DESCRIPTION OF SELECTED PRESENT-LAW PROVISIONS

RELATING TO THE FEDERAL INCOME TAX TREATMENT

OF DOMESTIC OIL AND GAS PRODUCTION

AND CERTAIN UTILITY CONSERVATION PAYMENTS

Scheduled for a Public Hearing

Before the

SUBCOMMITTEE ON OVERSIGHT

OF THE

HOUSE COMMITTEE ON WAYS AND MEANS

on March 5, 2001

Prepared by the Staff

of the

JOINT COMMITTEE ON TAXATION

March 1, 2001

JCX-5-01
ii

CONTENTS

Page

INTRODUCTION.......................................................................................................... 1

I. INCOME TAX RULES RELATING TO DOMESTIC OIL AND GAS

PRODUCTION......................................................................................................... 2

A. Depletion.............................................................................................................. 2

B. Intangible Drilling and Development Costs.......................................................... 5

C. Geological and Geophysical Costs....................................................................... 7

D. Tax Credits........................................................................................................... 9

1. Credit for producing fuels from nonconventional sources.............................. 9

2. Enhanced oil recovery credit.......................................................................... 10

E. Alternative Minimum Tax..................................................................................... 12

F. Passive Activity Loss and Credit Rules ............................................................... 13

G. Sales and Exchanges of Property Interests............................................................ 13

H. Net Operating Losses........................................................................................... 14

II. EXCLUSION FOR CERTAIN ENERGY SUBSIDIES PROVIDED BY A

PUBLIC UTILITY.................................................................................................... 15
1

INTRODUCTION

The Subcommittee on Oversight of the House Committee on Ways and Means has 

scheduled a public hearing on March 5, 2001, on issues relating to the impact of Federal tax law 

on domestic production of oil and gas and energy conservation. This document,1 prepared by the 

staff of the Joint Committee on Taxation, describes selected Federal income tax provisions that 

may affect these activities.

 

1

 This document may be cited as follows: Joint Committee on Taxation, Description of 

Selected Present-Law Provisions Relating to the Federal Income Tax Treatment of Domestic Oil 

and Gas Production and Certain Utility Conservation Payments (JCX-5-01), March 1, 2001.
2

I. INCOME TAX RULES RELATING TO DOMESTIC

OIL AND GAS PRODUCTION

A. Depletion

In general

Depletion, like depreciation, is a form of capital cost recovery. 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 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. 

An economic interest is possessed in every case in which the taxpayer has acquired by 

investment any interest in minerals 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.2 Thus, for example, both working interests and royalty interests in an oil- or gasproducing 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 it possesses an 

economic or pecuniary advantage derived from production through a contractual relation.

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 end of taxable year plus the number of units sold 

during the taxable year. Thus, the amount recovered under cost depletion may never exceed the 

taxpayer's basis in the property.

The Code generally limits the percentage depletion method for oil and gas properties to 

independent producers and royalty owners.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 generally may not exceed 

100 percent of the net income from that property in any year (the "net-income limitation") (sec. 

613(a)).4 Additionally, the percentage depletion deduction for all oil and gas properties may not 

 

2

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

3

 Sec. 613A.

4

 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 prospectively changed the net-income limitation threshold to 100 percent only for oil and 
3

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)).5 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)).

Limitation on oil and gas percentage depletion to independent producers and royalty 

owners

As stated above, percentage depletion of oil and gas properties generally is not permitted, 

except for independent producers and royalty owners, certain fixed-price gas contracts, and 

natural gas from geopressured brine.6 For purposes of the percentage depletion allowance, an 

independent producer is any producer that is not a "retailer" or "refiner." A retailer is any person 

that directly, or through a related person, sells oil or natural gas (or a derivative thereof): 

(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 a 

derivative thereof) 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. Further, if the 

combined gross receipts of the taxpayer 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, the taxpayer 

will not be treated as a retailer.

A refiner is any person that directly or through a related person engages in the refining of 

crude oil in excess of 50,000 barrels per day on any day during the taxable year (sec. 

613A(d)(4)).

Percentage depletion for eligible taxpayers is allowed only for up to 1,000 barrels of 

average daily production of domestic crude oil or an equivalent amount of domestic natural gas 

 

gas properties, effective for taxable years beginning after 1990. The 100-percent net-income 

limitation for marginal wells has been suspended for taxable years beginning after December 31, 

1997, and before January 1, 2002.

5

 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.

6

 The Tax Reduction Act of 1975 (the "1975 Act") repealed the deduction for percentage 

depletion with respect to much oil and gas production.
4

(sec. 613A(c)).7 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.

In addition to independent producers and royalty owners, certain sales of natural gas 

under a fixed contract in effect on February 1, 1975, and certain natural gas from geopressured 

brine,8 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 company.

Before 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.9 The 1990 Act repealed 

the limitation on claiming percentage depletion on transferred properties effective for property 

transfers occurring after October 11, 1990.

Percentage depletion on marginal production

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 for the immediately preceding calendar year10 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 that 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 1999 (the most 

recent year for which a determination is available) was $15.56.11 Thus, the percentage depletion 

rate for production from marginal wells was increased to 19 percent for taxable years beginning 

in 2000.

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 

 

7

 As originally enacted, the depletable oil quantity was 2,000 barrels of average daily 

production. This was 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.

8

 This exception is limited to wells the drilling of which began between September 30, 

1978, and January 1, 1984.

9

 The exceptions to this rule included transfers at death, certain transfers to controlled 

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

10 This price is determined under the provisions of the nonconventional fuels production 

credit of section 29 of the Code.

11 IRS Notice 2000-23, 2000-17 I.R.B. 952.
5

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 taxpayer's taxable year begins (sec. 

613A(c)(6)(E)).12

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, a taxpayer makes the stripper well property determination 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 interest. 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. The deduction 

is allowed for the 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.

B. Intangible Drilling and Development Costs

In general

In general, costs that benefit future periods must be capitalized and recovered over those 

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 or working interest owner13 that pays or 

 

12 The amount of 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, its equivalent 

barrels produced would equal 12 barrels (i.e., 10 + (12,000 / 6,000)).

13 An operator or working interest owner is defined as a person that 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.
6

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 done by contractors under any form of contract, including a turnkey contract. 

Such work includes labor, fuel, repairs, hauling, and supplies which are used (1) in the drilling, 

shooting, and cleaning of wells; (2) in the clearing of ground, draining, road making, surveying, 

and geological works as necessary in preparation for the drilling of wells; and (3) 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 that have a salvage value (such as pipes and casings) or 

items that are part of the acquisition price of an interest in the property.14 They also do not 

include the cost to operators (1) payable only out of production or gross or net proceeds from 

production, if the amounts are depletable income to the recipient, and (2) amounts properly 

allocable to the cost of depreciable 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. In 

the case of a nonproductive well ("dry hole"), IDCs may be deducted at the election of the 

operator.15 For an integrated oil company 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)).16

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. This allows the taxpayer to reduce or eliminate the IDC adjustments or 

preferences under the alternative minimum tax.

The election to deduct IDCs applies only to those IDCs associated with domestic 

properties.17 For this purpose, the United States includes certain wells drilled offshore.18

 

14 Treas. Reg. sec. 1.612-4(a).

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

16 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, 1993-1 C.B. 50.

17 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 
7

Exemption from uniform capitalization rules

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 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 that are otherwise deductible under the Code (sec. 263A(c)(3)).

C. Geological and Geophysical Costs

In general

Geological and geophysical expenditures ("G&G costs") are costs incurred by a taxpayer 

for the purpose of obtaining and accumulating data that will serve as the basis for the acquisition 

and retention of mineral properties by taxpayers exploring for minerals. A key issue with respect 

to the tax treatment of such expenditures is whether or not they are capital in nature. Capital 

expenditures are not currently deductible as ordinary and necessary business expenses, but are 

allocated to the cost of the property.19

Courts have held that G&G costs are capital, and therefore are allocable to the cost of the 

property20 acquired or retained.21 The costs attributable to such exploration are allocable to the 

cost of the property acquired or retained. As described further below, IRS administrative rulings 

have provided further guidance regarding the definition and proper tax treatment of G&G costs.

 

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)).

18 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).

19 Under section 263, capital expenditures are defined generally as any amount paid for 

new buildings or for permanent improvements or betterments made to increase the value of any 

property or estate. Treasury regulations define capital expenditures 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. Treas. Reg. sec. 1.263(a)-1(b).

20 "Property" means an interest in a property as defined in section 614 of the Code, and 

includes an economic interest in a tract or parcel of land notwithstanding that a mineral deposit 

has not been established or proved at the time the costs are incurred.

21 See, e.g., Schermerhorn Oil Corporation v. Commissioner, 46 B.T.A. 151 (1942). 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.
8

Revenue Ruling 77-188

In Revenue Ruling 77-18822 (hereinafter referred to as the "1977 ruling"), the IRS 

provided guidance regarding the proper tax treatment of G&G costs. The ruling describes a 

typical geological and geophysical exploration program as containing the following elements:

• 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 (1) the size and topography of the project area to 

be explored, (2) the existing information available with respect to the project area and 

nearby areas, and (3) the quantity of equipment, the number of personnel, and the 

amount of money available to conduct a reasonable exploration program over the 

project area.

• 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. These techniques are designed to 

yield data that will afford a basis for identifying specific geological features with 

sufficient mineral potential to merit further exploration.

• 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.

• 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 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.

 

22 1977-1 C.B. 76.
9

If 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. The loss is claimed in the taxable year in 

which that particular project area is abandoned as a potential source of mineral production.

A taxpayer may acquire or retain a property within or adjacent to an area of interest, 

based on data obtained from a detailed survey that does not relate exclusively to any discrete 

property within a particular area of interest. Generally, under the 1977 ruling, the taxpayer 

allocates the entire amount of G&G costs to the acquired or retained property as a capital cost 

under section 263(a). If more than one property is acquired, 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 on the basis of comparative acreage.

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 83-105,23 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 

“abandonment as a potential source of mineral production."

D. Tax Credits

1. Credit for producing fuels from nonconventional sources

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.24 

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.

A facility that produces gas from biomass or produces liquid, gaseous, or solid synthetic 

fuels from coal (including lignite) placed in service by the taxpayer before July 1, 1998, pursuant 

to a written binding contract in effect before January 1, 1997, generally is treated as being placed 

in service before January 1, 1993. If a facility that qualifies for this binding contract exception 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.

For purposes of the section 29 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 

 

23 1983-2 C.B. 51.

24 A barrel-of-oil equivalent generally means that amount of the qualifying fuel that has a 

Btu (British thermal unit) content of 5.8 million.
10

lignite), including such fuels when used as feedstocks. 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 does not qualify for the credit.

The amount of the section 29 credit generally is adjusted by an inflation adjustment factor 

for the calendar year in which the sale occurs. The inflation adjustment factor for the 1999 

taxable year was 2.0013. Therefore, the inflation-adjusted amount of the credit for that year was 

$6.00 per barrel or barrel equivalent.25 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.26 For 1999 (the most recent year for which a 

determination is available), the inflation adjusted threshold for onset of the phase out was $47.03 

($23.50 x 2.0013), and the average wellhead price for 1999 was substantially lower than the 

indexed threshold.

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, under section 53, 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). The credit is limited to what would have 

been the regular tax liability but for the alternative minimum tax.

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 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.

 

25 IRS Notice 2000-23.

26

 Id.
11

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).27 For calendar year 2000, this amount 

was $33.84 ($28 X 1.2087).28 If the average unregulated wellhead price exceeds this amount, 

the credit would be reduced ratably over a $6 phase out 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);29 and (3) the cost of tertiary injectants with respect to which a 

deduction is allowable for the taxable year. Purchased and self-produced injectants are treated 

the same for purposes of the enhanced oil recovery credit.

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:30 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 EOR credit, immiscible nonhydrocarbon 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 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.

 

27 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.

28 The inflation adjustment factor for 2000 is 1.2087. IRS Notice 2000-51, 2000-38 

I.R.B. 291.

29 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).

30 See, section 212.78(c) of the June 1979 Department of Energy regulations.
12

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 ("AMTI") 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 AMTI 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 that 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

Since the provisions of the Energy Policy Act of 1992 became fully effective, there has 

been no AMT preference for oil and gas percentage depletion. Before enactment of that Act, oil 

and gas percentage depletion deductions in excess of the taxpayer's basis in the property were an 

AMT preference.

AMT treatment of IDCs

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 either to 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)).

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 of the 

amount that the taxpayer's AMTI would have been had the excess IDC preference not been 

repealed.

In addition, for purposes of computing the an integrated oil company'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)). The ACE preference does not 

apply to independent oil and gas producers since enactment of the Energy Policy Act of 1992.
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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).31 Thus, for example, an 

individual taxpayer generally 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. Suspended 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 in a 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 the activity. 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)).32 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 production 

credit and the enhanced oil recovery credit. However, if a taxpayer has net income from a 

working interest in an oil and gas property that is treated as not arising from a passive activity, 

then any tax credits attributable to the interest in that property are treated as credits not from a 

passive activity (and, thus, not subject to the passive activity credit limitation). The amount of 

such credits may not exceed the regular tax liability of the taxpayer for the taxable year, which is 

allocable to such net income.

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 long-term capital gains, however, the gains 

generally are subject to a maximum tax rate of 20 percent. There currently is no differential 

between the rates of taxation on capital gains and ordinary income in the case of corporate 

taxpayers.

 

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

certain closely held corporations.

32 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.
14

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 in a 

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.33 For this purpose, the term "section 

1254 property" means any property (within the meaning of sec. 614) if any IDCs are properly 

chargeable to such property or the adjusted basis of such property includes adjustments for 

depletion deductions.

H. Net Operating Losses

A net operating loss ("NOL") is generally the amount by which business deductions of a 

taxpayer exceed business gross income. In general, an NOL may be carried back two years and 

carried forward 20 years to offset taxable income in such years.34 A carryback of an NOL results 

in the refund of Federal income tax paid for the carryback year. A carryforward of an NOL 

reduces Federal income tax liability for the carryforward year. Special NOL carryback rules 

apply to (1) casualty and theft losses of individual taxpayers, (2) Presidentially declared disasters 

for taxpayers engaged in a farming business or a small business, (3) real estate investment trusts, 

(4) specified liability losses, (5) excess interest losses, and (6) farm losses.

 

33 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.

34 A taxpayer could elect to forgo the carryback of an NOL.
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II. EXCLUSION FOR CERTAIN ENERGY SUBSIDIES

PROVIDED BY A PUBLIC UTILITY

Present law35 provides an exclusion from the gross income of a customer of a public 

utility for the value of any subsidy provided by the utility for the purchase or installation of an 

energy conservation measure with respect to a dwelling unit (as defined by sec. 280A(f)(1)).36 

For purposes of section 136, an energy conservation measure is any installation or modification 

primarily designed to reduce consumption of electricity or natural gas or to improve the 

management of energy demand with respect to property.

Present law denies a deduction or credit to a taxpayer (or requires a reduction in the 

adjusted basis of property of a taxpayer in appropriate cases) for any expenditure to the extent 

that a subsidy related to the expenditure was excluded from the gross income of the taxpayer. 

The exclusion does not apply to payments made to or from a qualified cogeneration facility or a 

qualifying small power production facility pursuant to section 210 of the Public Utility 

Regulatory Policy Act of 1978.

 

35 Sec. 136, added by the Energy Policy Act of 1992.

36 For subsidies received after 1994 and before 1997, section 136 provided a partial 

exclusion from gross income for the value of any subsidy provided by a utility for the purchase 

or installation of an energy conservation measure with respect to property that was not a 

dwelling unit. The amount of the partial exclusion was 40 percent of the value for subsidies 

received in 1995, and 50 percent of the value for subsidies received in 1996. Sec. 136 would 

have provided an exclusion for 65 percent of the value for subsidies received after 1996 with 

respect to property other than a dwelling unit, but the exclusion with respect to property that was 

not a dwelling unit was repealed by P.L. 104-188.