DESCRIPTION OF PRESENT LAW RELATING TO FEDERAL TAX

PROVISIONS THAT AFFECT ENERGY 

PRODUCTION AND CONSERVATION

Scheduled for a Public Hearing

Before the

SUBCOMMITEE ON SELECT REVENUE MEASURES

of the

HOUSE COMMITTEE ON WAYS AND MEANS

on May 3, 2001

Prepared by the Staff

of the

JOINT COMMITTEE ON TAXATION

May 1, 2001

JCX-29-01
i

CONTENTS

Page

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

I. INCOME TAX RULES RELATING TO DOMESTIC OIL AND GAS

 OPERATIONS....................................................................................................... 2

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

B. Intangible Drilling and Development Costs....................................................... 6

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

D. Depreciation Rules Applicable to Oil and Gas Property................................... 10

E. Credit for Producing Fuels From Nonconventional Sources.............................. 13

F. Enhanced Oil Recovery Credit.......................................................................... 15

G. Alternative Minimum Tax.................................................................................. 16

H. Passive Activity Loss and Credit Rules............................................................. 17

I. Sales and Exchanges of Property Interests......................................................... 18

J. Net Operating Losses......................................................................................... 19

II. FOREIGN TAX RULES RELATING TO OIL AND GAS INCOME............... 20

III. CAPITAL CONSTRUCTION FUNDS FOR VESSELS................................... 21

IV. CREDITS FOR PRODUCING ELECTRICITY FROM CERTAIN 

RENEWABLE RESOURCES ............................................................................. 22

A. Production of Electricity from Wind, Closed Loop Biomass, and 

Poultry Litter...................................................................................................... 22

B. Investment in Solar and Geothermal Energy Property........................................ 22

V. INCOME TAX CREDIT AND PARTIAL EXCISE TAX EXEMPTION

 FOR CERTAIN RENEWABLE FUELS............................................................ 24

VI. SPECIAL COST RECOVERY PROVISIONS FOR ELECTRIC AND 

CLEAN-FUEL VEHICLES .................................................................................. 25

VII. EXCLUSION FOR CERTAIN ENERGY SUBSIDIES PROVIDED BY A

PUBLIC UTILITY................................................................................................. 26
1

INTRODUCTION

The Subcommittee on Select Revenue Measures of the House Committee on Ways and 

Means has scheduled a public hearing on May 3, 2001, on issues relating to the effect of Federal 

tax law on energy production and 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 

Present Law Relating to Federal Tax Provisions That Affect Energy Production and 

Conservation (JCX-29-01), May 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.

Cost depletion

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.

Percentage depletion and related income limitations

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)). 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 

 

2

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

3

 Sec. 613A.
3

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 

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. 

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)).4 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.5 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.

 

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.

5

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

depletion with respect to other oil and gas production.
4

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 

(sec. 613A(c)).6 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,7 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.8 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 year9 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 

 

6

 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.

7

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

1978, and January 1, 1984.

8

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

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

9

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

credit of section 29 of the Code.
5

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 $15.56.10 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 

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)).11

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.

 

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

11 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)).
6

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 owner12 that 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 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.13 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.14 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)).15

 

12 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.

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

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

15 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.
7

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

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.18

 

16 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)).

17 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).

18 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).
8

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

property

19 acquired or retained.20 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.

Revenue Ruling 77-188

In Revenue Ruling 77-18821 (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.

 

19 "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.

20 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.

21 1977-1 C.B. 76.
9

• 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.

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 83-105,22 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."

 

22 1983-2 C.B. 51.
10

D. Depreciation Rules Applicable to Oil and Gas Property

In general

Under present law, a taxpayer generally must capitalize the cost of property used in a 

trade or business and recover such cost over time through annual deductions for depreciation or 

amortization. Tangible property generally is depreciated under the Modified Accelerated Cost 

Recovery System (MACRS), which determines depreciation by applying specific recovery 

periods, placed-in-service conventions, and depreciation methods to the cost of various types of 

depreciable property (sec. 168). 

Personal property 

Classification of assets and recovery periods

 Personal property is classified under MACRS based on the property’s “class life” unless 

a different classification is specifically provided in section 168. The class life applicable for 

personal property is the asset guideline period (midpoint class life as of January 1, 1986). Based 

on the property’s classification, a recovery period is prescribed under MACRS. In general, there 

are six classes of recovery periods to which personal property can be assigned. For example, 

personal property that has a class life of four years or less has a recovery period of three years, 

whereas personal property with a class life greater than four years but less than 10 years has a 

recovery period of five years. The class lives and recovery periods for most property are 

contained in Rev. Proc. 87-5623 (as clarified and modified by Rev. Proc. 88-2224). 

Depreciation methods

The cost of personal property with a recovery period of ten years or less is recovered 

using the 200-percent declining balance method. The cost of personal property included in the 

15-year or 20-year class is recovered using the 150-percent declining balance method. Under 

both methods, a taxpayer switches to the straight-line method for the first taxable year for which 

using the straight line method will yield a larger deduction. In addition, a taxpayer may elect to 

use the straight-line method over the applicable MACRS recovery period or an alternative 

depreciation system based on class lives for property that is otherwise eligible for MACRS. 

Placed in service conventions

A half-year convention applies under which all personal property placed in service or 

disposed of during a taxable year is treated as placed in service or disposed of at the midpoint of 

such year. As a result, a half-year of depreciation is allowed for the first year the property is 

placed in service, regardless of when the property is placed in service during the year, and a halfyear of depreciation is allowed for the year in which property is disposed of or is otherwise 

retired from service. 

 

23 1987-2 C.B. 674.

24 1988-1 C.B. 785.
11

A mid-quarter convention is applied to all personal property if more than 40 percent of all 

depreciable personal property placed in service by a taxpayer during a taxable year is placed in 

service during the last three months of the taxable year. The mid-quarter convention treats all 

property placed in service during any quarter of a taxable year as placed in service on the 

midpoint of such quarter.

Real property

The cost of residential rental property is recovered using the straight-line method of 

depreciation, and a recovery period of 27.5 years. The cost of nonresidential real property is 

recovered using the straight-line method of depreciation, and a recovery period of 39 years.

Placed in service convention

In the case of both residential rental property and nonresidential real property, a midmonth convention applies. Under the mid-month convention, the depreciation allowance for the 

first year property is placed in service is based on the number of months the property was in 

service, and property placed in service at any time during a month is treated as having been 

placed in service in the middle of the month. 

Alternative depreciation system

An alternative depreciation system is provided for property that is predominantly foreignuse property, tax-exempt use property, financed tax-exempt bond financed property, or with 

respect to which a taxpayer elects to apply the alternative depreciation system. In these cases, 

depreciation allowances are computed under the alternative depreciation system, which provides 

for straight-line recovery and use of the placed in service conventions described above.

Unless specifically prescribed by section 168, the recovery period under the alternative 

system generally is equal to the property's class life (12 years for personal property with no ADR 

midpoint life, and 40 years for real property).

Rules Governing Cost Recovery Deductions for Oil and Gas Property

The applicable recovery periods for oil and gas property generally follow the MACRS 

rules described above with recovery periods ranging from seven years to 15 years. Rev. Proc. 

87-56, 1987-2 CB 674 (as clarified and modified by Rev. Proc. 88-22, 1988-1 CB 785) 

prescribes recovery periods for oil & gas property used in the following activities. 

Offshore drilling 

Depreciable assets used in offshore drilling are assigned a five-year recovery period. 

Includes assets used in offshore drilling for oil and gas such as floating, self-propelled, and other 

drilling vessels, barges, platforms, and drilling equipment, and support vessels such as tenders, 

barges, towboats, and crewboats. Excludes oil and gas production assets.
12

Drilling of oil and gas wells

Depreciable assets used in drilling of oil and gas wells are assigned a five-year recovery 

period. Includes assets used in the drilling of onshore oil and gas wells and the provision of 

geophysical and other exploration services, and the provision of such oil and gas field services as 

chemical treatment, plugging and abandoning of wells, and cementing or perforating well 

casings. Does not include assets used in the performance of any of these activities and services 

by integrated petroleum and natural gas producers for their own account. 

Exploration for, and production of petroleum and natural gas deposits

Depreciable assets used in the exploration for, and production of petroleum and natural 

gas deposits are assigned a seven-year recovery period. Includes assets used by petroleum and 

natural gas producers for drilling wells and production of petroleum and natural gas, including 

gathering pipelines and related storage facilities. Also includes petroleum and natural gas 

offshore transportation facilities used by producers and others, consisting of platforms (other 

than offshore drilling platforms), compression or pumping equipment, and gathering and 

transmission lines to the first onshore transshipment facility. The assets used in the first onshore 

transshipment facility are also included and consist of separation equipment (used for separation 

of natural gas, liquids, and solids), compression or pumping equipment (other than equipment 

included in the category Natural Gas Production Plant), and liquid holding or storage facilities 

(other than those included in the category Liquified Natural Gas Plant). Does not include support 

vessels.

Natural gas gathering lines owned by non-producers of natural gas could be described in 

this category or, alternatively, in pipeline transportation (discussed below). The uncertainty 

regarding the appropriate recovery period has resulted in litigation between taxpayers and the 

IRS. The 10th Circuit Court of Appeals held that natural gas gathering lines owned by nonproducers fall within the scope of this category (i.e., seven-year recovery period).25

Petroleum refining

Depreciable assets used in petroleum refining are assigned a 10-year general recovery 

period. Includes assets used for the distillation, fractionation, and catalytic cracking of crude 

petroleum into gasoline and its other components. 

Pipeline transportation

Depreciable assets used in pipeline transportation are assigned 15-year general recovery 

period. Includes assets used in the private, commercial, and contract carrying of petroleum, gas, 

and other products by means of pipes and conveyors. The trunk lines and related storage 

facilities of integrated petroleum and natural gas producers are included in this class. Excludes 

 

25 Duke Energy v. Commissioner, 172 F.3d 1255 (10th Cir. 1999), rev.’g 109 TC 416 

(1997). See also True v. Commissioner, 97-2 U.S. Tax Cas. (CCH) par. 50,946 (D. Wyo. 1997).
13

initial clearing and grading improvements as specified in Rev. Rul. 72-40326, but includes all 

other related land improvements.

Substitute natural gas-coal gasification

Depreciable assets used in substitute natural gas-coal gasification are assigned 10-year 

general recovery period. Includes assets used in the manufacture and production of pipelinequality gas from coal using the basic Lurgi process with advanced methanation. Includes all 

process plant equipment and structures used in this coal gasification process and all utility assets 

such as cooling systems, water supply and treatment facilities, and assets used in production and 

distribution of electricity and steam for use by the taxpayer in a gasification plant and attendant 

coal mining but not for assets used in the production and distribution of electricity and steam for 

sale to others. Also includes all other related land improvements. Does not include assets used in 

the direct mining and treatment of coal prior to the gasification process itself.

Natural gas production plant

Depreciable assets used in a natural gas production plant are assigned seven-year general 

recovery period.

Gas utility trunk pipelines and related storage facilities

Depreciable assets used in gas utility trunk pipelines and related storage facilities are 

assigned 15-year general recovery period. Excludes initial clearing and grading land 

improvements as specified in Rev. Rul. 72-40327.

Liquified natural gas plant

Depreciable assets used in a liquified natural gas plant are assigned 15-year general 

recovery period. Includes assets used in the liquefaction, storage, and regasification of natural 

gas including loading and unloading connections, instrumentation equipment and controls, 

pumps, vaporizers and odorizers, tanks, and related land improvements. Also includes pipeline 

interconnections with gas transmission lines and distribution systems and marine terminal 

facilities.

E. 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.28 

Fuels qualifying for the credit must be produced domestically from a well drilled, or a facility 

 

26 1972-2 C.B. 102.

27 Id.

28 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.
14

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 

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.29 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.30 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.

 

29 IRS Notice 2000-23.

30

 Id.
15

F. 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 one taxable 

years and carried forward 20 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.

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).31 For calendar year 2000, this amount 

was $33.84 ($28 X 1.2087).32 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);33 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 

 

31 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.

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

I.R.B. 291.

33 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).
16

the following nine methods:34 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.

G. 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.

 

34 See, section 212.78(c) of the June 1979 Department of Energy regulations.
17

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.

AMT treatment of depreciation

Depreciation on property placed in service after 1986 and before January 1, 1999, must 

be computed by using the generally longer class lives prescribed by the alternative depreciation 

system of section 168(g) and either (a) the straight-line method in the case of property subject to 

the straight-line method under the regular tax or (b) the 150-percent declining balance method in 

the case of other property. The Taxpayer Relief Act of 1997 provided that AMT depreciation on 

property placed in service after December 31, 1998, is computed by using the regular tax 

recovery periods and the AMT methods (i.e., straight line or 150% declining balance) described 

in the previous sentence. For property placed in service after 1980 and before 1987, the amount 

by which accelerated depreciation exceeds straight-line depreciation on real and leased personal 

property is treated as an AMT preference.

H. 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).35 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 

 

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

certain closely held corporations.
18

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)).36 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.

I. 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.

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 

 

36 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.
19

basis of the property, is characterized as ordinary income.37 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.

J. 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.38 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.

 

37 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.

38 A taxpayer could elect to forgo the carryback of an NOL.
20

II. FOREIGN TAX RULES RELATING TO OIL AND GAS INCOME

In general, the United States taxes the U.S. 10-percent shareholders of a controlled 

foreign corporation (“CFC”) on their pro rata shares of certain income of the CFC (referred to as 

"subpart F income"), without regard to whether the income is distributed to the shareholders.39

Subpart F income includes, among other things, foreign base company oil-related income. 

Foreign base company oil-related income generally includes all oil-related income derived from 

foreign sources (as defined in sec. 907(c)(2) and (3) and described below) other than income 

derived from a source within a foreign country in connection with either (1) oil or gas which was 

extracted from a well located in that foreign country, or (2) oil, gas, or a primary product of oil or 

gas which is sold by the foreign corporation or a related person for use or consumption within 

that foreign country, or is loaded in that country on a vessel or aircraft as fuel for that vessel or 

aircraft (sec. 954(g)). An exception is available for any foreign corporation that, together with 

related persons, does not constitute a large oil producer.

A credit against U.S. tax on foreign-source income generally is allowed for foreign taxes 

paid or accrued (or deemed paid). The amount of foreign tax credits that a taxpayer may claim is 

subject to a limitation that prevents taxpayers from using foreign tax credits to offset U.S. tax on 

U.S.-source income. The foreign tax credit limitation is calculated on an overall basis and

separately for specific categories of income.

Special foreign tax credit rules apply in the case of foreign oil and gas income. Under a 

special limitation, taxes on foreign oil and gas extraction income are creditable only to the extent 

that they do not exceed a specified amount (e.g., 35 percent of such income in the case of a 

corporation) (sec. 907(a)). For this purpose, foreign oil and gas extraction income is income 

derived from foreign sources from the extraction of minerals from oil or gas wells or the sale or 

exchange of assets used by the taxpayer in such extraction. A taxpayer must have excess 

limitation under the special rules applicable to foreign extraction taxes and excess limitation 

under the general foreign tax credit provisions in order to utilize excess foreign oil and gas 

extraction taxes in a carryback or carryforward year.

In the case of taxes paid or accrued to any foreign country with respect to certain foreign 

oil-related income, discriminatory foreign taxes are not treated as creditable foreign taxes (sec. 

907(b)). For this purpose, foreign oil-related income is income derived from foreign sources 

from (1) the processing of minerals extracted by the taxpayer or any other person from oil or gas 

wells into their primary products, (2) the transportation of such minerals or primary products, (3) 

the distribution or sale of such minerals or primary products, (4) the disposition of assets used by 

the taxpayer in such processing, transportation, or distributions or sales, or (5) the performance 

of any other related service (sec. 907(c)(2)).

 

39 In general, a foreign corporation is a CFC if U.S. 10-percent shareholders own more 

than 50 percent of such corporation’s stock (measured by vote or value) (sec. 957).
21

III. CAPITAL CONSTRUCTION FUNDS FOR VESSELS

In determining taxable income for regular tax purposes, a qualified taxpayer who owns or 

leases a qualified vessel (an "agreement vessel") is allowed a deduction for certain amounts 

contributed to a fund established under section 607 of the Merchant Marine Act of 1936 (a 

"capital construction fund") (sec. 7518). In addition, the investment earnings on amounts 

contributed to a capital construction fund are excluded from gross income for regular tax 

purposes.

If a withdrawal from a capital construction fund is used to acquire, construct, or 

reconstruct a qualified vessel, the amount withdrawn generally is not included in gross income 

and the basis of the qualified vessel generally is reduced by the amount withdrawn to the extent 

attributable to amounts previously deducted or excluded from income. In the case of any other 

withdrawal from a capital construction fund, the amount withdrawn generally is included in 

gross income to the extent attributable to amounts previously deducted or excluded from income 

and interest on the tax liability attributable to such inclusion generally must be paid from the date 

of the deduction or exclusion.

Under section 607(k) of the Merchant Marine Act, 1936, as in effect as of the date of 

enactment of the Tax Reform Act of 1986, a qualified vessel generally is a vessel constructed or 

reconstructed in the United States (the "U.S.-build requirement") and documented under the laws 

of the United States (the "U.S.-flag requirement"). In addition, the person maintaining the capital 

construction fund must agree with the Secretary of Commerce or the Secretary of Transportation 

that the vessel will be operated in the United States foreign trade, Great Lakes trade, or 

noncontiguous domestic trade or in the fisheries of the United States.
22

IV. CREDIT FOR PRODUCING ELECTRICITY FROM CERTAIN

RENEWABLE RESOURCES

A. Production of Electricity from Wind,

Closed Loop Biomass, and Poultry Litter

An income tax credit is allowed for the production of electricity from either qualified 

wind energy, qualified “closed-loop” biomass, or qualified poultry waste facilities (sec. 45).

The credit applies to electricity produced by a wind energy facility placed in service after 

December 31, 1993, and before January 1, 2002, to electricity produced by a closed-loop 

biomass facility placed in service after December 31, 1992, and before January 1, 2002, and to a 

poultry waste facility placed in service after December 31, 1999, and before January 1, 2002. 

The credit is allowable for production during the 10-year period after a facility is originally 

placed in service. In order to claim the credit, a taxpayer must own the facility and sell the 

electricity produced by the facility to an unrelated party. In the case of a poultry waste facility, 

the taxpayer may claim the credit as a lessee/operator of a facility owned by a governmental unit.

Closed-loop biomass is plant matter, where the plants are grown for the sole purpose of 

being used to generate electricity. It does not include the use of waste materials (including, but 

not limited to, scrap wood, manure, and municipal or agricultural waste). The credit also is not 

available to taxpayers who use standing timber to produce electricity. Poultry waste means 

poultry manure and litter, including wood shavings, straw, rice hulls, and other bedding material 

for the disposition of manure.

The credit for electricity produced from wind, closed-loop biomass, or poultry waste is a 

component of the general business credit (sec. 38(b)(8)). 

B. Investment in Solar and Geothermal Energy Property

A nonrefundable, 10-percent business energy credit is allowed for the cost of new 

property that is equipment (1) that uses solar energy to generate electricity, to heat or cool a 

structure, or to provide solar process heat, or (2) used to produce, distribute, or use energy 

derived from a geothermal deposit, but only, in the case of electricity generated by geothermal 

power, up to the electric transmission stage.

The business energy tax credits are components of the general business credit (sec. 

38(b)(1)). The business energy tax credits, when combined with all other components of the 

general business credit, generally may not exceed for any taxable year the excess of the 

taxpayer's net income tax over the greater of (1) 25 percent of net regular tax liability above 

$25,000 or (2) the tentative minimum tax. For credits arising in taxable years beginning after 

December 31, 1997, an unused general business credit generally may be carried back one year 

and carried forward 20 years (sec. 39).

A taxpayer may exclude from income the value of any subsidy provided by a public 

utility for the purchase or installation of an energy conservation measure. An energy 

conservation measure means any installation or modification primarily designed to reduce 
23

consumption of electricity or natural gas or to improve the management of energy demand with 

respect to a dwelling unit (sec. 136).
24

V. INCOME TAX CREDIT AND PARTIAL EXCISE TAX EXEMPTION

FOR CERTAIN RENEWABLE FUELS

In general

Ethanol and methanol derived from renewable sources (e.g., biomass) are eligible for an 

income tax credit (the "alcohol fuels credit") equal under present law to 53 cents per gallon 

(ethanol) and 60 cents per gallon (methanol). These tax credits are provided to blenders of the 

alcohol with other taxable fuels, or to retail sellers of unblended alcohol fuels. Typically, ethanol 

is blended with gasoline subject to Highway Trust Fund excise tax to produce "gasohol." The 

53-cents-per-gallon income tax credit rate is scheduled to decline to 51 cents per gallon during 

the period 2003 through 2007. The credit is scheduled to expire after December 31, 2007.

The alcohol fuels tax credit may be claimed either against income tax or as a reduction in 

Federal excise tax imposed on gasoline or other highway motor fuels. Most of the benefit of the 

alcohol fuels credit is claimed through the excise tax system.

Small producer credit

In addition to the general alcohol fuels credit, small producers of ethanol are entitled to a 

10-cents-per-gallon income tax credit. Eligible small producers are defined as persons whose 

production capacity does not exceed 30 million gallons and whose annual production does not 

exceed 15 million gallons. This credit is scheduled to expire after December 31, 2007.
25

VI. SPECIAL COST RECOVERY PROVISIONS FOR ELECTRIC

AND CLEAN-FUEL VEHICLES

A 10-percent tax credit is provided for the cost of a qualified electric vehicle, up to a 

maximum credit of $4,000 (sec. 30). A qualified electric vehicle is a motor vehicle that is 

powered primarily by an electric motor drawing current from rechargeable batteries, fuel cells, or 

other portable sources of electrical current, the original use of which commences with the

taxpayer, and that is acquired for the use by the taxpayer and not for resale. The full amount of 

the credit is available for purchases prior to 2002. The credit phases down in the years 2002 

through 2004, and is unavailable for purchases after December 31, 2004.

Certain costs of qualified clean-fuel vehicle property and clean-fuel vehicle refueling 

property may be expensed and deducted when such property is placed in service (sec. 179A). 

Qualified clean-fuel vehicle property includes motor vehicles that use certain clean-burning fuels 

(natural gas, liquefied natural gas, liquefied petroleum gas, hydrogen, electricity and any other 

fuel at least 85 percent of which is methanol, ethanol, any other alcohol or ether. The maximum 

amount of the deduction is $50,000 for a truck or van with a gross vehicle weight over 26,000 

pounds or a bus with seating capacities of at least 20 adults; $5,000 in the case of a truck or van 

with a gross vehicle weight between 10,000 and 26,000 pounds; and $2,000 in the case of any 

other motor vehicle. Qualified electric vehicles do not qualify for the clean-fuel vehicle 

deduction. 

Clean-fuel vehicle refueling property comprises property for the storage or dispensing of 

a clean-burning fuel, if the storage or dispensing is the point at which the fuel is delivered into 

the fuel tank of a motor vehicle. Clean-fuel vehicle refueling property also includes property for 

the recharging of electric vehicles, but only if the property is located at a point where the electric 

vehicle is recharged. Up to $100,000 of such property at each location owned by the taxpayer 

may be expensed with respect to that location. 

The deduction phases down in the years 2002 through 2004, and is unavailable for 

purchases after December 31, 2004.
26

VII. EXCLUSION FOR CERTAIN ENERGY SUBSIDIES PROVIDED

BY A PUBLIC UTILITY

Present law40 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)).41 

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.

 

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

41 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.