Exxon Mobil Corporation and Affiliated Companies, f.k.a. Exxon Corporation and Affiliated Companies v. Commissioner , 114 T.C. No. 20 ( 2000 )

114 T.C. No. 20UNITED 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
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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...)
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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.
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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.
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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.
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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
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field and a few other producing oil fields, there are scattered
throughout the North Slope just a few isolated Eskimo
communities.
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
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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
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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
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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
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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.
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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.
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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
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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.
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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
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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]
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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
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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
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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
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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.
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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.
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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
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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
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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.
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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
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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
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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
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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
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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.