity and material im-

portance is best resolved after a trial, where the fac-

tual nuances can best be explored.

Accordingly, the court denies the government’s mo-

tion for summary judgment. The parties have

reached the end of filing dispositive motions in this

suit. Unless settlement negotiations undertaken in

good faith between the parties prove fruitless (and

oral argument suggests that they would be), the court

expects to proceed to trial. A few remarks should be

made at this point, and the court hopes they will be

useful in spite of the rather simple propositions the

remarks express.

8la

Initially, the court emphasizes that with respect to

the summary judgment motion, all that it has decided

in this order is that Exxon has presented sufficient

evidence to survive the motion and put on its case.

That is to say, it has presented more than a mere

scintilla of evidence in its favor, see Anderson, 477

U.S. at 253, and the evidentiary issue it presents is

not the product of mere speculation or bald assertion,

SMS Data Prods. Group, Inc. v. United States, 19 Cl.

Ct. 612, 617 (1990). Exxon, however, has not been

excused from satisfying the heavy burden of proof

demanded of a plaintiff in a tax refund suit.

“Tt is well settled in a tax refund suit there is a

strong rebuttable presumption of the correctness of

the determination of the Commissioner.” Mulholland

v. United States, No. 645-85T, slip op. at 17 (Fed. Cl.

May 3, 1993) (emphasis in original) (citing Welch v.

Helvering, 290 U.S. 111, 115 (1933) ; Snap-On Tools,

Ine. v. United States, 26 Cl. Ct. 1045, 1055 (1992)).

Generally, the plaintiff has the burden of rebutting

this presumption. United States v. Janis, 428 US.

433, 440-41 (1976) “A tax refund suit is not a quasi

appellate review of an administrative determination.

In order to prevail, the taxpayer, in addition to show-

ing the IRS action was arbitrary, capricious, or un-

reasonable, must prove the correct amount of the tax

and resulting overpayment.” The Hearst Corp. v.

United States, No. 704-89T, slip op. at 46 (Fed. Cl.

May 4, 1993). At oral argument, the government

suggested that in further proceedings it would also

take issue with the methodology used by the IRS to

determine the depletion deduction allowed to Exxon.

If so, then both parties would be attacking the pre-

sumptive correctness of the IRS determination.

82a

The burden of not only proving the determination

of a deficiency was incorrect but also proving the cor-

rect refund amount to which the taxpayer is entitled

is still more difficult to meet when the disagreement

with the Commissioner relates to a deduction. Deduc-

tions are a matter of legislative grace, not of right.

New Colonial Ice Co. v. Helvering, 292 U.S. 435, 440

(1934); The Hearst Corp., slip op. at 46. Exemptions

and exclusions from taxable income should be con-

strued narrowly, and a taxpayer must bring itself

within the clear scope of an exemption, an exclusion,

or a deduction. Commissioner v. Jacobson, 336 U.S.

28, 49 (1949) .*

Finally, the court must note that even if the plain-

tiff in this case were to demonstrate to this court that

a representative market or field price of gas sales

in the vicinity of the wellhead can be reasonably es-

tablished from the data it presents, that in itself does

not mean that that figure will be accepted for the pur-

poses of allowing a higher depletion deduction. As

the Court of Claims did in Panhandle, the entire fact-

ual and contractual scenario must be visited by the

court to determine if the field price proposed is a rea-

sonable one. Such a field price could be rejected as

“highly indigestible.” See Panhandle, 187 Ct. Cl. at

171, 408 F.2d at 717. The field price must be set in

a manner that best follows the statute and the regula-

tion, but where the regulation produces a “highly

indigestible” result, the court can work to find a better

25 Furthermore, the court notes that in lawsuits that have

the potential of imposing a large financial burden on the

United States, the statute in issue will be very cautiously

scrutinized.—See Alliance of Descendants of Texas Land

Grants v. United States, 27 Fed. Cl. 837, 841 n.3 (1993).

83a

figure.” Though it shouldn’t have to, the court ex-

presses anew that if anyone knows best what would be

a representative wellhead sales figure for these 1974

sales, it is the plaintiff and the defendant. The Com-

missioner initially allowed Exxon more than ninety

percent of the depletion deduction it claimed from

these 504 properties on its original return. This de-

termination is deemed to be presumptively correct.

The fact that both parties are going to try to rebut

that presumption, in a situation where reasonable

minds might differ on what constitutes a representa-

tive price might justify deference on the particular

facts to the IRS’s determination as one of several pos-

sible reasonable determinations.”

*6 With respect to the statements and conclusions of the

court in the second Hugoton decision referred to above,

we read the language in question to mean that the ap-

plicable regulation requires the use of a “representative

market or field price,” if an acceptable price of such

nature can be established. Neither the court’s decision

in that case nor the regulation requires the impossible,

i.e., the use of a price that cannot be determined repre-

sentative, or as precluding us from applying some other

formula that produces a fair result. To hold otherwise

would mean that in the instant proceeding the Govern-

ment has successfully presented to plaintiff a “heads I

win, tails you lose” proposition.

Panhandle, 187 Ct. Cl. at 174, 408 F.2d at 717-18 (emphasis

in original) (footnote omitted).

27 Presumably, the government would attack the IRS meth-

odology as being inappropriate “netbacking,” a technique

frowned on by some courts but available to a court if no

representative market price can be determined. See Pan-

handle, 187 Ct. Cl. at 170-175, 408 F.2d at 715-18.

84a

For the foregoing reasons, defendant’s motion for

judgment on the pleadings is denied and its motion

for summary judgment is also denied. The parties

are directed to advise the court within thirty days of

the date of this order relative to further proceedings

in this case.

—

‘s/ Thomas J. Lydon

THOMAS J. LYDON

Senior Judge

85a

APPENDIX C

IN THE UNITED STATES COURT

OF FEDERAL CLAIMS

No. 660-89T

(Filed: April 11, 1995)

EXXON CORPORATION, PLAINTIFF

Vv.

THE UNITED STATES, DEFENDANT

Tax refund; I.R.C. § 611 (1954) and Treas.

Reg. § 1.613-3(a); percentage depletion de-

duction; statutory and regulatory interpre-

ation and construction; representative mar-

ket or field price (RMFP); reasonableness

test.

OPINION

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 alleges it is

entitled to a refund of federal income taxes paid for

the tax year ending December 31, 1974. Exxon’s

complaint alleges it is entitled to recover the sum of

$17,164,405.46, together with interest thereon as pro-

86a

vided by law, which sum represents an alleged over-

payment by Exxon of federal income taxes in the

amount of $5,330,734 and assessed interest in the

amount of $11,833,671.46. This claim relates to the

single issue of whether Exxon properly computed its

“gross income from the property” for purposes of

calculating its percentage depletion deduction for

1974 under section 613(a) of the Internal Revenue

Code of 1954 (Code) with respect to natural gas pro-

duced by Exxon from 482 properties located along the

Texas Gulf Coast and East Texas regions and sold

under long-term contracts to industrial users in the

Texas intrastate market or used by Exxon for its own

operations.’ By Order issued June 29, 1993, the court

de~.ied defendant’s motion for judgment on the plead-

ings and for summary judgment. Trial was held

from July 27 through August 10, 1994. Exxon now

seeks a refund based on a “representative market or

field price” (RMFP) of $.41 per Mcf.’

Exxon is in the business of exploring for and pro-

ducing crude oil and natural gas in addition to the

refining, transporting, buying, and selling of petro-

1 The parties have stipulated that during 1974, Exxon pro-

duced raw natural gas from each of the properties at issue,

that Exxon owned an economic interest, within the meaning

of Treas. Reg. § 1.611-1(b), in each of these properties, and

that each of these properties is a “property” within the mean-

ing of Code §614 and Treas. Reg. § 1.611-1(d)(1). The

parties have further stipulated to various items necessary to

determine the appropriate depletion deduction for each

property.

*An Mef is 1,000 cubic feet and is a standard of measure

for natural gas.

87a

leum and petroleum products. During 1974, Exxon

produced approximately 861 billion cubic feet (Bcf)

of raw natural gas, net of injections and other work-

ing interest shares, from the 482 properties in issue.

Most of the gas produced from these properties was

processed at gas plants to remove the liquefiable hy-

drocarbons and then transported through Exxon’s

own pipeline system, the Exxon Gas System (EGS),

prior to sale. Exxon also sold some of the gas at its

gas plant tailgates and used the remainder in its own

yperations, including as fuel for its Baytown, Texas

refinery and chemical complex.

Exxon can be classified as a fully integrated pro-

ducer of natural gas. An integrated producer is one

that engages in more than one phase of the oil or gas

business. A fully integrated producer is engaged in

all phases of the business from exploration of the re-

tail sale of end products. These phases include ex-

ploration and production, transportation, manufactur-

ing or refining, and retailing or marketing. In the

most limited sense an integrated producer of natural

gas is one that has the ability to process or trans-

port its gas prior to sale. Non-integrated producers

do not own facilities to transport or process their

gas and must sell their gas, “raw” or unprocessed

in the producing area, whereas the integrated pro-

ducer can elect either to sell its raw gas in the vi-

cinity of the well or to transport or process its gas

prior to sale.

The relevant statutory provisions and regulations

for the 1974 tax year wihch govern the present dis-

pute have changed only insignificantly since the

1930s. Section 611(a) of the Code provides:

‘In the case of mines, oil and gas wells, other

natural deposits, and timber, there shall be al-

88a

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 or his dele-

gate.

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 taxpay-

er’s taxable income from the property (computed

without allowance for depletion).

(b) Percentage depletion rate—The mines,

wells, and other natural deposits, and the per-

centages, referred to in subsection (a) are as

follows:

(1) 22 percent—

(A) oil and gas wells...

For the 1974 taxable year, the determination of gross

income from oil and gas producing properties was

made with reference to Treasury Regulation section

1.613-3(a) which provides in pertinent part:

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

89a

the well. If the oil or gas is not sold on the

premises but is transported from the premises

prior to sale, the gross income from the property

shall be assumed to be equivalent to the repre-

sentative market or field price [RMFP] of the

oil or gas before conversion or transportation.

It is the second sentence, quoted above, that serves as

the catalyst for this litigation.

A. The Background of the Depletion Deduction

1. Congress Provides for Discovery 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. 63-16, § II(G) (b), 38 Stat. 114,

172-73 (1913). 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 its capital expenditures, the depletion deduc-

tion was based on 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 in 1918, when

Congress allowed oil and gas producers to take a de-

duction based on “discovery depletion,” in which the

acca ai i i iii

90a

deduction would be “based upon the fair market value

of the property at the 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 deple-

tion deduction provided that the fair market value of

a mineral property was to be determined by the pres-

ent value at the date of the discovery of the reserve’s

estimated future value upon production. 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 shall

not exceed the net income, computed without allow-

ance for depletion, frem the property upon which

the discovery is made... .” Revenue Act of 1921,

§ 234(a) (9), 42 Stat. 256. A Senate Report on the

bill explains that the law was modified to ‘make

it 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 sepa-

rate and distinct line of business... .” S. Rep. No.

275, 67th Cong., Ist Sess. 14-15 (1921). In 1924, this

limitation fixed by net income was drawn tighter still

as Congress moved to reduce the allowable depletion

deduction to fifty percent of the taxpayer’s net income

from the property. Revenue Act of 1924, ch. 234,

§ 204(c), 43 Stat. 253.

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

9la

been vary difficult because of the discovery valua-

tion that has to be made in the case of each dis-

covered 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., 1st Sess. 31 (1926).

Congress determined that instead of discovery deple-

tion, “the best way to [determine the depletion de-

duction] 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 greaty.” 67 Cong. Rec. 3762 (1926). The ap-

proximate percentage to be used by producers was

fixed at twenty-seven and one-half percent. The new

percentage depletion deduction was enacted by Con-

gress in 1926. Revenue Act of 1926, ch. 27, § 204(c)

(2), 44 Stat. 9 (1927). The statute provided:

In the case of oil and gas wells the allowance

for depletion shall be 2714 per centum of the

gross income from the property during the tax-

able year. Such allowance shall not exceed 50

per centum of the net income of the taxpayer

(computed without allowance for depletion) from

the property, except that in no case shall the de-

pletion 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.”

92a

Hugoton Prod. Co. v. United States, 161 Ct.Cl. 274,

277, 315 F.2d 868, 869 (1963) (Hugoton I).

Although discovery depletion deductions were phased

out in favor of those based on the fixed percentages,

the reason for allowing the duction (providing for the

recovery of capital expenditures) did not change. Im-

portantly, what did change was the reference 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 property.”

When the percentage depletion section was adopted,

Congress did not define gross income. The term had,

however, been addressed in Treasury regulations dat-

ing to the adoption of the net income limitation on

depletion deductions in 1921. Treasury Regulation

62, Art. 201(h), adopted in connection with the Reve-

nue Act of 1921, provided the following illustration

of “gross income from the property.”

If the mineral products are not sold as raw ma-

terials 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.

Treas. Reg. 62 (1922 ed.), Art. 201(h). This regu-

tion indicates 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 over-

representing the value of their products due to product

refining of some sort.

This regulation apparently did not stop companies

from reporting figures for purposes of deduction based

93a

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 Com-

mittee on Internal Revenue Taxation remarked that

“[t]he larger [gas-producing] companies have prob-

ably 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 Revenue Act of 1926, 69th Cong., Ist Sess.

23 (1927). 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 Committ’s thoughts were ex-

pressed in Treasury Regulation 74, Art. 221(i), pro-

mulgated pursuant to the Revenue Act of 1928. This

regulation 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

assumed to be equivalent to the market or field

price of the oil and gas before conversion or

transportation.

Treas. Reg. 74 (1929 ed.), Art. 221 (i). Slight amend-

ments were made to this regulation in 1933 and 1936.

94a

When the 1939 Internal Revenue Code was adopted,

adjustments were made to the regulation once again,

but the substance of the provision did not change.

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 deduction.

The Treasury was hesitant to extend percentage deple-

tion to mineral producers because it was even harder

to determine the value of hard minerals in their

unrefined state than it was to determine the value of

unrefined gas. The Special Assistant to the Secretary

of the Treasury discussed the administrative differ-

ences between oil and gas and hard minerals, stating

that:

[ W Jhile the bureau is having difficulty in admin-

istering the percentage depletion provisions in the

case of oil and gas wells, the Treasury believes

that the problem of administering like provisions

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 taxpayers do their own

concentrating, smelting, refining, transporting,

and marketing, all that is known is that the re-

fined or fabricated product was sold for a certain

amount. There is thus presented the insuperable

difficulty of dividing up the resulting income

among all those various activities—maketing,

95a

transporting, smelting, refining, mining, etc.—

and then allocating the proper portion to the min-

ing operation which would be the income from

the mine.

Hearings before the Joint Committee on Internal

Revenue Taxation, 71st Cong., 3d Sess. 111 (1930)

(statement of B.H. Bartholow, Special Assistant to

the Secretary of the Treasury).

Percentage depletion was extended to metal, coal,

and sulphur mines in 1932. Revenue Act of 1932, ch.

209, § 114(b) (4), 47 Stat. 203. As with oil and gas

properties, the deduction was to be calculated as a

percentage of “gross income from the property.” In

Treasury Regulation 77, Art. 221(g), 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

Treas. Reg. 77 (1933 ed.), Art. 221(g).

The depletion deduction statute in effect in 1974

provided, 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 ex-

cluding from such gross income an amount equal

to the rent or royalties paid or incurred by the

96a

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.

LR.C. § 613(a) (1954).

3. Treasury Regulation section 1.613-3

The relevant statutory provisions and regulations

for the 1974 tax year which govern the present dis-

pute have changed only slightly since the 1930s. For

example, the limitation confini 1g the deduction to

fifty percent of “net income from the property” was

changed to “taxable income from the property” in

1954. I.R.C. §618(a). The governing language of

section 613 was adopted by the Public Debt and Tax

Extension Act of 1960. Pub. L. No. 86-564, 74 Stat.

290. Thus, for the 1974 tax year, the determination

of gross income from oil and gas producing proper-

ties was made with reference to section 1.613-3(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 gas in the immediate vicinity of the

well. If the oil or gas is not sold on the premises

but 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 con-

version or transportation.

Treas. Reg. § 1.613-3(a).

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

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concern that the RMFP of a produced resource could

be greater than the price actually received by the

producer for the resource under a pre-existing con-

tract 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-

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, section 1.613-4

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 trans-

portation) which the taxpayer applies to his ore

or mineral regularly exceeds the taxpayer’s ac-

tual 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 nonrecur-

ring factors rather than to the use of a market

or field price which is not representative.

Treas. Reg. § 1.613-4(c) (6) (1972).

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 section 1.613-3(a) unchanged. 33 Fed. Reg. 10700

(1968) ; 36 Fed. Reg. 19256 (1971).

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B. Natural Gas Production

Natural gas as it emerges from the wellhead is a

swirling mixture of hydrocarbon gases and liquids

with various other minerals and contaminants, such

as water, water vapor, and may include sand, hydro-

gen sulfide, carbon dioxide, nitrogen and helium. Nat-

ural gas is composed primarily of methane with

small amounts of heavier hydrocarbons such as

ethane, propane, butanes, pentanes, and heavier com-

ponents. Methane, the lightest component, is com-

posed of one carbon atom and four hydrogen atoms.

Ethane, the second lightest hydrocarbon component,

has two carbon atoms. The hydrocarbon components

of natural gas that contain five or more carbon atoms

(pentanes, hexane, heptane, octane, nonnane and

decane) are generally referred to collectively as “‘nat-

ural gasoline.”

Natural gas is found in hydrocarbon accumula-

tions in geologic traps called reservoirs. Natural gas

exists in three conditions in reservoirs: 1) gas, with-

out the presence of oil, 2) gas dissolved in oil, or 3)

a gas cap over oil. When produced, natural gas is

generally classified as “gas well gas” or “casinghead

gas,” depending upon its origin. “Gas well gas”

refers to gas that is found in a gaseous state at reser-

voir conditions. Wells that produce gas well gas are

called “gas wells.” “Casinghead gas” refers to gas

that was dissolved in oil at reservoir conditions but

becomes gaseous at atmospheric pressure at the top,

or “casinghead,” of an oil well. Casinghead gas is

generally richer in heavier hydrocarbons than gas

well gas, and it is generally produced at lower

pressure.

99a

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