18

56(g) (4) (F)). Thus, the difference between a corporation’s
percentage depletion deduction (if any) claimed for regular
tax purposes and its allowable deduction determined under the
cost depletion method is factored into its overall ACE
adjustment. The Energy Policy Act of 1992 provided an
exception to this general rule in the case of corporations
which are independent oil and gas producers and royalty
owners. Under this exception, for taxable years beginning
after 1992, these corporations are permitted to determine
depletion deductions using the percentage depletion method in
computing their ACE adjustments.

AMT treatm £ ID

Also as discussed above, in computing its regular tax, a
taxpayer who pays or incurs IDCs in the development of
domestic oil or gas properties may elect to either expense or
capitalize these amounts. The difference between the amount
of a taxpayer’s IDC deductions and the amount which would
have been currently deductible had IDCs been capitalized and
recovered over a 10-year period may constitute an item of tax
preference for the AMT to the extent that this amount exceeds
65 percent of the taxpayer’s net income from oil and gas
properties for the taxable year (the "excess IDC preference")
(sec. 57(a)(2)). In addition, for purposes of computing the a
corporation’s ACE adjustment to the AMT, IDCs are capitalized
and amortized over the 60-month period beginning with the
month in which they are paid or incurred (sec.
56(g) (4) (D) (i)).

For taxpayers other than integrated oil companies, the
Energy Policy Act of 1992 repealed the excess IDC preference
for IDCs related to oil and gas wells for taxable years
beginning after 1992 (sec. 57(a) (2) (E)). The repeal of the
excess IDC preference, however, may not result in the
reduction of the amount of the taxpayer’s AMTI by more than
40 percent (30 percent for taxable years beginning in 1993)
of the amount that the taxpayer’s AMTI would have been had
the excess IDC preference not been repealed.

In addition, for corporations other than integrated oil
companies, the 1992 Energy Policy Act repealed the ACE
adjustment for IDCs paid or incurred in taxable years
beginning after December 31, 1992, with respect to oil and
gas wells. That is, such a taxpayer is permitted to utilize
its regular tax method of writing off IDCs for purposes of
computing its adjusted current earnings.



12

and identified within the original project area, then the
entire expenditure for those exploratory operations is to be
allocated to that one area of interest and thus capitalized
into the depletable basis of that area of interest. On the
other hand, if two or more areas of interest are located and
identified within the original project area, the entire
expenditure for the exploratory operations is to be allocated
equally among the various areas of interest.

If, however, from the data obtained by the exploratory
operations no areas of interest are located and identified by
the taxpayer within the original project area, then the 1977
ruling states that the entire amount of the G&G costs related
to the exploration is deductible as a loss under section 165
for the taxable year in which that particular project area is
abandoned as a potential source of mineral production.

The 1977 ruling further provides that if, on the basis
of data obtained from a detailed survey that does not relate
exclusively to any particular property within a particular
area of interest, an oil or gas property is acquired or
retained within or adjacent to that area of interest, the
entire G&G exploration expenditures, including those incurred
prior to the identification of the particular area of
interest but allocated thereto, are to be allocated to the
property as a capital cost under section 263(a). If more than
one property is acquired or retained within or adjacent to an
area of interest, it is proper to determine the amount of the
G&G costs allocable to each such property by allocating the
entire amount of the costs among the properties so acquired
or retained on the basis of the comparative acreage of the
properties.

If, however, no property is acquired or retained within
or adjacent to that area of interest, the entire amount of
the G&G costs allocable to the area of interest is deductible
as a loss under section 165 for the taxable year in which
such area of interest is abandoned as a potential source of
mineral production.

In 1983, the IRS issued Revenue Ruling 83-105," which
elaborates on the positions set forth in the 1977 ruling by
setting forth seven factual situations and applying the
principles of the 1977 ruling to those situations. In
addition, Revenue Ruling 83-105 explains what constitutes an
"abandonment as a potential source of mineral production."

9 1983-2 C.B. 51.



3

Under the percentage depletion method, generally 15
percent of the taxpayer’s gross income from an oil- or
gas-producing property is allowed as a deduction in each
taxable year (sec. 613A(c)). The amount deducted may not
exceed 100 percent of the net income from that property in
any year (the "net-income limitation") (sec. 613(a)).?
Additionally, the percentage depletion deduction for all oil
and gas properties may not exceed 65 percent of the
taxpayer’s overall taxable income (determined before such
deduction and adjusted for certain loss carrybacks and trust
distributions) (sec. 613A(d) (1)).* Because percentage
depletion, unlike cost depletion, is computed without regard
to the taxpayer’s basis in the depletable property,
cumulative depletion deductions may be greater than the
amount expended by the taxpayer to acquire or develop the
property.

A taxpayer is required to determine the depletion
deduction for each oil or gas property under both the
percentage depletion method (if the taxpayer is entitled to
use this method) and the cost depletion method. If the cost
depletion deduction is larger, the taxpayer must utilize that
method for the taxable year in question (sec. 613(a)).

a £ and gas e m_to independent
rod 1 owne:

The Tax Reduction Act of 1975 (the "1975 Act") repealed
the deduction for percentage depletion with respect to much
oil and gas production. Following the 1975 Act, only
independent producers and royalty owners (as contrasted to
integrated oil companies) are allowed to claim percentage
depletion with respect to up to 1,000 barrels of average
daily production of domestic crude oil or an equivalent

3 By contrast, for any other mineral qualifying for the

percentage depletion deduction, such deduction may not exceed 50
percent of the taxpayer’s taxable income from the depletable
property. A similar 50-percent net-income limitation applied to
oil and gas properties for taxable years beginning before 1991.
Section 11522(a) of the Omnibus Budget Reconciliation Act of 1990
(P.L. 101-508) prospectively changed the net-income limitation
threshold to 100 percent only for oil and gas properties, for
taxable years beginning after 1990.

4 amounts disallowed.as a result of this rule may be carried
forward and deducted in subsequent taxable years, subject to the
65-percent taxable income limitation for those years.


19

F. Passive Activity Loss and Credit Rules

A taxpayer's deductions from passive trade or business
activities, to the extent they exceed income from all such
passive activities of the taxpayer (exclusive of portfolio
income), generally may not be deducted against other income
(sec. 469). Thus, for example, an individual taxpayer may
not deduct losses from a passive activity against income from
wages. Losses suspended under this "passive activity loss"
limitation are carried forward and treated as deductions from
passive activities in the following year, and thus may offset
any income from passive activities generated in that later
year. Undeducted losses from a passive activity may be
deducted in full when the taxpayer disposes of its entire
interest in that activity to an unrelated party ina
transaction in which all realized gain or loss is recognized.

An activity generally is treated as passive if the
taxpayer does not materially participate in it. A taxpayer is
treated as materially participating in an activity only if
the taxpayer is involved in the operations of the activity on
a basis which is regular, continuous, and substantial.

A working interest in an oil or gas property generally
is not treated as a passive activity, whether or not the
taxpayer materially participates in the activities related to
that property (sec. 469(c) (3) and (4)). This exception from
the passive activity rules does not apply if the taxpayer
holds the working interest through an entity which limits the
liability of the taxpayer with respect to the interest. In
addition, if a taxpayer has any loss for any taxable year
from a working interest in an oil or gas property which is
treated pursuant to this working interest exception as a loss
which is not from a passive activity, then any net income
from such property (or any property the basis of which is
determined in whole or in part by reference to the basis of
such property) for any succeeding taxable year is treated as
income of the taxpayer which is not from a passive activity.

Similar limitations apply to the utilization of tax
credits attributable to passive activities (sec.
469(a) (1) (B}). Thus, for example, the passive activity rules
{and, consequently, the oil and gas working interest
exception to those rules) apply to the nonconventional fuels

77 This provision applies to individuals, estates, trusts, and
personal service corporations.



21

G. Sales and Exchanges of Property Interests

Under present law, individual taxpayers are subject to a
maximum statutory income tax rate of 39.6 percent. If an
individual recognizes capital gains, however, the gains are
subject to a maximum tax rate of 28 percent. There currently
is no differential between the rates of taxation of capital
gains and ordinary income in the case of corporate taxpayers.

Gain recognized from the disposition of an interest in
an oil or gas property generally is characterized as capital
gain. The Code contains a special recapture provision,
however, which mandates that in certain cases a portion of
any gain is to be treated as ordinary income and not as
capital gain (sec. 1254). Specifically, the Code provides
that if a taxpayer disposes of "section 1254 property" that
was placed in service after 1986, then the lesser of (1) the
gain recognized on the disposition or (2) the aggregate
amount of (a) depletion deductions which resulted ina
reduction in the basis of the property disposed of and (b)
IDCs deducted pursuant to an election under section 263(c)
and which, but for the deduction, would have been included in
the adjusted basis of the property, is characterized as
ordinary income.” For this purpose, the term "section 1254
property" means any property (within the meaning of section
614) if any IDCs are properly chargeable to such property or
the adjusted basis of such property includes adjustments for
depletion deductions.

% For dispositions of property placed in service before 1987,
taxpayers are not required to recapture depletion deductions and
are required to recapture IDC deductions only in excess of the
amounts which would have been deductible as depletion if the IDCs
had been capitalized.



16

unless the project's operator submits to the IRS a
certification from a petroleum engineer that the project
meets the requirements set forth in the preceding paragraph.

The enhanced oil recovery credit is effective for
taxable years beginning after December 31, 1990, with respect
to costs paid or incurred in EOR projects begun or
significantly expanded after that date.



8

the election of the operator.'' In the case of an integrated
oil company (i.e., a company that engages, either directly or
though a related enterprise, in substantial retailing or
refining activities) that has elected to expense IDCs, 30
percent of the IDCs on productive wells must be capitalized
and amortized over a 60-month period (sec. 291(b) (1) (A)).”

Notwithstanding the fact that a taxpayer has made the
election to deduct IDCs, the Code provides an additional
election under which the taxpayer is allowed to capitalize
and amortize certain IDCs over a 60-month period beginning
with the month the expenditure was paid or incurred (sec.
59(e)(1)). This rule applies on an expenditure-by-expenditure
basis; that is, for any particular taxable year, a taxpayer
may deduct some portion of its IDCs and capitalize the rest
under this provision.

The election to deduct IDCs applies only to those IDCs
associated with domestic properties. For this purpose, the
United States includes certain wells drilled offshore."

Ex m from uni apitaliz. ies
The uniform capitalization rules, which were enacted as

part of the Tax Reform Act of 1986, require certain direct
and indirect costs allocable to property to be included in

n Treas. Reg. sec. 1.612-4(b) (4).

2 The IRS has ruled that if a company that has capitalized
and begun to amortize IDCs over a 60-month period pursuant to
section 291 ceases to be an integrated oil company, it may not
immediately write off the unamortized portion of the capitalized
IDCs, but instead must continue to amortize the IDCs so capitalized
over the 60-month amortization period. (Rev. Rul. 93-26, 1993-15
I.R.B. 5.)

3 In the case of IDCs paid or incurred with respect to an oil
or gas well located outside of the United States, the costs, at the
election of the taxpayer, are either (1) included in adjusted basis
for purposes of computing the amount of any deduction allowable for
cost depletion or (2) capitalized and amortized ratably over a
10-year period beginning with the taxable year such costs were paid
or incurred (sec. 263(i)).

4 The term "United States" for this purpose includes the
seabed and subsoil of those submarine areas that are adjacent to
the territorial waters of the United States and over which the
United States has exclusive rights, in accordance with
international law, with respect to the exploration and exploitation
of natural resources (i.e., the Continental Shelf area) (sec. 638).



company .

Prior to enactment of the Omnibus Budget Reconciliation
Act of 1990 (the "1990 Act"), if an interest in a proven oil
or gas property was transferred (subject to certain
exceptions), the production from such interest did not
qualify for percentage depletion.’ The 1990 Act repealed the
limitation on claiming percentage depletion on transferred
properties effective for property transfers occurring after
October 11, 1990.

Pere e zeti rai no

The 1990 Act also created special percentage depletion
provisions for oil and gas production from so-called marginal
properties held by independent producers or royalty owners
(sec. 613A(c) (6)). Under this provision, the statutory
percentage depletion rate is increased (from the general rate
of 15 percent) by one percent for each whole dollar that the
average price of crude oil (as determined under the
provisions of the nonconventional fuels production credit of
section 29) for the immediately preceding calendar year is
less than $20 per barrel. In no event may the rate of
percentage depletion under this provision exceed 25 percent
for any taxable year. The increased rate applies for the
taxpayer’s taxable year which immediately follows a calendar
year for which the average crude oil price falls below the
$20 floor. To illustrate the application of this provision,
the average price of a barrel of crude oil for calendar year
1992 was $15.98;* thus, the percentage depletion rate for
production from marginal wells is increased by four percent
(to 19 percent) for taxable years beginning in 1993.

The Code defines the term "marginal production" for this
purpose as domestic crude oil or domestic natural gas which
is produced during any taxable year from a property which (1)
is a stripper well property for the calendar year in which
the taxable year begins, or (2) is a property substantially
all of the production from which during such calendar year is
heavy oil (i.e., oil that has a weighted average gravity of
20 degrees API or less corrected to 60 degrees Fahrenheit)
(sec. 613A(c) (6) (D)). A stripper well property is any oil or
gas property which produces a daily average of 15 or less
equivalent barrels of oil and gas per producing oil or gas
well on such property in the calendar year during which the

7 The exceptions to this rule included transfers at death,

certain transfers to controlled corporations, and transfers between
controlled corporations or other business entities.

8 IRS Notice 93-28, I.R.B. 1993-18, 14.



4

amount of domestic matural gas (sec. 613A(c)).° For producers
of both oil and natural gas, this limitation applies on a
combined basis. All production owned by businesses under
common control and members of the same family must be
aggregated (sec. 613A(c)(8)); each group is then treated as
one producer for application of the 1,000-barrel limitation.

For purposes of the percentage depletion allowance, an
independent producer is any producer who is not a "retailer"
or "refiner." A retailer is any person who directly, or
through a related person, sells oil or natural gas or any
product derived therefrom (1) through any retail outlet
operated by the taxpayer or related person, or (2) to any
person that is obligated to market or distribute such oil or
natural gas (or product derived therefrom) under the name of
the taxpayer or the related person, or that has the authority
to occupy any retail outlet owned by the taxpayer or a
related person (sec. 613A(d)(2)). Bulk sales of crude oil and
natural gas to commercial or industrial users, and bulk sales
of aviation fuel to the Department of Defense, are not
treated as retail sales for this purpose. Further, a person
is not a retailer within the meaning of this provision if the
combined gross receipts of that person and all related
persons from the retail sale of oil, natural gas, or any
product derived therefrom do not exceed $5 million for the
taxable year.

A refiner is any person who directly or through a
related person engages in the refining of crude oil, but only
if such person or related person has a refinery run in excess
of 50,000 barrels per day on any day during the taxable year
(sec. 613A(d) (4)).

In addition to the independent producer and royalty
owner exception, certain sales of natural gas under a fixed
contract in effect on February 1, 1975, and certain natural
gas from geopressurized brine,® are eligible for percentage
depletion, at rates of 22 percent and 10 percent,
respectively. These exceptions apply without regard to the
1,000-barrel-per-day limitation and regardless of whether the
producer is an independent producer or an integrated oil

5 As originally enacted, the depletable oil quantity was 2,000

barrels of average daily production. This was gradually phased down
to 1,000 barrels of average daily production for 1980 and
thereafter. The 1975 Act also phased down the percentage depletion
rate from 22 percent in 1975 to 15 percent in 1984 and thereafter.

6 This exception is limited to wells the drilling of which
began between September 30, 1978, and January 1, 1984.



17

E. Alternative Minimum Tax

In_ general

A taxpayer is subject to an alternative minimum tax
("AMT") to the extent that its tentative minimum tax exceeds
its regular income tax liability (sec. 55(a)).. A corporate
taxpayer's tentative minimum tax generally equals 20 percent
of its alternative minimum taxable income in excess of an
exemption amount. (The marginal AMT rate for a noncorporate
taxpayer is 26 or 28 percent, depending on the amount of its
alternative minimum taxable income above an exemption
amount.) Alternative minimum taxable income ("AMTI") is the
taxpayer’s taxable income increased by certain tax
preferences and adjusted by determining the tax treatment of
certain items in a manner which negates the deferral of
income resulting from the regular tax treatment of those
items.

The AMTI of a corporation is increased by an amount
equal to 75 percent of the amount by which adjusted current
earnings ("ACE") of the corporation exceed AMTI (as
determined before this adjustment) (sec. 56(g)). In general,
ACE means AMTI with additional adjustments that generally
follow the rules presently applicable to corporations in
computing their earnings and profits.

AMT treatment of depletion

As stated above, for purposes of computing regular
taxable income, taxpayers involved in the production of
natural resources (including oil and gas) generally are
permitted to claim a deduction for depletion under either of
two methods--the cost depletion method or the percentage
depletion method. The percentage depletion deduction is not
limited to the taxpayer’s adjusted basis in the depletable
property. Thus, a taxpayer is permitted to claim such
deductions that are in excess of the amount the taxpayer
invested in the depletable property.

As a general rule, percentage depletion deductions
claimed in excess of the basis of the depletable property
constitute an item of tax preference in determining the AMT
(sec. 57(a)(1)). For taxable years beginning after 1992,
however, the Energy Policy Act of 1992 provides that excess
percentage depletion deductions related to crude oil and
natural gas production are not items of tax preference for
AMT purposes.

Moreover, as a general rule a corporation must use the
cost depletion method in computing its ACE adjustment (sec.



B. Intangible Drilling and Development Costs
In_general

In general, costs that benefit future periods must be
capitalized and recovered over such periods for income tax
purposes, rather than being expensed in the period the costs
are incurred. Special rules are provided, however, for the
treatment of intangible drilling and development costs
("IDCs"). Under these special rules, an operator (i.e., a
person who holds a working or operating interest in any tract
or parcel of land either as a fee owner or under a lease or
any other form of contract granting working or operating
rights) who pays or incurs IDCs in the development of an oil
or gas property located in the United States, may elect
either to expense or capitalize those costs (sec. 263(c)).

IDCs include all expenditures made by an operator for
wages, fuel, repairs, hauling, supplies, etc., incident to
and necessary for the drilling of wells and the preparation
of wells for the production of oil and gas. In addition, IDCs
include the cost to operators of any drilling or development
work (excluding amounts payable only out of production or
gross or net proceeds from production, if the amounts are
depletable income to the recipient, and amounts properly
allocable to the cost of depreciable property) done by
contractors under any form of contract (including a turnkey
contract). Such work includes labor, fuel, repairs, hauling,
and supplies which are used in the drilling, shooting, and
cleaning of wells; in such clearing of ground, draining, road
making, surveying, and geological works (as are necessary in
preparation for the drilling of wells); and in the
construction of such derricks, tanks, pipelines, and other
physical structures as are necessary for the drilling of
wells and the preparation of wells for the production of oil
and gas. Generally, IDCs do not include expenses for items
which have a salvage value (such as pipes and casings), or
items which are part of the acquisition price of an interest
in the property.”

If an election to expense IDCs is made, the taxpayer
deducts the amount of the IDCs as an expense in the taxable
year the cost is paid or incurred. Generally, if IDCs are not
expensed, but are capitalized, they may be recovered through
depletion or depreciation, as appropriate; or in the case of
a nonproductive well ("dry hole"), they may be deducted, at

‘0 Treas. Reg. sec. 1.612-4(a).



OVERVIEW OF PRESENT-LAW TAX RULES RELATING TO
DOMESTIC OIL AND GAS EXPLORATION AND PRODUCTION

Scheduled for a Hearing
Before the
SUBCOMMITTEE ON TAXATION
of the
SENATE COMMITTEE ON FINANCE

on March 14, 1994

Prepared By the Staff

of the

JOINT COMMITTEE ON TAXATION

March 11, 1994

JCX-2-94



10

C. Geological and Geophysical Costs

In_ general

Under the Code, no current deduction is allowed for any
amount paid for new buildings or for permanent improvements
or betterments made to increase the value of any property or
estate (sec. 263(a)). The regulations define capital amounts
to include amounts paid or incurred (1) to add to the value,
or substantially prolong the useful life, of property owned
by the taxpayer or (2) to adapt property to a new or
different use.

The proper income tax treatment of geological and
geophysical expenditures ("G&G costs") has. been the subject
of a number of court decisions and administrative rulings.
G&G costs are incurred by the taxpayer for the purpose of
obtaining and accumulating data that will serve as a basis
for the acquisition and retention of mineral properties by
taxpayers exploring for minerals. Courts have ruled that such
costs are capital in nature and are not deductible as
ordinary and necessary business expenses.’ Accordingly, the
costs attributable to such exploration are allocable to the
cost of the property acquired or retained.” The term
"property" is used in this case in the sense of an interest
in a property as defined in the Code (sec. 614) and related
regulations, and includes an economic interest in a tract or
parcel of land notwithstanding that a mineral deposit has not
been established or proven at the time the costs are
incurred.

Revenue Ruling 77-188

In Revenue Ruling 77-188"* (hereinafter referred to as
the "1977 ruling"), the Internal Revenue Service ("IRS")
provided guidance regarding the proper tax treatment of G&G

1% Treas. Reg. sec. 1.263(a)- (1) (b).

16
(1942) .

See, e.g., hhermerho: il lobar , 46 B.T.A. 151

By contrast, section 617 of the Code permits a taxpayer to
elect to deduct certain expenditures incurred for the purpose of
ascertaining the existence, location, extent, or quality of any
deposit of ore or other mineral (but not oil and gas). These
deductions are subject to recapture if the mine with respect to
which the expenditures were incurred reaches the producing stage.

% 1977-1 C.B. 76.



9

inventory or capitalized as part of the basis of such
property (sec. 263A). In general, the uniform capitalization
rules apply to real and tangible personal property produced
by the taxpayer or acquired for resale. Pursuant to a special
exception, these rules do not apply to IDCs incurred with
respect to oil or gas wells which are otherwise deductible
under the Code (sec. 263A(c) (3)).



6
taxpayer’s taxable year begins (sec. 613A(c) (6) (E)).°

The determination of whether a property qualifies as a
stripper well property is made separately for each calendar
year. The fact that a property is or is not a stripper well
property for one year does not affect the determination of
the status of that property for a subsequent year. Further,
the stripper well property determination is made by a
taxpayer for each separate property interest (as defined
under section 614) held by the taxpayer during a calendar
year. The determination is based on the total amount of
production from all producing wells that are treated as part
of the same property interest of the taxpayer. A property
qualifies as a stripper well property for a calendar year
only if the wells on such property were producing during that
period at their maximum efficient rate of flow.

If a taxpayer’s property consists of a partial interest
in one or more oil- or gas-producing wells, the determination
of whether the property is a stripper well property or a
heavy oil property is made with respect to total production
from such wells, including the portion of total production
attributable to ownership interests other than the
taxpayer's. If the property satisfies the requirements of a
stripper well property, then that person receives: the
benefits of this provision with respect to its allocable
share of the production from the property for its taxable
year that begins during the calendar year in which the
property so qualifies.

The allowance for percentage depletion on production
from marginal oil and gas properties is subject to the 1,000-
barrel-per-day limitation discussed above. Unless a taxpayer
elects otherwise, marginal production is given priority over
other production for purposes of utilization of that
limitation.

° Equivalent barrels is computed as the sum of (1) the number
of barrels of crude oil produced, and (2) the number of cubic feet
of natural gas produced divided by 6,000. If a well produced 10

barrels of crude oil and 12,000 cubic feet of natural gas,

equivalent barrels produced would equal 12 (i.e., 10 + (12,000 /

6,000)).



20

production credit and the enhanced oil recovery credit.*

28 A proposed technical correction to section 469 would

provide that if a taxpayer has net income from a working interest
in an oil and gas property which is treated as not arising from a
passive activity, then any tax credits attributable to the interest
in that property would be treated as credits not from a passive
activity (and, thus, not subject to the passive activity credit
limitation) to the extent that the amount of such credits does not
exceed the regular tax liability of the taxpayer for the taxable
year which is allocable to such net income. (H.R. 3419, 103d
Cong., Ist Sess., sec. 1003(d), as reported by the House Committee
on Ways and Means, H. Rept. 103-353, 216.)



PRESENT-LAW TAX RULES APPLICABLE TO
DOMESTIC OIL AND GAS OPERATIONS

A. Depletion

eral

Depletion, like depreciation, is a class of ordinary and
necessary business expense. In both cases, the taxpayer is
allowed a deduction in recognition of the fact that an
asset--in the case of depletion for oil or gas interests, the
mineral reserve itself--is being expended in order to produce
income. Certain costs incurred prior to drilling an oil- or
gas-producing property are recovered through the depletion
deduction. These include costs of acquiring the lease or
other interest in the property, and geological and
geophysical costs (in advance of actual drilling) .

Depletion is available to any person having an economic
interest in a producing property. Treasury Department
regulations state that an economic interest is possessed in
every case in which the taxpayer has acquired by investment
any interest in mineral in place, and secures, by any form of
legal relationship, income derived from the extraction of the
mineral, to which it must look for a return of its capital.”
Thus, for example, both working interests and royalty
interests in an oil- or gas-producing property constitute
economic interests, thereby qualifying the interest holders
for depletion deductions with respect to the property. A
taxpayer who has no capital investment in the mineral deposit
does not possess an economic interest merely because through
a contractual relation it possesses a mere economic or
pecuniary advantage derived from production.

Two methods of depletion are currently allowable under
the Internal Revenue Code (the "Code"): (1) the cost
depletion method, and (2) the percentage depletion method
(secs. 611-613). Under the cost depletion method, the
taxpayer deducts that portion of the adjusted basis of the
depletable property which is equal to the ratio of units sold
from that property during the taxable year to the number of
units remaining as of the taxable year (in general, the
number of units remaining to be recovered in the property at
the end of the taxable year, plus the number of units sold
during the taxable year). The amount recovered under cost
depletion, thus, may never exceed the taxpayer’s basis in the
property.

? Treas. Reg. sec. 1.611-1(b) (1).



13

D. Tax Credits
1. Nonconventional fuels production credit

Taxpayers that produce certain qualifying fuels from
nonconventional sources are eligible for a tax credit ("the
section 29 credit") equal to $3 per barrel or Btu oil barrel
equivalent.” Fuels qualifying for the credit must be
produced domestically from a well drilled, or a facility
treated as placed in service, before January 1, 1993.” The
section 29 credit generally is available for qualified fuels
sold to unrelated persons before January 1, 2003.”

For purposes of the credit, qualified fuels include: (1)
oil produced from shale and tar sands; (2) gas produced from
geopressured brine, Devonian shale, coal seams, a tight
formation, or biomass (i.e., any organic material other than
oil, natural gas, or coal (or any product thereof)); and (3)
liquid, gaseous, or solid synthetic fuels produced from coal
(including lignite), including such fuels when used as
feedstocks. The amount of the credit is determined without
regard to any production attributable to a property from
which gas from Devonian shale, coal seams, geopressured
brine, or a tight formation was produced in marketable
quantities before 1980.

2% A barrel-of-oil equivalent generally means that amount of

the qualifying fuel which has a Btu (British thermal unit) content
of 5.8 million.

21 Pursuant to section 1918 of the Energy Policy Act of 1992,
a facility that produces gas from biomass or produces liquid,
gaseous, or solid synthetic fuels from coal (including lignite)
generally will be treated as being placed in service before January
1, 1993, if it is placed in service by the taxpayer before January
1, 1997, pursuant to a written binding contract in effect before
January 1, 1996. In the case of a facility that produces coke or
coke gas, however, this provision applies only if the original use
of the facility commences with the taxpayer.

Also, the IRS has ruled that production from certain post-1992
"recompletions" of wells that were originally drilled prior to the
expiration date of the credit would qualify for the section 29
credit. (Rev. Rul. 93-54, 1993-27 I.R.B. 5.)

2 If a facility that qualifies for the 1992 Energy Policy
Act's binding contract rule is originally placed in service after
December 31, 1992, production from the facility may qualify for the
credit if sold to an unrelated person before January 1, 2008.



15

required to be capitalized and recovered through
depreciation, depletion, or amortization, as appropriate,
with respect to these costs. A taxpayer may elect not to have
the enhanced oil recovery credit apply for a taxable year.

The amount of the enhanced oil recovery credit is
reduced in a taxable year following a calendar year during
which the annual average unregulated wellhead price per
barrel of domestic crude oil exceeds $28 (adjusted for
inflation since 1990).*% In such a case, the credit would be
reduced ratably over a $6 phaseout range.

For purposes of the credit, qualified enhanced oil
recovery costs include the following costs which are paid or
incurred with respect to a qualified EOR project: (1) the
cost of tangible property which is an integral part of the
project and with respect to which depreciation or
amortization is allowable; (2) IDCs with respect to which a
taxpayer may make an election to deduct under section
263(c);% and (3) the cost of tertiary injectants with
respect to which a deduction is allowable under section 193.

A qualified EOR project means any project that is
located within the United States and involves the application
(in accordance with sound engineering principles) of one or
more tertiary recovery methods as defined under section
193(b) (3) which can reasonably be expected to result in more
than an insignificant increase in the amount of crude oil
which ultimately will be recovered. The tertiary recovery
methods referred to in section 193(b) (3) generally include
the following nine methods which were listed in section
212.78(c) of the June 1979 Department of Energy regulations:
miscible fluid displacement, steam-drive injection,
microemulsion flooding, in situ combustion, polymer-augmented
water flooding, cyclic-steam injection, alkaline flooding,
carbonated water flooding, and immiscible non-hydrocarbon gas
displacement, or any other method approved by the IRS. In
addition, for purposes of the enhanced oil recovery credit,
immiscible non-hydrocarbon gas displacement generally is
considered a qualifying tertiary recovery method, even if the
gas injected is not carbon dioxide.

A project is not considered a qualified EOR project

% The average per-barrel price of crude oil for this purpose
is determined under the same manner as it is for purposes of the

section 29 credit.

% In the case of an integrated oil company, the credit base
includes those IDCs which the taxpayer is required to capitalize

under section 291(b) (1).



INTRODUCTION

This document,' prepared by the staff of the Joint
Committee on Taxation, provides an overview of various
present-law tax provisions that relate to the exploration
for, and the production of, crude oil and natural gas located
within the United States. The Subcommittee on Taxation of the
Senate Finance Committee has scheduled a public hearing on
tax proposals to increase domestic oil and gas production on
March 14, 1994.

1 This document may be cited as follows: Joint Committee on

Taxation, rview of Pri nt-Law Tax

Qverview of Present-Law Tax Rules Relating to Domestic
Qil_ and Gas Exploration and Production (JCX-2-94), March 11, 1994.


CONTENTS

INTRODUCTION.............- nec c eee ween eee rs

PRESENT-LAW TAX RULES APPLICABLE TO

DOMESTIC OIL AND GAS OPERATIONS.............. sence eae eree
A. Depletion............... see eee e eee eee e eee eee eee
B. Intangible Drilling and Development Costs.......
C. Geological and Geophysical Costs................
D. Tax Credits........ cc cece eee eee eee tee eee

E.

F.

1. Nonconventional fuels production credit.....

2. Enhanced oil recovery credit..............6-

Alternative Minimum Tax...........-.0- es eeeee eee
Passive Activity Loss and Credit Rules..........
Sales and Exchanges of Property Interests.......

13

13

14

17

19

21



11

costs. The ruling describes a typical geological and
geophysical exploration program as containing the following
elements:

o It is customary in the search for mineral producing
properties for a taxpayer to conduct an exploration
program in one or more identifiable project areas. Each
project area encompasses a territory that the taxpayer
determines can be explored advantageously in a single
integrated operation. This determination is made after
analyzing certain variables such as the size and
topography of the project area to be explored, the
existing information available with respect to the
project area and nearby areas, and the quantity of
equipment, the number of personnel, and the amount of
money available to conduct a reasonable exploration
program over the project area.

o The taxpayer selects a specific project area from
which geological and geophysical data are desired and
conducts a reconnaissance-type survey utilizing various
geological and geophysical exploration techniques that
are designed to yield data that will afford a basis for
identifying specific geological features with sufficient
mineral potential to merit further exploration.

o Each separable, noncontiguous portion of the original
project area in which such a specific geological feature
is identified is a separate "area of interest." The
original project area is subdivided into as many small
projects as there are areas of interest located and
identified within the original project area. If the
circumstances permit a detailed exploratory survey to be
conducted without an initial reconnaissance-type survey,
the project area and the area of interest will be
coextensive.

eo The taxpayer seeks to further define the geological
features identified by the prior reconnaissance-type
surveys by additional, more detailed, exploratory
surveys conducted with respect to each area of interest.
For. this purpose, the taxpayer engages in more intensive
geological and geophysical exploration employing methods
that are designed to yield sufficiently accurate sub-
surface data to afford a basis for a decision to acquire
or retain properties within or adjacent to a particular
area of interest or to abandon the entire area of
interest as unworthy of development by mine or well.

The 1977 ruling provides that if, on the basis of data
obtained from the preliminary geological and geophysical
exploration operations, only one area of interest is located



14

The amount of the section 29 credit generally is
adjusted by an inflation adjustment factor for the calendar
year in which the sale occurs.TM There is no adjustment for
inflation in the case of the credit for sales of natural gas
produced from a tight formation. The credit begins to phase
out if the annual average unregulated wellhead price per
barrel of domestic crude oil exceeds $23.50 multiplied by the
inflation adjustment factor.TM

The amount of the section 29 credit allowable with
respect to a project is reduced by any unrecaptured business
energy tax credit (sec. 48) or enhanced oil recovery credit
(sec. 43) claimed with respect to such project.

As with most other credits, the section 29 credit may
not be used to offset alternative minimum tax liability. Any
unused section 29 credit generally may not be carried back or
forward to another taxable year; however, a taxpayer receives
a credit for prior year minimum tax liability to the extent
that a section 29 credit is disallowed as a result of the
operation of the alternative minimum tax (sec. 53).

2. Enhanced oil recovery credit

Taxpayers are permitted to claim a general business
credit for a taxable year, which consists of several
different components (sec. 38(a)). One component of the
general business credit is the enhanced oil recovery credit
(sec. 43). The general business credit for a taxable year may
not exceed the excess (if any) of the taxpayer’s net income
over the greater of (1) the tentative minimum tax, or (2) 25
percent of so much of the taxpayer’s net regular tax
liability as exceeds $25,000. Any unused general business
credit generally may be carried back three taxable years and
carried forward 15 taxable years.

The enhanced oil recovery credit for a taxable year is
equal to 15 percent of certain costs attributable to
qualified enhanced oil recovery ("EOR") projects undertaken
by the taxpayer in the United States during the taxable year.
To the extent that a credit is allowed for such costs, the
taxpayer must reduce the amount otherwise deductible or

% The inflation adjustment factor for the 1992 taxable year
was 1.8430. Therefore, the inflation-adjusted amount of the credit
for that year was $5.53 per barrel or barrel equivalent. (IRS
Notice 93-28, I.R.B. 1993-18, 14.)

% For 1992, the inflation adjusted threshold for onset of the
phaseout was $43.31 ($23.50 x 1.843) and the average wellhead price
for that year was $15.98. (IRS Notice 93-28, I.R.B. 1993-18, 14.)