Exxon Mobil Corporation and Affiliated Companies, f.k.a. Exxon Corporation and Affiliated Companies v. Commissioner

114 T.C. No. 20

• Court: United States Tax Court
• Decided: May 3, 2000
• Docket: 18618-89, 18432-90
• Status: Unknown

Opinion

114 T.C. No. 20

UNITED STATES TAX COURT

EXXON MOBIL CORPORATION AND AFFILIATED COMPANIES, f.k.a. EXXON CORPORATION AND AFFILIATED COMPANIES, Petitioners v. COMMISSIONER OF INTERNAL REVENUE, Respondent

Docket Nos. 18618-89, 18432-90. Filed May 3, 2000.

Held: For the years before the Court, $204 million (reflecting petitioners’ 22-percent share of a total $928 million) in estimated dismantlement, removal, and restoration (DRR) costs relating to fieldwide oil production equipment and facilities located in the Prudhoe Bay oil field on the North Slope of Alaska is not sufficiently fixed and definite to be accruable under the all-events test of sec. 1.461- 1(a)(2), Income Tax Regs.

Held, further, for the years before the Court, $24 million (reflecting petitioners’ 22-percent share of a total $111 million) in estimated DRR costs relating specifically to oil wells and to well drilling sites located in the Prudhoe Bay oil field: (1) Is sufficiently fixed, definite, and reasonably determinable to satisfy the all-events accrual test of the accrual method of accounting; (2) is not accruable as a capital cost because such accrual would constitute - 2 -

a change in petitioners’ method of accounting for such costs for which change respondent has not granted permission; and (3) is not accruable as a current ordinary and necessary business expense because such accrual would cause a distortion in petitioners’ reporting of income.

Robert L. Moore II, Jay L. Carlson, Thomas D. Johnston,

Kevin L. Kenworthy, Emmett B. Lewis III, James P. Tuite, David B.

Blair, Laura G. Ferguson, Troy J. Babin, Jeffrey S. Lynn, Paul F.

Kirgis, and Matthew J. Borger, for petitioners.

Richard L. Hunn, Robert M. Morrison, William G. Bissell,

Carl D. Inskeep, Sandra K. Reid, Richard T. Cummings, and

Richard D. Fultz, for respondent.

SWIFT, Judge: In these consolidated cases, respondent

determined deficiencies in petitioners’ Federal income taxes for

the years 1979 through 1982 as follows:

Year Deficiency 1979 $ 268,721,294 1980 2,898,174,073 1981 2,037,809,876 1982 1,599,495,218

After settlement of many issues and court decisions on three

issues,1 the primary issue remaining for decision is whether

1 See Exxon Corp. v. Commissioner, 113 T.C. 338 (1999) (involving the creditability of the United Kingdom petroleum revenue tax); Exxon Corp. v. Commissioner, 102 T.C. 721 (1994) (involving percentage depletion); Exxon Corp. v. Commissioner, (continued...) - 3 -

petitioners’ attempted accrual, for 1979 through 1982, of its

$204 million share of $928 million in total estimated

dismantlement, removal, and restoration (DRR) costs relating to

oil wells and to oil production equipment and facilities in the

Prudhoe Bay oil field on the North Slope of Alaska (North Slope)

would satisfy the all-events test of the accrual method of

accounting. If, for the years in issue, the accrual of any of

the estimated DRR costs would satisfy the all-events test of the

accrual method of accounting, further issues are to be addressed

relating to the amount and method of petitioners’ claimed accrual

thereof.2

Unless otherwise indicated, all section references are to

the Internal Revenue Code in effect for the years in issue, and

all Rule references are to the Tax Court Rules of Practice and

Procedure.

FINDINGS OF FACT

The parties have stipulated numerous facts and the

authenticity and admissibility of numerous exhibits. The

stipulated facts are so found.

1 (...continued) T.C. Memo. 1999-247 (involving the accrual of deficiency interest). 2 The issues in these consolidated cases have also been raised by petitioners in timely filed claims for refund for 1977 and 1978, which claims we understand to be still pending. - 4 -

During the years in issue, petitioners constituted an

affiliated group of more than 175 U.S. and 500 foreign subsidiary

corporations. At the time the petitions were filed, petitioner

Exxon Corp. was the common parent of the affiliated group,

incorporated in New Jersey, with its principal places of business

located in New York, New York, or Houston, Texas. Hereinafter,

petitioners will be referred to simply as Exxon.3

The businesses in which Exxon was engaged primarily involved

exploration for and production, refining, transportation, and

sale of crude oil, natural gas, and other petroleum products.

During the years in issue, Exxon owned a 22-percent interest in

the Prudhoe Bay Unit, a partnership of international oil and gas

companies that owned and operated oil and gas leases in the

Prudhoe Bay oil field on the North Slope of Alaska.

Location of Prudhoe Bay Oil Field

The Prudhoe Bay oil field is located in an extremely remote

area 250 miles above the Arctic Circle on the North Slope of

Alaska. It is bounded by the Beaufort Sea on the north, the

Arctic National Wildlife Refuge on the east, the Brooks Mountain

Range on the south, and the Bering Sea on the west.

3 The parties appear to disagree as to Exxon’s principal place of business during the years in issue. If this question cannot be resolved by the parties by way of a post-opinion stipulation, it will be resolved in a Rule 155 hearing. - 5 -

The surface of the Prudhoe Bay oil field consists of a flat,

treeless, desert plain of approximately 69,000 square miles

covered by a thin mat of vegetation and organic material called

tundra. Beneath the tundra is a layer of permafrost that extends

to a depth of 1,800 to 2,000 feet.

From mid-May through mid-September, the sun does not set on

the North Slope. Summer temperatures may reach 80 degrees

Fahrenheit. From June through September, when the tundra thaws

to a depth of 12 to 18 inches, vehicular traffic on the tundra is

prohibited unless authorized by permit and may be conducted only

in specially designed vehicles called Rolligons.

During summer, the permafrost traps water on the tundra

surface, and the North Slope becomes a wetlands with thousands of

shallow lakes and abundant wildlife, including numerous migratory

birds and animals.

In winter, North Slope temperatures fall to -70 degrees

Fahrenheit, the tundra freezes, blizzards and whiteouts are

common, and darkness prevails for much of the day. In late

November, the sun dips below the horizon and does not reappear

until mid-January.

In spite of harsh winter conditions, some work on the North

Slope is better performed during winter because frozen tundra

provides a better foundation for vehicular traffic than tundra

that, during the summer, may not be passable. - 6 -

In 1979, the U.S. Army Corps of Engineers designated the

entire North Slope of Alaska as a protected wetlands. Ninety-

nine percent of the tundra on the North Slope is treated as

wetlands for regulatory purposes.

Even with the extensive oil wells and oil recovery equipment

and facilities that were constructed in the Prudhoe Bay oil field

and that will be described further below, the North Slope of

Alaska accurately may be described and regarded as essentially

undeveloped, as a habitat for fish, wildlife, and birds, with

occasional subsistence use of the land by isolated Eskimo

communities.

Physical access to the North Slope is limited. The Dalton

Highway, a two-lane gravel road that traverses the Brooks

Mountain Range, provides the only land access. The only all-

water route to the North Slope follows the west coast of Alaska

north through the Bering Sea, around Point Barrow, and east to

Prudhoe Bay. Except during an ice thaw that lasts, on average,

6 weeks in late summer when the Arctic ice cap sufficiently

recedes from the shoreline, marine vessels and barges cannot

access Prudhoe Bay.

The North Slope has no significant local infrastructure.

Fairbanks, located approximately 400 miles to the south and

beyond the Brooks Mountain Range, is the nearest city to Prudhoe

Bay. Anchorage is located 700 miles to the south. Other than

the facilities and personnel associated with the Prudhoe Bay oil - 7 -

field and a few other producing oil fields, there are scattered

throughout the North Slope just a few isolated Eskimo

Because of its isolation and remoteness, labor, materials,

equipment, and support services for major construction projects

on the North Slope–-in particular, for construction and

installation of the Prudhoe Bay oil field equipment and

facilities–-must be imported, which significantly increases the

costs of construction and of performing work on the North Slope.

The oil companies’ total $11 billion capital cost, in the 1970's

and early 1980's, of installing and constructing the Prudhoe Bay

oil field equipment and facilities was more than four times what

the total cost would have been to install and construct a

comparable oil field in the lower 48 States.

Alaska Oil and Gas Leases Relating to, and Discovery of, Oil Reserves in the Prudhoe Bay Oil Field

In 1959, by the Alaska Statehood Law of 1958, Pub. L. 85-

508, 72 Stat. 339, the Federal Government authorized the new

State of Alaska to select 103,350,000 acres of Federal lands

within the boundaries of Alaska to become State lands. Alaska

selected approximately 1.6 million acres on the North Slope

between the Colville and Canning Rivers.

In 1964, the State of Alaska began to offer to oil and gas

companies oil and gas exploration and development leases on its - 8 -

lands on the North Slope using the standard Alaska Competitive

Oil and Gas Lease Form No. DL-1 (DL-1 Leases).

In 1964, 1965, 1967, and 1969, using the DL-1 Leases, with

Exxon, Atlantic Richfield Co. (ARCO), British Petroleum (BP), and

other oil and gas companies, Alaska entered into the particular

oil and gas leases covering the portions of the Prudhoe Bay oil

field that are involved in these cases. The terms of the DL-1

Leases extended for 10 years subject to being renewed by the oil

companies as long thereafter as oil or gas is produced “in paying

quantities”.

In December of 1967, Exxon and ARCO discovered a large oil

and natural gas reservoir at an exploratory well that had been

drilled on one of their jointly owned Prudhoe Bay leases. The

reservoir, named “Sadlerochit”, after the Eskimo word for “area

outside the mountains”, was and remains the largest oil and gas

reservoir ever discovered on the North American Continent.

As of 1967, the reservoir was estimated to contain 23

billion barrels of oil in place and 42 trillion cubic feet of

natural gas. Over its projected 30- to 50-year productive life,

the Sadlerochit Reservoir was projected to produce from 13 to 14

billion barrels of liquid hydrocarbons, approximately 60 percent

of the original oil in place.

Within the Prudhoe Bay field, the Sadlerochit Reservoir

extends approximately 30 miles east to west and 13 miles north to - 9 -

south. It underlies approximately 111 Alaska oil and gas leases

owned by various oil and gas companies.

Construction of Trans-Alaska Pipeline and Unitization of Prudhoe Bay Oil Field

In 1969, Exxon, ARCO, and BP announced plans to construct a

798-mile pipeline to transport oil recovered from the Prudhoe Bay

oil field to the port of Valdez, Alaska, from which the oil would

be shipped to the lower 48 States and to other destinations

throughout the World. This pipeline came to be known as the

Trans-Alaska Pipeline System (TAPS).

TAPS was constructed under rights-of-way granted in 1974 by

the Federal Government and Alaska to a group of seven pipeline

companies, including subsidiaries of Exxon, ARCO, and BP.

By early 1977 construction of TAPS was completed, and on

June 20, 1977, oil production began from the wells located in the

Prudhoe Bay oil field, and oil began flowing through TAPS to the

port in Valdez, Alaska.

Production Facilities Constructed in the Prudhoe Bay Oil Field

Engineering obstacles that had to be overcome to construct

the Prudhoe Bay oil wells and oil production facilities were

enormous. The North Slope’s harsh conditions, fragile

environment, and remote location presented unique challenges to

the design, construction, and installation of the Prudhoe Bay oil - 10 -

field, the accomplishment of which constituted an engineering

feat of breathtaking proportions.

Construction of the oil wells and of the related oil

production facilities at Prudhoe Bay represents the largest oil

development project in our country’s history. In addition to the

oil wells, an extensive network of facilities was constructed to

separate gas and water from crude oil recovered from the

reservoir, to reinject separated natural gas and water into the

reservoir in order to maintain reservoir pressure for enhanced

oil recovery, to prepare recovered oil for transport through

TAPS, to supply the necessary power and fuel requirements

associated with all Prudhoe Bay operations, and to provide

necessary support facilities.

The Prudhoe Bay oil field is laid out in a manner similar to

an offshore oil field with centralized oil production facilities

and isolated drilling locations. The oil well drilling equipment

at the well sites rests on gravel pads called “well pads” from

which multiple wells are drilled directionally underground into

the oil reservoir. The six large production centers within the

oil field are called “gathering centers” or “flow stations”.

Above-ground pipelines throughout the Prudhoe Bay oil field

rest on vertical support members (VSM’s) and run from oil well

drilling sites, to the production centers, and to TAPS.

Pipelines within the Prudhoe Bay oil field are elevated on the

VSM’s above the ground at a sufficient height so that the tundra - 11 -

would not melt and so that moose and other wildlife would be able

to traverse the pipelines.

Due to the careful design, construction, and operation of

the Prudhoe Bay oil field, the facilities and operations of the

oil field have disturbed only 5,600 acres, or 2 percent, of the

total land acreage at Prudhoe Bay.

In light of the costly and difficult construction conditions

on the North Slope, the large industrial buildings and facilities

at Prudhoe Bay (such as the flow stations and power plant),

initially were constructed as large, modular buildings in plants

near Bellingham and Seattle, Washington. The buildings, with the

extensive equipment and facilities fully contained and installed

therein, were then transported by special, oceangoing barges up

the west coast of Canada through the Bering Sea to Prudhoe Bay

where they were transported slowly over gravel roads to the

installation sites in the Prudhoe Bay field.

To protect the North Slope tundra from thermal damage, the

large plants and buildings constituting the oil production

facilities at Prudhoe Bay were installed on pilings and gravel

pads rising 4 to 6 feet above ground level. Once installed and

in place at Prudhoe Bay, the modular segments of the large

buildings were then joined together to form integrated facilities

and buildings by connecting their structural components, piping,

and electrical lines at interface points. - 12 -

The oceangoing sealifts by which the equipment, buildings,

and other facilities were transported by barge to Prudhoe Bay

occurred in the 1970's and early 1980's.

By July of 1984, construction, transportation, and

installation costs of the wells, the equipment, the buildings,

the pipelines, and the other facilities installed at the Prudhoe

Bay field reflected, as indicated, a total capital cost to the

oil companies of approximately $11 billion. The facilities

included 645 wells drilled on 37 drilling sites, 980 acres of

pits, 800 miles of above-ground pipelines, 3 flow stations, 3

gathering centers, a central power station, a central compressor

plant, a base operations center, electrical lines and associated

poles, switchgear, transformers, and an offshore seawater

treatment plant completed in 1983 and connected to the mainland

by a gravel causeway.

Pump Station No. 1, the access or entry point from which oil

flows out of the Prudhoe Bay oil production facilities and into

TAPS, and a segment of the above-ground portion of TAPS lie

within the geographical boundaries of the Prudhoe Bay oil field.

Portions of the Endicott and Kuparuk pipelines, which transport

crude oil from neighboring oil fields to Pump Station No. 1 for

entry into TAPS, also traverse the Prudhoe Bay oil field. In

many areas, the Endicott, Kuparuk, and Prudhoe Bay pipelines are

physically indistinguishable and run alongside each other,

supported above the tundra by the same VSM’s. - 13 -

Unitization of Oil Company Interests in Prudhoe Bay Oil Field

Effective April 1, 1977, to save costs and to enhance

operating efficiencies, Exxon and the other oil companies owning

the oil exploration and production leases in the Prudhoe Bay

field entered into a unitization or partnership agreement with

the State of Alaska (Unit Agreement) under which they unitized

their oil exploration and production leases into a single

operating partnership, the Prudhoe Bay Unit (the PBU).

The Unit Agreement divided the Prudhoe Bay oil field into

two operating areas–-the Western Operating Area to be operated by

BP and the Eastern Operating Area to be operated by ARCO.

Also, effective April 1, 1977, the PBU partners entered into

the PBU Operating Agreement (Operating Agreement), which

established how the PBU would be operated and how costs would be

shared among Exxon and the other oil companies with ownership

interests in the PBU. As indicated, under the Unit and Operating

Agreements, Exxon’s share of the total costs of constructing and

operating the Prudhoe Bay oil field was approximately 22 percent.

When the PBU terminates, the individual leases to the oil

companies will remain in force for at least 1 year or for as long

as the lessee oil companies continue production of oil on the

leases in paying quantities. The separate oil companies may take

over and continue to operate wells and equipment on their leases

after the Unit Agreement terminates. As permitted by - 14 -

paragraph 36 of the DL-1 Leases, the lessees may salvage any

remaining equipment within a reasonable time but not less than

3 years after oil production terminates.

The Unit Agreement incorporates therein whatever oil company

DRR obligations existed under the DL-1 Leases with the State of

Alaska. It also stipulates that no well site may be abandoned

until “final cleanup and revegetation, if required, is approved

in writing” by the State. The Unit Agreement modified the

original DL-1 Leases in certain respects not pertinent to the

issues involved herein.

Production of Oil From Prudhoe Bay

From 1980 to 1987, oil production from the Prudhoe Bay field

was at its peak, averaging approximately 1.5 million barrels per

day, approximately 25 percent of total U.S. oil production.

Since 1987, oil production from the Prudhoe Bay field has been

declining. By 1997, more than 70 percent of the recoverable

crude oil located in the Prudhoe Bay field had been recovered.

Current projections by the PBU owners, the Alaska Department of

Natural Resources, the Alaska Department of Revenue, and the

North Slope Borough consistently forecast that oil production

from the Prudhoe Bay field will end approximately in the year

2030, well after estimated production from other known oil

reservoirs on the North Slope will have ended. - 15 -

The PBU partners originally believed that they might be able

to recover and to market natural gas reserves located in the

Prudhoe Bay field. To date, however, studies conducted by the

PBU partners and by State and Federal agencies indicate that

natural gas recovery from Prudhoe Bay will not be economically

viable given the projected low price of natural gas relative to

the high cost of recovering, producing, and transporting natural

gas from the Prudhoe Bay field to world markets. In 1987, Exxon

“debooked” (removed from “proved undeveloped” to “uneconomic”)

the natural gas reserves in the Prudhoe Bay field. In 1988, the

U.S. Department of Energy (DOE) agreed with that decision and

reduced its estimate of North Slope natural gas reserves by 24.6

trillion cubic feet.

The extensive Prudhoe Bay oil field production facilities

and the TAPS pipeline from Prudhoe Bay to Valdez, Alaska, were

designed for the recovery, processing, and transportation of

crude oil, not natural gas, and it is not anticipated that any

significant portion of the Prudhoe Bay oil field production

facilities and the TAPS pipeline would be usable or modifiable

for the eventual recovery and transportation of natural gas from

the Prudhoe Bay field should recovery of the Prudhoe Bay natural

gas someday become economically viable. That is, it is

anticipated that separate, new wells, processing, and

transportation facilities would have to be constructed for the - 16 -

recovery from the Prudhoe Bay field of natural gas, if recovery

of such natural gas someday would become profitable.

Terms of DL-1 Leases Relating to Exxon’s DRR Obligations

The particular provisions of the DL-1 Leases (under which

Exxon and the other oil companies conducted oil exploration and

recovery activities in the Prudhoe Bay field) that apply to DRR

obligations of Exxon and of the other oil companies upon

termination of oil production in the Prudhoe Bay oil field are

vague and general.

The principal language of the DL-1 Leases that describes

what is to happen--upon termination of oil production at Prudhoe

Bay--to the extensive oil production equipment and facilities

located in the Prudhoe Bay field is found in paragraph 36, which

reads oddly and ambiguously in terms of “rights” and “privileges”

of the oil companies (not in terms of DRR “duties or

obligations”) as follows:

RIGHTS ON TERMINATION. Upon the expiration or earlier termination of this lease as to all or any portion of said lands, * * * [Exxon] shall have the privilege at any time within a period of six months thereafter, or such extension thereof as may be granted * * * [by Alaska], of removing from said land or portion thereof all machinery, equipment, tools, and materials other than improvements needed for producing wells. Any materials, tools, appliances, machinery, structures, and equipment subject to removal as above provided which are allowed to remain on said land or portion thereof shall become the property of * * * [Alaska] upon expiration of such period; provided, that * * * [Exxon] shall remove any and all of such properties when so directed by * * * [Alaska]. Subject to the foregoing, * * * [Exxon] - 17 -

shall deliver up said lands or such portion or portions thereof in good order and condition. [Emphasis added.]

Language in paragraph 20 of the DL-1 Leases--pertaining

generally to due diligence and to prevention of waste in the

conduct of activities at Prudhoe Bay--does contain specific

reference to Exxon’s (and to the other oil companies’)

obligations to plug wells upon termination of oil production at

the well sites. That language also makes general reference to

Alaska regulations “relating to the matters covered by this

paragraph” (namely, to due diligence and to waste). The language

of paragraph 20, however, provides neither a description of DRR

work that Exxon is or will be obligated to perform on leased

property not associated with well sites nor specific reference to

any Alaska regulations pertaining to broader fieldwide DRR

obligations of the oil companies. Paragraph 20 provides, in

part, as follows:

DILIGENCE; PREVENTION OF WASTE. * * * [Exxon] * * * shall plug securely in an approved manner any well before abandoning it; * * * and shall abide by and conform to valid applicable rules and regulations of the Alaska Oil and Gas Conservation Commission and the regulations of * * * [Alaska] relating to the matters covered by this paragraph in effect on the effective date hereof or hereafter in effect if not inconsistent with any specific provisions of this lease. [Emphasis added.]

Language in paragraph 31 of the DL-1 Leases provides for

assignment of the leases, or of undivided interests in the - 18 -

leases, subject to the State's approval. Language in paragraphs

4, 7, 8, and 28 provides for suspension of operations without the

leases expiring.

Language in paragraph 33 of the DL-1 Leases provides that

Exxon (and the other oil companies), should it so choose, may

abandon or surrender its interests in the leases to the State,

provided it--

[places] all wells on the surrendered land * * * in condition satisfactory to * * * [Alaska] for suspension or abandonment; thereupon, * * * [Exxon] shall be released from all other obligations accrued or to accrue under this lease with respect to the surrendered lands * * *. [Emphasis added.]

Alaska Law and Regulations Relating to Exxon’s DRR Obligations in Prudhoe Bay

In 1959, the new State of Alaska Constitution provided for

“development, and conservation of all natural resources * * * for

the maximum benefit of its people.” Alaska Const. art. VIII,

sec. 2. Alaska’s land management policies generally allow

development of Alaska’s natural resources on condition that the

environment be restored to the maximum reasonable extent upon

completion of operations.

In 1967, the Alaska Oil and Gas Conservation Commission

(AOGCC) issued regulations relating to plugging and abandonment

of oil wells and to cleanup of oil well sites. See Alaska Admin.

Code tit. 11, secs. 2101-2108 (effective Sept. 1967), later at

Alaska Admin. Code tit. 11, secs. 22.100-22.110 (1973), and at - 19 -

Alaska Admin. Code tit. 20, secs. 25.105-25.170 (1980). These

regulations are written only in terms of “plugging” the wells and

cleaning up “loose debris” and restoring the well sites to a

“generally level condition.” The AOGCC regulations do not set

forth or describe either specific or general DRR obligations of

oil companies relating to the extensive Prudhoe Bay oil

processing facilities not located at well drilling sites.

In 1972, in anticipation of oil production at Prudhoe Bay, a

joint Federal-State commission was established to study Alaska

land use issues. In 1979, the commission stated in its final

report that development activities in the Arctic “should not lead

to irreversible consequences” and that “areas impacted should be

capable of restoration to a natural state upon the completion of

development activities.” (Emphasis added.)

TAPS Right-Of-Way Provisions

In contrast to the generally vague language of the

DL-1 Leases relating to oil company DRR obligations in the

Prudhoe Bay oil field, language in the TAPS right-of-way

provisions relating to DRR obligations of the oil companies which

constructed and which operate TAPS is more specific. As

explained, TAPS was constructed, and operates today, under lease

rights-of-way granted in 1974 by the Federal and Alaska State

Governments to a group of seven pipeline companies, which include

subsidiaries of Exxon, ARCO, and BP. The Federal and Alaska - 20 -

right-of-way agreements for TAPS contain express language and

provisions relating to oil company DRR obligations that

specifically require the oil companies, upon termination of their

use of the TAPS rights-of-way, to remove the facilities,

improvements, and equipment. The Federal right-of-way agreements

for TAPS state:

Stipulations for the Agreement and Grant of Right-of-Way for the Trans-Alaska Pipeline

1.10. Completion of Use

1.10.1. * * * [the oil companies] shall promptly remove all improvements and equipment, except as otherwise approved in writing by the Authorized Officer, and shall restore the land to a condition that is satisfactory to the Authorized Officer or at the option of * * * [the oil companies] pay the cost of such removal and restoration. * * * [Emphasis added.]

The State of Alaska right-of-way agreements for TAPS contain

virtually the same language explicitly requiring the oil

companies, upon shutting TAPS down, to perform or to pay for the

DRR work associated with dismantling and removing the pipeline

and restoring the land.

DRR Liabilities Recognized for TAPS Rate Making Purposes

As stated, the Federal right-of-way agreements and the

permits relating to TAPS expressly require DRR work to be

completed by the oil companies upon termination of pipeline

operations. - 21 -

Also, in setting transportation rates for TAPS and other

pipelines on the North Slope, the Federal Energy Regulatory

Commission (FERC) has permitted owners of the pipelines to treat

estimated DRR costs as capital costs of constructing the

pipelines and therefore as costs that are recoverable ratably

over the life of the pipelines through rate charges for

transporting oil through TAPS and the other pipelines.

PBU Financial Statements and PBU Tax Reporting Relating to Estimated DRR Costs at Prudhoe Bay

For all relevant years and all items (including DRR costs),

the financial books and records and the Federal partnership

income tax returns of the PBU were prepared on the accrual method

of accounting.

From formation of the PBU partnership through the years in

issue, on the financial books and records and on the Federal

income tax returns of the PBU partnership, DRR costs were accrued

utilizing the all-events test of the accrual method of

accounting. At the time, it was understood generally within the

oil industry that DRR costs could not be accrued for Federal

income tax purposes until the related DRR work was actually

performed. This understanding was consistent with and followed

respondent’s then-published position that DRR work had to be

performed before the related DRR costs for tax purposes could be

accrued under the all-events test. See Rev. Rul. 80-182, 1980-2

C.B. 167. - 22 -

Accordingly, for the years in issue, the PBU partnership

accrued ordinary business expense deductions relating to DRR

costs in the years in which the related DRR work was performed.

On the PBU partnership Federal income tax returns for the

years in issue (1979-82), with respect to estimated future

Prudhoe Bay DRR costs associated with projected DRR work to be

performed in subsequent years upon termination of oil production

at Prudhoe Bay, no accrual was claimed for an increase to a

capital liability account, for an increase in the depreciable tax

basis of capital assets at the Prudhoe Bay field, nor for

ordinary and necessary business expenses.

During the years in issue, a PBU-sponsored DRR cost study

relating to the Prudhoe Bay field was not completed.

On its 1979 and 1980 partnership Federal income tax returns,

the PBU elected to compute depreciation on its depreciable assets

placed in service in those years under the class life asset

depreciation range (ADR) system of section 1.167(a)-11, Income

Tax Regs. For those same years, PBU elected under section 167(f)

to reduce the amount taken into account as salvage value by an

amount not exceeding 10 percent of the basis of property

depreciated under the ADR system. In making this election, the

PBU claimed that the gross salvage value did not exceed 10

percent of the unadjusted basis of the facilities. This election

caused the salvage value of each ADR vintage account to be

reduced to zero. For 1981 and 1982, the PBU depreciated assets - 23 -

placed in service in 1981 and 1982 under the Accelerated Cost

Recovery System (ACRS) of section 168.

Exxon’s Financial Reporting Relating to Estimated Prudhoe Bay DRR Costs

In 1977, the Financial Accounting Standards Board (FASB)

issued Statement of Financial Accounting Standards No. 19,

“Financial Accounting and Reporting by Oil and Gas Producing

Companies” (FAS 19),4 which required oil and gas companies, for

financial income statement reporting purposes, to take estimated

future DRR costs into account in determining amortization and

depreciation rates. For financial accounting purposes, oil and

gas companies have estimated such costs in a variety of ways.

Where estimates of DRR costs exceed estimated salvage value, oil

and gas companies, including Exxon, have reported and claimed,

for financial income statement reporting purposes, depreciation

4 Paragraph 37 of FAS 19 provides with regard to fixed DRR obligations the following income statement accounting for DRR:

Estimated dismantlement, restoration, and abandonment costs and estimated residual salvage values shall be taken into account in determining amortization and depreciation rates.

FAS 19 does not address the balance sheet accounting for DRR. In a February 1996 Exposure Draft entitled “Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets”, which would include onshore and offshore oil and gas production facilities, the FASB recommended that oil and gas companies, for financial reporting purposes, fully accrue estimated future DRR costs that represent fixed obligations in the year the obligations first arise, capitalize such costs into the bases of the related assets, and recover the costs through depreciation deductions over the productive lives of the assets. - 24 -

expenses for estimated future DRR costs (including those relating

to the Prudhoe Bay oil field) over the entire life of an oil

field using the units-of-production method.

Oil and gas companies, including Exxon, typically review and

revise their estimates and depreciation rates relating to

estimated future DRR costs throughout the life of a field. Their

financial income statements incorporate and reflect changes in

DRR cost estimates relating to changes in technology, inflation,

labor, equipment, and material rates. When new facilities are

installed, oil and gas companies reflect additional estimated DRR

costs relating to the new facilities in their financial income

statements as additional depreciation expenses.

FAS 19 does not state that estimated future DRR costs should

be reflected as a fixed capital liability on a company’s

financial balance sheets.

During the years in issue, consistent with FAS 19, Bulletin

61 of Exxon’s financial accounting manual, “Accounting for Cost

of Plant Removal and Site Restoration” relating to the accrual of

DRR costs, provided as follows:

Annual accruals [for future DRR] are to be provided only if both of the following conditions are met:

1) The work must be required as the result of local laws or regulations, or as part of a contractual agreement.

2) The nature of the work is such that it is possible to estimate its cost. Thus, the law or - 25 -

agreement must specify the work to be performed or the conditions to be met.

For the years in issue, Exxon, like most other oil and gas

companies, did not recognize on its financial balance sheet

statements estimated future DRR costs as a fixed liability.

Rather, Exxon disclosed estimated future DRR costs in a note to

its financial statements and, as required by FAS 19, reflected

and claimed estimated future DRR costs relating to Prudhoe Bay

and to its other oil and gas facilities in its annual

depreciation calculations on its financial income statements.

As indicated, during the years in issue, no PBU partnership-

wide study was made of estimated future Prudhoe Bay DRR costs.

Rather, each oil company, including Exxon, with a working

interest in the PBU partnership generally developed its own

estimate of future Prudhoe Bay DRR costs.

Set forth in the schedule below for 1977 through 1988 are

the amounts of its share of total future Prudhoe Bay DRR costs

that, at the end of each year, were estimated by Exxon. The

amounts vary because of differences in methodology and

assumptions that were used from year to year to estimate total

future DRR costs. - 26 -

Exxon’s Estimated Future Total Prudhoe Bay DRR Costs Year (Millions) 1977 $215 1978 215 1979 228 1980 122 1981 162 1982 180 1983 247 1984 300 1985 300 1986 333 1987 209 1988 209

As indicated, in its financial income statements for each

year, Exxon included a depreciation expense item relating to its

share of the above estimated future Prudhoe Bay DRR costs. On

Exxon’s financial income statements for each year, the amount of

the depreciation expense item reported for estimated Prudhoe Bay

DRR costs was calculated roughly on the basis of the above

estimates of total future Prudhoe Bay DRR costs and on the basis

of the units of oil production that occurred in each year

relative to Exxon’s estimates of total oil recovery that would

occur at Prudhoe Bay over the projected life of the field,

reflecting Exxon’s 22-percent interest in the PBU.

Following FAS 19 and oil industry practice, however, on its

annual financial balance sheet statements Exxon did not accrue as

a fixed capital liability or cost any of the above estimated

Prudhoe Bay DRR costs. Rather, on such yearend financial balance

sheet statements, the amount of the annual depreciation expense - 27 -

relating to estimated future Prudhoe Bay DRR costs, which was

reflected on Exxon’s income statements as an item of depreciation

and charged to earnings, was credited to a “reserve” liability

account.

During the years in issue, for financial income statement

and balance sheet reporting purposes, Exxon’s practice for the

financial reporting of estimated future DRR costs was the same as

that followed by a majority of oil and gas companies.

Set forth in the section below (infra p. 30), is a schedule

setting forth, among other things, the amount of estimated future

PBU DRR costs that Exxon, in its financial income statements for

each year, accrued as a depreciation expense and added to a

liability reserve account.

Exxon’s Federal Corporation Income Tax Returns and Now Proposed Tax Treatment of Estimated DRR Costs

In preparing and filing its Federal corporation income tax

returns for the years in issue, Exxon used the accrual method of

accounting, and Exxon has consistently used the all-events test

as the standard for determining when its liabilities accrue under

the accrual method of accounting.

On its consolidated Federal corporation income tax returns

for the years in issue, Exxon accrued costs relating to its

worldwide DRR obligations on the accrual method of accounting as

its tax return preparers then understood the application to DRR

costs of the all-events test of the accrual method of accounting. - 28 -

That is, DRR costs, for Federal income tax return purposes, were

accrued only when the related DRR work was performed and then as

current business expenses. As explained and as reflected in Rev.

Rul. 80-182, 1980-2 C.B. 167, this was consistent with

respondent’s interpretation of how the all-events test of the

accrual method of accounting applied to DRR costs.

Set forth below for each of the years 1977 through 1982 is a

schedule that reflects the amount of estimated Prudhoe Bay DRR

costs indicated: (1) On Exxon’s financial balance sheet

statements (as explained, estimated DRR costs were accrued on

Exxon’s financial balance sheet statements not as a fixed

liability cost but only in a footnote as a reserved liability);

(2) on Exxon’s financial income statements (as explained,

estimated future DRR costs were accrued on Exxon’s income

statements as a depreciation expense based on units of oil

production that occurred in each year); (3) on Exxon’s Federal

income tax returns, as filed with respondent (as explained, on

Exxon’s income tax returns DRR costs were not accrued until DRR

work was performed and then as current business expenses); and

(4) as now claimed by Exxon for Federal income tax purposes,

namely, in the year Prudhoe Bay oil wells and the related

equipment, facilities, and buildings were constructed, total

estimated future Prudhoe Bay DRR costs would be capitalized and

for each year related accelerated depreciation, investment tax - 29 -

credits, and intangible drilling costs, or, alternatively,

current business expense deductions would be claimed therefor.

Exxon’s Accrual of Estimated Future PBU DRR Costs On Financial Statements Tax Treatment On Income Statements As Depreciation Current Expense Would Now Capitalize On Balance Expense & On Balance On Tax Returns & Claim Depreciation, Sheets Sheets As Addition To As Filed ITC, & IDC, Or As Fixed Reserved Liability With Respondent Current Expense For Liability (Millions) (Thousands) (Millions) 1977 --- $2.5 -0- $ 6.9 1978 --- 4.2 $15,040 11.4 1979 --- 6.1 -0- 11.8 1980 --- 4.1 -0- 12.4 1981 --- 5.2 -0- 13.7 1982 --- 6.0 -0- 18.8

In the 1980's, a Tax Court decision allowed, for Federal

income tax purposes, the accrual of estimated future strip-

mining land reclamation costs relating to underground mines.

See Ohio River Collieries Co. v. Commissioner, 77 T.C. 1369

(1981). As a result, in the late 1980's, the PBU and the

partners in PBU including Exxon raised in these pending cases

with respondent via timely claims for refund the DRR cost

accrual issue relating to estimated Prudhoe Bay DRR costs, as

well as the accrual of estimated DRR costs for other projects

throughout the world.

As a result of such claims, with regard to oil company

estimated DRR costs relating to underground mines, oil shale

projects, and TAPS, respondent has allowed Exxon and other oil

companies the tax accrual of estimated DRR costs.

For the years in issue, with regard to estimated DRR

costs relating to foreign offshore oil drilling platforms and - 30 -

to Exxon’s oil wells located in the lower 48 States (as well

as those relating to the Prudhoe Bay oil field), respondent

continues to disallow the accrual of estimated DRR costs.

With regard to the accrual of DRR costs relating to foreign

offshore oil drilling platforms and to Exxon’s oil wells

located in the lower 48 States, Exxon has withdrawn its claims

for refund with regard thereto.

In the referred-to claims for refund, the PBU and Exxon

have raised the issue of whether they may accrue estimated DRR

expenses relating to Prudhoe Bay beginning in 1977, the first

year of the PBU partnership’s existence, and Exxon has pending

refund claims on the issue beginning with each year of the PBU

partnership.

As explained, Exxon’s primary position in these cases is

that estimated DRR costs relating to the oil-producing

equipment and facilities located in the Prudhoe Bay field

should be accruable, in the year such equipment and facilities

are constructed and installed, as capital costs of the

facilities and depreciated under the relevant tax depreciation

system (for the years in issue--ADR and ACRS). Further, with

regard to estimated DRR costs that are capitalized and that

relate specifically to oil wells and to cleanup of oil well

sites, Exxon claims that investment tax credits under section

38 and intangible drilling costs under section 263(c) should

be allowed. - 31 -

Alternatively, in the year the oil field equipment and

facilities were constructed and installed, Exxon claims that

estimated Prudhoe Bay DRR costs should be accruable under

section 162 as ordinary and necessary business expense

deductions.

Exxon’s Estimates of Future PBU DRR Costs

Exxon’s experts have made elaborate and detailed

projections with regard to future DRR activity that may be

undertaken in the Prudhoe Bay field and to estimated DRR costs

that may be incurred with respect thereto. In doing so, they

claim that all facilities in Prudhoe Bay other than the

Seawater Treatment Plant will be dismantled beginning in the

year 2031 and that it will take 6 years to dismantle and

remove the facilities and equipment from the North Slope of

Alaska.

Exxon estimates that a total of $928 million in DRR costs

relating to the Prudhoe Bay oil-producing facilities will be

incurred by the PBU partnership, and Exxon calculates that its

share thereof will be approximately $204 million. - 32 -

OPINION

Accrual of DRR Costs Under the All-Events Test of Section 461

For Federal income tax purposes during the years in

issue, an accrual basis taxpayer generally may accrue costs

not yet paid in the year in which the costs satisfy the two-

pronged all-events test of the accrual method of tax

accounting; i.e., in the year in which all the events occur

that establish the fact of the taxpayer’s liability for the

costs and in which the amount of the liability can be

determined with reasonable accuracy. See United States v.

General Dynamics Corp., 481 U.S. 239, 243-244 (1987); United

States v. Hughes Properties, Inc., 476 U.S. 593, 600 (1986);

United States v. Anderson, 269 U.S. 422, 437-438 (1926); sec.

1.446-1(c)(1)(ii), Income Tax Regs.

As the Supreme Court has explained:

It is fundamental to the “all events” test that, although expenses may be deductible before they have become due and payable, liability must first be firmly established. This is consistent with our prior holdings that a taxpayer may not deduct a liability that is contingent * * *. [United States v. General Dynamics Corp., supra at 243.]

The all-events test also applies under section 1012 to

the accrual into the tax bases of capital assets of estimated

future capital costs. See Denver & Rio Grande W. R.R. v.

United States, 205 Ct. Cl. 597, 505 F.2d 1266 (1974); La Rue

v. Commissioner, 90 T.C. 465 (1988); Seaboard Coffee Serv., - 33 -

Inc. v. Commissioner, 71 T.C. 465, 476 (1978); Lemery v.

Commissioner, 52 T.C. 367, 377-378 (1969), affd. per curiam

451 F.2d 173 (9th Cir. 1971); Gibson Prods. Co. v. United

States, 460 F. Supp. 1109, 1115 (N.D. Tex. 1978), affd. 637

F.2d 1041 (5th Cir. 1981); sec. 1.461-1(a)(2), Income Tax

Regs. Herein, respondent disputes whether Exxon’s attempted

accrual of estimated Prudhoe Bay DRR costs would satisfy

either prong of the all-events test.

The first prong of the all-events test looks only to

whether the taxpayer’s fact of liability for the costs in

question has been established. This test may be satisfied

even if it is not known when or to whom costs will be paid.

See United States v. Hughes Properties, Inc., supra at 604;

Valero Energy Corp. & Subs. v. Commissioner, 78 F.3d 909, 915

(5th Cir. 1996), affg. T.C. Memo. 1994-132. A liability can

be fixed even if there are procedural or ministerial steps

that still have to occur before payment. Accrual should be

deferred if the occurrence of those steps is sufficiently

uncertain that they render the taxpayer’s liability

contingent. See, e.g., Continental Tie & Lumber Co. v. United

States, 286 U.S. 290 (1932); United States v. Anderson, supra.

The mere speculative possibility that some future event

will release the taxpayer from its liability does not prevent - 34 -

accrual. See, e.g., United States v. Hughes Properties, Inc.,

supra at 601-602, 606.

Exxon argues that the combination of the DL-1 Lease

provisions, Alaska law, regulations, and oil industry

practice, as of the end of each of the years 1979 through

1982, establish the fixed and definite nature of Exxon’s

future Prudhoe Bay DRR obligations regarding the entire

Prudhoe Bay oil field. The extent of the DRR obligations to

which Exxon contends the PBU and the other oil companies

became subject upon construction of the Prudhoe Bay oil wells

and oil production facilities is summarized briefly by one of

Exxon’s experts, as follows:

PBU will have to plug all wells, close all reserve and containment pits, remove all above-ground pipelines and electrical lines, and remove all other structures, such as modular flow stations and gathering centers. The PBU Partners will have to dismantle, transport to barges, and transport off the North Slope the modules, pipelines, and electrical distribution systems, and leave the land in a clean and generally level condition. It is expected that Exxon and its PBU Partners will perform these DRR obligations around the year 2030.

In comparing the language of the right-of-way agreements

relating to TAPS and to the other North Slope pipelines

involved in the FERC rate-making proceedings, on the one hand,

to the language of the DL-1 Lease agreements, on the other,

Exxon’s experts sense a common denominator or “idea” in the

language of both sets of right-of-way agreements (namely, that - 35 -

removal of the equipment and related DRR work is “required” in

each instance).

We note simply that specific language relating to oil

company DRR obligations is found in the TAPS right-of-way

agreements, but, as we have explained, is not found in the

language and provisions of the DL-1 Leases that relate to

fieldwide oil production facilities at Prudhoe Bay.

Neither the language of paragraph 36 nor the language of

paragraph 20 of the DL-1 Leases reflects fieldwide facility

and equipment dismantlement, removal, or restoration

obligations. As we have explained, paragraph 36 is written in

terms of a “privilege” of the oil companies to remove

equipment if they so choose or of an “option” of Alaska to

have the equipment removed if it so elects. Paragraph 20

refers only generally to waste and due diligence, to

preservation of the land, and to plugging abandoned wells.

Fixed obligations to dismantle, remove, and restore the

Prudhoe Bay fieldwide facilities and equipment are not

reflected in the language of paragraph 20.

Further, as we have found, and contrary to Exxon’s

experts, AOGCC regulations in effect during the years in issue

relate only to plugging, abandonment, and cleanup of oil well

sites and do not apply to, and do not establish, DRR

obligations of the PBU or of the oil companies to the - 36 -

extensive Prudhoe Bay oil field equipment and facilities not

located at oil well sites.

Again, we note that the right-of-way leases relating to

TAPS and the regulations relating to oil well drilling sites

reflect express language that imposes DRR obligations on the

oil companies. The DL-1 Leases and the Alaska regulations,

however, contain no such express language imposing fixed and

definite DRR obligations on the oil companies relating to

fieldwide production facilities located in the Prudhoe Bay

oil field.

We believe the differences in language relating to DRR

obligations are significant for purposes of the all-events

test of the accrual method of accounting. We believe that

specific DRR obligations relating to fieldwide oil production

facilities could have been reflected in the DL-1 Leases or in

the Alaska regulations were such obligations intended.

Specific DRR language was used in the TAPS right-of-way

provisions. No adequate explanation has been provided as to

why specific language relating to DRR obligations of the PBU

and of the oil companies relating to fieldwide DRR was not set

forth either in the DL-1 Leases or in the Alaska regulations,

other than that such DRR obligations with regard thereto, as

of the years in issue, were not established.

As the current Commissioner of the Department of Natural

Resources for the State of Alaska acknowledged in his trial - 37 -

testimony herein, as late as 1997 no Alaska regulations

specifically covered Prudhoe Bay fieldwide DRR obligations of

the oil companies. He testified as follows:

Question. So in June of 1994, your Deputy Commissioner said there was no established policy on DRR and in June of 1997 you said there is no fixed policy on DRR but now you are claiming on the witness stand that there is, is that correct?

Answer. I’m not claiming there is a policy. I am claiming there’s an expectation. We do not have a policy written in regulation about lease closure and how we go about lease closure. This has been a general concern of the industry that goes well beyond this case, and the purpose of my memorandum to the staff was to continue work that had begun earlier on such a policy.

However, we have certainly in the lease and, I think, in a variety of other arenas stated our expectations of the industry, and I think those expectations show very high standards in terms of environmental cleanup.

Question. But those expectations are not stated in any regulation or official ruling, is that correct?

Answer. That is correct.

The 1979 joint Federal-State commission that studied

Alaska land use issues and that concluded that development

activities in the North Slope should not irreversibly damage

the environment and that the environment should be “capable”

of restoration upon completion of development activities

imposed no fixed and definite DRR obligations on Exxon. An

“expectation” of and the “capability” of restoration do not

necessarily require restoration. - 38 -

Exxon placed in evidence the extensive history, during

the 1960's through the present, of the State of Alaska’s

supervision of oil company abandonment and cleanup operations

of numerous North Slope exploratory well sites. Exxon

emphasizes and argues that such history and practice and the

AOGCC regulations (relating to abandonment of wells and to

cleanup of well sites) together establish affirmative DRR

obligations of the oil companies for all of the massive

equipment and facilities located in the entire Prudhoe Bay oil

field. One of Exxon’s experts states in his report as

follows:

The AOGCC’s record of strict enforcement of cleanup requirements [for well locations] over the last thirty-one years * * * evidences the State’s commitment to having its lands returned in good order and condition * * *. [Emphasis added.]

We reject the equation, if that is what is intended by

Exxon’s expert, between well sites and the balance of the “lands”

constituting the Prudhoe Bay oil field.

Recognizing the dispute between Exxon and respondent over

alleged differences between well sites and the balance of the

Prudhoe Bay oil field, Exxon’s expert comments as follows:

It is not necessary to resolve the issue of what constitutes a “location” to understand that the cleanup requirements of paragraph 20, the AOGCC regulations, and the consistent, virtually uniform pattern of enforcement over many years, collectively illustrate - 39 -

the type of standards which will be applicable to final cleanup at the PBU. Far from the AOGCC regulations being somehow distinct and inapplicable, there is every reason to conclude that the State of Alaska will enforce DRR obligations under State leases consistent with the approach applied under these regulations.

To the contrary, “expectations” or reasonable and probable

“predictions” on the part of Alaska government officials and

Exxon’s experts regarding what eventually may be required from

the oil companies in the way of Prudhoe Bay fieldwide DRR do not

provide a sufficiently fixed and definite basis on which to base

the tax accruals sought herein. During the years before us, such

expectations and predictions simply do not satisfy the all-events

test of section 461. They do not rise to the level of fixed and

definite legal obligations.

The fact that Exxon annually on its financial income

statements accrued a depreciation deduction for DRR costs based

on units of oil produced each year does suggest, as Exxon argues,

that Exxon’s management considered some accrual of estimated

Prudhoe Bay DRR costs appropriate and consistent with Exxon’s

financial accounting policies and with generally accepted

financial accounting principles. As explained, under FAS 19 oil

companies are required to accrue as an expense future DRR costs

where the company is under an existing obligation to incur such

costs and where such future DRR costs can be estimated with

reasonable accuracy. - 40 -

The rules of financial accounting and a company’s financial

treatment of such costs, however, whether correct or incorrect

thereunder are not controlling for Federal income tax purposes.

See Thor Power Tool Co. v. Commissioner, 439 U.S. 522, 540

(1979). We also note that Exxon, for financial reporting

purposes, did not on its financial balance sheets (as

distinguished from its financial income statements) accrue any

fixed liability relating to estimated DRR obligations at Prudhoe

Bay.

Exxon argues strenuously that respondent’s position, under

which no tax accrual would be allowed for estimated future

Prudhoe Bay DRR costs, produces a fundamental and gross mismatch

of Exxon’s income and expenses relating to Prudhoe Bay oil

recovery. Under the matching principle of Federal income tax

accounting, however, only those obligations are to be recognized

that are properly accruable (i.e., that satisfy the all-events

test). To allow estimated costs of obligations that do not

satisfy the all-events accrual test (such as the majority of the

estimated DRR costs involved herein) to be accrued and to offset

current income is not part of the matching principle.

Further, Alaska’s general policy under its constitution for

management of Alaska lands (to permit development while at the

same time insisting that the environment be preserved or, if

necessary, restored to the fullest reasonable extent) does not

establish any specific oil company DRR obligations with regard to - 41 -

Prudhoe Bay that may be legally recognized for Federal income tax

purposes.

DRR Obligations Relating Specifically to Well Plugging and to Well-Site Cleanup

Contrary to our holding regarding fieldwide Prudhoe Bay DRR,

we believe Exxon’s Prudhoe Bay DRR obligations relating

specifically to oil wells and to oil well sites are clearly set

forth and established in the provisions of the DL-1 Leases and

satisfy the first prong of the all-events test of the accrual

method of accounting. Paragraph 20 expressly states that upon

closing down wells, Exxon is to plug the wells and abide by

Alaska regulations relating to such plugging. For the years in

issue, Alaska regulations similarly required oil companies to

plug and to clean up well drilling sites.

Respondent argues that the filing of a “notice of

abandonment” of the wells constitutes a condition precedent to

the recognition of any firm oil company DRR obligations. Also,

respondent argues that DRR technology and Alaska regulations

regarding well plugging and well-site cleanup may be changed by

the time the wells in the Prudhoe Bay field are to be plugged by

the oil companies, making all DRR work that the oil companies

might have to perform in Prudhoe Bay indefinite and speculative.

We disagree. We regard the notice of abandonment provision of

the DL-1 Leases as ministerial and perfunctory, certainly not a

condition precedent to DRR obligations relating to the wells - 42 -

which obligations came into existence when the wells were

drilled. As Exxon on brief explains:

it is preposterous to think that Exxon could avoid having to plug wells simply by refusing to file a notice of abandonment. * * * Filing the notice is just a step in performing the well plugging obligation already imposed by Paragraph 20 of the lease.

Further, in the oil industry, oil well plugging and site

cleanup relating thereto are common events. Although variations

in plugging procedures may occur, we believe sufficient oil

industry experience and practice are established with regard to

the frequent procedure of well plugging and well-site cleanup

that possible changes in technology and Alaska regulations do not

render Exxon’s Prudhoe Bay DRR obligations with regard thereto

indefinite and contingent.

Respondent contends that Exxon’s well-site DRR obligations

should not be regarded as fixed because of the possibility that

Exxon might surrender or assign its interest in PBU, along with

the related DRR obligations, to some other oil company. The mere

possibility of assignment, however, is not sufficient to prevent

tax accrual because the same argument could be made with respect

to every fixed liability that a taxpayer otherwise would accrue.

In any event, the PBU partners are not permitted to assign their

interests in the PBU without approval from Alaska, and the State

would not approve an assignment that would ignore the well

plugging and well-site DRR obligations. Further, the Unit - 43 -

Agreement does not allow an owner to avoid its DRR obligations by

transferring its ownership interest in PBU.

The Reasonableness of Exxon’s $24 Million Estimate for Prudhoe Bay Well-Plugging and Other Well-Site DRR Costs

Of the total $928 million estimated by Exxon’s experts for

total fieldwide DRR costs, $111.6 million relates to well-site

DRR costs--$85 million for plugging the 645 wells and $26.6

million for closing the pits next to the wells and for cleaning

up the 37 well sites. We discuss below the reasonableness of

Exxon’s estimate of $24 million (22 percent of $111.6 million)

for its share of Prudhoe Bay well plugging and well-site cleanup,

the only DRR costs that we have determined satisfy the first

prong of the all-events test of the accrual method of accounting.

Respondent claims that all of Exxon’s estimated Prudhoe Bay DRR

costs are too remote and speculative, that they cannot be

ascertained with reasonable accuracy, and therefore that they do

not satisfy the second prong of the all-events accrual test.

To protect against hydrocarbon leakage after abandonment of

the wells, AOGCC regulations require that upon abandonment each

well must be “plugged in a manner which will permanently confine

all oil, gas, and water to the separate strata originally

containing them.” This procedure involves setting a series of

cement plugs to seal the wells. Exxon presented a cost-effective

plan, which makes use of coiled tubing units, for setting such

plugs. Exxon’s plugging method achieves the regulatory - 44 -

objectives of isolating the well substances within their separate

strata and preventing the leakage of hydrocarbons after well

abandonment.

Exxon’s estimated DRR costs associated with plugging wells

include wages, rental of equipment, supplies, and hauling of

equipment and materials.

We reiterate that in the oil industry well plugging and

related site cleanup are common events. As a general matter and

based on such experience, the costs of such DRR work is

reasonably estimable.

John B. Willis, currently with Halliburton Energy Services,

Inc., a leading oil well service company, prepared Exxon’s plan

for and estimated the cost of plugging the Prudhoe Bay oil wells

in 1970 and 1980 dollars at a total of $131,976 for each of the

645 wells for which an estimate was done (reflecting total PBU

estimated costs for well plugging of $85,124,800 of which Exxon’s

22-percent share would be $18,727,456). Mr. Willis supervised

the drilling and plugging of wells at Prudhoe Bay during the

1970's. We accept Mr. Willis’ estimates of Exxon’s well-plugging

costs for the Prudhoe Bay field.

During the drilling of wells, mud is pumped into the well

bore. Mud and drill “cuttings” move to the surface as the wells

are drilled and must be contained when they exit from the top of

the wells. To accomplish that containment, the PBU owners

constructed “reserve pits” at the drill sites by enclosing a - 45 -

portion of the tundra with gravel dikes or berms. They

constructed other pits, called “containment” and “flare” pits, to

collect escaped hydrocarbons during oil production.

The AOGCC regulations from the period at issue provided

that, upon abandonment of wells, the pits at well sites must be

filled and the well sites left in a clean and generally level

condition. Exxon’s plan for closing the pits upon abandoning and

plugging the wells uses the so-called freeze-back-in-place

method, which involves placing on each pit a 6-foot layer of

gravel fill with a domed cap. The insulating effect of the

gravel cover keeps the waste located in the pits permanently

frozen, thereby containing the waste in place. During the years

in issue, freeze-back in place represented an acceptable method

of pit closure.

Exxon’s estimated DRR costs associated with pit closures

include wages, fuel, rental of equipment, supplies, and hauling

of gravel and equipment.

Charles E. Wilson, a civil engineer and employee of Harding

Lawson Associates, a large environmental remediation and civil

engineering firm with an Anchorage office, developed Exxon’s pit

closure plan and estimated the related DRR costs. Mr. Wilson is

experienced in closing pits and moving gravel on the North Slope.

Mr. Wilson estimated total PBU pit closing costs in the

Prudhoe Bay field in 1970 and 1980 dollars to be $152,720 for

each of the 174 pits for which an estimate was done (for a total - 46 -

cost for all of the Prudhoe Bay pits of $26,573,366, of which

Exxon’s 22-percent share would be $5,846,141). We accept

Mr. Wilson’s estimates of Exxon’s pit closing costs for the

Prudhoe Bay field.

We conclude that $24 million for Exxon’s share of the costs

of Prudhoe Bay well-site DRR represents, as of the end of the

years in issue, a reasonable estimate of such future costs.5

5 Obviously, the specific years in which wells are constructed would control the specific year in which related estimated well-site DRR costs would be accrued, subject to resolution of the remaining issues herein. - 47 -

Accrual of Estimated Prudhoe Bay Well-Site DRR Costs as Capital Costs or as Current Business Expenses

Although we are satisfied that Exxon’s attempted accrual of

$24 million in estimated DRR costs relating to Prudhoe Bay well

plugging and well-site cleanup would satisfy the all-events test

of the accrual method of accounting, respondent argues that Exxon

may not, without respondent’s permission, accrue such $24 million

into the tax bases of its share of Prudhoe Bay capital asset

costs and claim thereon accelerated depreciation, investment tax

credits (ITC), and intangible drilling costs (IDC). We agree

with respondent.

We believe that Exxon’s claim to such capitalization,

accelerated depreciation, ITC, and IDC constitutes a substantial

deviation from the current ordinary business expense treatment of

Prudhoe Bay well-site DRR costs (at the time of performance of

related DRR work) that Exxon has been using on its Federal

corporation income tax returns as filed and that such a change

would constitute a “change” in Exxon’s method of accounting for

DRR costs for which respondent’s permission is required. See

sec. 446(e), particularly the last sentence of sec. 1.446-

1(e)(2)(ii)(b), and (3)(i), Income Tax Regs. Not having obtained

such permission and absent a finding herein that respondent

abused his discretion in not granting such permission, Exxon is

not allowed to accrue estimated Prudhoe Bay well-site DRR costs

into the capital cost bases of the wells and the well-site - 48 -

equipment and to claim accelerated depreciation, ITC, and IDC

relating thereto. We find no abuse in respondent’s refusal to

authorize this change in the accrual of Exxon’s DRR costs.

The question remains as to whether Exxon should be allowed

its alternative claim to accrue the estimated $24 million in

well-site DRR costs (that we have concluded satisfy the all-

events test) as current ordinary and necessary business expenses

in the year in which oil wells are drilled. Treating such DRR

costs as ordinary business expenses would be consistent with

Exxon’s tax return treatment under which such expenses were so

accrued--albeit in the year in which the DRR work was performed.

The proposed modification to Exxon’s accrual as ordinary

business expenses of estimated well-site DRR costs (from the

year in which the related DRR work is performed to the year in

which wells are drilled and the DRR obligation first becomes

fixed) arguably, as Exxon asserts, would constitute a mere

“correction” in the application of the all-events test to such

costs (namely, the costs would be regarded as being fixed and

reasonably estimable--and therefore as satisfying the all-events

test--in the years the wells are drilled, rather than in later

years in which the DRR work is performed).

Section 1.446-1(e)(2)(ii)(b), Income Tax Regs., provides,

among other things, that a mere technical “correction” in the

application of a taxpayer's existing method of accounting for the

same or similar items may be made without obtaining respondent’s - 49 -

permission. For examples of situations where certain

modifications in the accrual of items under the all-events test

were held to constitute not “changes” in methods of accounting

for such items but mere “corrections” in the application to such

items of the all-events test of the accrual method of accounting

(for which corrections respondent’s permission was not required)

see Northern States Power Co. v. United States, 151 F.3d 876,

883-885 (8th Cir. 1998); Gimbel Bros., Inc. v. United States, 210

Ct. Cl. 17, 535 F.2d 14, 21-23 (1976); Standard Oil Co. v.

Commissioner, 77 T.C. 349, 381-383 (1981).

In Ohio River Collieries Co. v. Commissioner, 77 T.C. 1369

(1981), we recognized that under the all-events test accrual of

estimated strip-mining reclamation costs as ordinary and

necessary business expenses may be appropriate in the year the

land is disturbed, rather than in the year the reclamation work

is performed. Arguably, in light of that case, Exxon’s attempted

modification to the accrual of estimated DRR costs from the year

DRR work is performed to the year in which wells are drilled

would qualify as a mere correction in Exxon’s method of

accounting for such well-site DRR costs for which respondent’s

permission would not be required. In light, however, of our

resolution of the next issue we need not, and we do not, decide

this issue.

Distortion of Income - 50 -

Respondent argues that Exxon’s alternative accrual as

ordinary business expenses in the year wells are drilled of the

$24 million in estimated Prudhoe Bay well-site cleanup costs

(that we determine satisfy the all-events test of the accrual

method of accounting) would distort Exxon’s income. Exxon

responds that under its alternative claim to currently expense

estimated Prudhoe Bay DRR costs its income would not be distorted

for Federal income tax purposes.

Section 446(b) grants respondent broad discretion to

determine whether a particular method of accounting clearly

reflects income and to impose such method of accounting as in

respondent’s opinion does clearly reflect income. Respondent’s

determination is to be respected unless it is found to be an

abuse of discretion. See Thor Power Tool v. Commissioner, 439

U.S. 522, 532 (1979); Ford Motor Co. v. Commissioner, 71 F.3d

209, 212 (6th Cir. 1995), affg. 102 T.C. 87 (1994); Prabel v.

Commissioner, 882 F.2d 820, 823 (3d Cir. 1989), affg. 91 T.C.

1101 (1988).

Herein, under Exxon’s alternative claim, Exxon would fully

write off $24 million in estimated well-site DRR costs

immediately in the years wells in the Prudhoe Bay oil field were

drilled. Such current expense treatment would be unrelated to

the years thereafter in which oil production from the wells

occurred and income from sale of the oil was realized and - 51 -

unrelated to the years in which oil production ceases, the wells

are plugged, and DRR costs are incurred.

We sustain respondent’s determination that Exxon’s attempted

accrual of $24 million in estimated well-site DRR costs as

current business expenses in the years wells are drilled would

result in a distortion of Exxon’s income.

Decisions will be entered

under Rule 155.