DESCRIPTION OF H.R. 1531,

THE “ENERGY TAX POLICY ACT OF 2003”

Scheduled for Markup

by the

HOUSE COMMITTEE ON WAYS AND MEANS

on April 3, 2003

Prepared by

the Staff of the

JOINT COMMITTEE ON TAXATION

April 2, 2003

JCX-30-03
i

CONTENTS

Page

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

I. CONSERVATION...................................................................................................................... 2

A. Tax Credit for Residential Solar Energy............................................................................. 2

B. Extension and Modification of the Section 45 Electricity Production Credit .................... 4

C. Tax Incentives for Fuel Cells.............................................................................................. 6

D. Modifications of Provisions Relating to Electric Vehicles and Clean-Fuel Vehicles........ 7

E. Credit for Energy Efficiency Improvements to Existing Homes........................................ 8

F. Business Credit for Construction of New Energy-Efficient Homes................................... 9

G. Energy Credit for Combined Heat and Power System Property....................................... 11

H. Allow Nonbusiness Energy Credits Against the Alternative Minimum Tax ................... 13

I. Repeal Certain Excise Taxes on Rail Diesel Fuel and Inland Waterway Barge Fuels..... 14

J. Btu-Based Rate for Diesel-Water Fuel Emulsion............................................................. 15

II. RELIABILITY......................................................................................................................... 16

A. Natural Gas Gathering Lines Treated as Seven-Year Property ........................................ 16

B. Natural Gas Distribution Lines Treated as Fifteen-Year Property ................................... 18

C. Transmission Property Treated as Fifteen-Year Property ................................................ 19

D. Expensing of Capital Costs Incurred and Credit for Production in Complying with

Environmental Protection Agency Sulfur Regulations..................................................... 20

E. Determination of Small Refiner Exception to Oil Depletion Deduction.......................... 21

F. Sales or Dispositions to Implement Federal Energy Regulatory Commission or State

Electric Restructuring Policy ............................................................................................ 22

G. Modification to Special Rules for Nuclear Decommissioning Costs ............................... 24

H. Treatment of Certain Income of Electric Cooperatives.................................................... 28
Page

ii

I. Exempt Certain Prepayments for Natural Gas From Tax-Exempt Bond Arbitrage

Rules ................................................................................................................................. 32

J. Prepayment of Premium Liability for Coal Miner Health Benefits.................................. 35

III. PRODUCTION....................................................................................................................... 37

A. Tax Credit for Oil and Gas Production From Marginal Wells ......................................... 37

B. Temporary Suspension of Limitation Based on 65 Percent of Taxable Income and

Extension of Suspension of Taxable Income Limit With Respect to Marginal

Production......................................................................................................................... 38

C. Amortization of Delay Rental Payments.......................................................................... 41

D. Amortization of Geological and Geophysical Expenditures ............................................ 42

E. Extension and Modification of Credit for Producing Fuel From a Non-Conventional

Source ............................................................................................................................... 45

F. Allow Business Energy Credits Against the Alternative Minimum Tax.......................... 47

G. Repeal Alternative Minimum Tax Intangible Drilling Costs ("IDC") Preference for

Oil and Gas Production..................................................................................................... 48

H. Allow Enhanced Oil Recovery Credit Against the Alternative Minimum Tax................ 49
1

INTRODUCTION

The House Committee on Ways and Means has scheduled a markup on April 3, 2003, on 

H.R. 1531, the “Energy Tax Policy Act of 2003.” This document,1 prepared by the staff of the 

Joint Committee on Taxation, provides a description of the “Energy Policy Tax Act of 2003.”

 

1

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

H.R. 1531, the “Energy Tax Policy Act of 2003” (JCX-30-03), April 2, 2003.
2

I. CONSERVATION

A. Tax Credit for Residential Solar Energy

Present Law

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 

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

respect to a dwelling unit (sec. 136).

There is no present-law personal tax credit for residential solar energy property.

Description of Proposal

The proposal provides a personal tax credit for the purchase of qualified photovoltaic 

property and qualified solar water heating property that is used exclusively for purposes other 

than heating swimming pools and hot tubs. The credit is equal to 15 percent of qualified 

investment up to a maximum credit of $2,000 for solar water heating property and $2,000 for 

rooftop photovoltaic property. This credit is nonrefundable, and the depreciable basis of the 

property is reduced by the amount of the credit.

Qualifying solar water heating property means an expenditure for property to heat water 

for use in a dwelling unit located in the United States and used as a residence if at least half of 

the energy used by such property for such purpose is derived from the sun. Qualified 

photovoltaic property is property that uses solar energy to generate electricity for use in a 

dwelling unit. Expenditures for labor costs allocable to onsite preparation, assembly, or original 

installation of property eligible for the credit are eligible expenditures.

Certain equipment safety requirements need to be met to qualify for the credit. Special 

proration rules apply in the case of jointly owned property, condominiums, and tenantstockholders in cooperative housing corporations. 
3

Effective Date

The credit applies to purchases in taxable years ending after December 31, 2003 and 

before January 1, 2007 (January 1, 2009 in the case of qualified photovoltaic property).
4

B. Extension and Modification of the Section 45 Electricity Production Credit

Present Law

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 

amount of the credit is 1.5 cents per kilowatt hour (indexed for inflation) of electricity produced. 

The amount of the credit was 1.8 cents per kilowatt hour for 2002. The credit is reduced for 

grants, tax-exempt bonds, subsidized energy financing, and other credits.

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

December 31, 1993, and before January 1, 2004, to electricity produced by a closed-loop 

biomass facility placed in service after December 31, 1992, and before January 1, 2004, and to a 

poultry waste facility placed in service after December 31, 1999, and before January 1, 2004. 

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 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)). The credit, 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). To coordinate the carryback with the 

period of application for this credit, the credit for electricity produced from closed-loop biomass 

facilities may not be carried back to a tax year ending before 1993 and the credit for electricity 

produced from wind energy may not be carried back to a tax year ending before 1994 (sec. 39).

Description of Proposal

The proposal extends the placed in service date for wind facilities and closed-loop 

biomass facilities to facilities placed in service after December 31, 1993 (December 31, 1992 in 

the case of closed-loop biomass facilities) and before January 1, 2007.

The proposal also defines three new qualifying facilities: open-loop biomass facilities, 

landfill gas facilities, and trash-to-energy facilities. Open-loop biomass is defined as any solid, 

nonhazardous, cellulosic waste material which is segregated from other waste materials and 

which is derived from any of forest-related resources, solid wood waste materials, or agricultural 
5

sources. Eligible forest-related resources are defined as mill as residues, precommercial 

thinnings, slash, and brush. Solid wood waste materials include waste pallets, crates, dunnage, 

manufacturing and construction wood wastes (other than pressure-treated, chemically-treated, or 

painted wood wastes), and landscape or right-of-way tree trimmings. Agricultural sources 

include orchard tree crops, vineyard, grain, legumes, sugar, and other crop by-products or 

residues. However, qualifying open-loop biomass does not include municipal solid waste 

(garbage) or paper that is commonly recycled. Landfill gas is defined as methane gas derived 

from the biodegradation of municipal solid waste. Trash-to-energy facilities are facilities that

burn municipal solid waste (garbage) to produce steam to drive a turbine for the production of 

electricity. Qualifying open-loop biomass facilities and qualifying landfill gas facilities include 

facilities used to produce electricity placed in service before January 1, 2007. Qualifying trashto-energy facilities include facilities placed in service after the date of enactment and before 

January 1, 2007.

In the case of qualifying open-loop biomass facilities and qualifying landfill gas facilities 

placed in service on or before the date of enactment, the taxpayer may claim the section 45 

production credit for only five years, commencing on the date of enactment. In the case of 

qualifying open-loop biomass facilities and qualifying landfill gas facilities placed in service on 

or before the date of enactment, the taxpayer may claim two-thirds of the otherwise allowable 

credit for electricity produced at the facility. In the case of qualifying open-loop biomass 

facilities originally placed in service on or before the date of enactment, a lessee or operator may 

claim the credit in lieu of the owner of the qualifying facility.

In the case of qualifying open-loop biomass facilities, the reduction in credit by reason of 

grants, tax-exempt bonds, subsidized energy financing, and other credits cannot exceed 50 

percent.

No facility that previously claimed or currently claims credit under section 29 of the 

Code is a qualifying facility for purposes of section 45. 

Effective Date

The proposal is effective for electricity sold from qualifying facilities after the date of 

enactment.
6

C. Tax Incentives for Fuel Cells

Present Law

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 

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

respect to a dwelling unit (sec. 136).

There is no present-law credit for fuel cell power plant property.

Description of Proposal

The proposal provides a 10 percent credit for the purchase of qualified fuel cell power 

plants for businesses and individuals. A qualified fuel cell power plant is an integrated system 

comprised of a fuel cell stack assembly and associated balance of plant components that converts 

a fuel into electricity using electrochemical means, and which has an electricity-only generation 

efficiency of greater than 30 percent. The credit may not exceed $500 for each 0.5 kilowatt of 

capacity. For individuals, the qualified fuel cell power plant must be installed on or in 

connection with a dwelling unit located in the United States and used by the taxpayer as a 

principal residence. The credit is nonrefundable. The taxpayer’s basis in the property is reduced 

by the amount of the credit claimed.

Effective Date

The credit for businesses applies to property placed in service after December 31, 2003 

and before January 1, 2007, under rules similar to rules of section 48(m) of the Internal Revenue 

Code of 1986 (as in effect on the day before the date of enactment of the Revenue Reconciliation 

Act of 1990). The credit for individuals applies to expenditures made after December 31, 2003 

and before January 1, 2007.
7

D. Modifications of Provisions Relating to Electric Vehicles

and Clean-Fuel Vehicles

Present Law

Electric 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 2004 

through 2006, and is unavailable for purchases after December 31, 2006.

Clean-fuel vehicles

Certain costs of qualified clean-fuel vehicle 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. The deduction phases down in the 

years 2004 through 2006, and is unavailable for purchases after December 31, 2006.

Description of Proposal

Electric vehicles

The proposal repeals the phased down reduction in the credit for years 2004, 2005, and 

2006. Thus, the proposal provides that a taxpayer could claim the full 10-percent credit (up to a 

$4,000) maximum for the purchase of qualified electric vehicles before January 1, 2007. 

Clean-fuel vehicles

The proposal repeals the phased down reduction in the allowable deduction for years 

2004, 2005, and 2006. Thus, the proposal provides that a taxpayer could claim a full deduction 

for allowable costs of clean-fuel vehicles purchased before January 1, 2007. 

Effective Date

The proposal is effective on the date of enactment. 
8

E. Credit for Energy Efficiency Improvements to Existing Homes

Present Law

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 

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

respect to a dwelling unit (sec. 136). 

There is no present law credit for energy efficiency improvements to existing homes.

Description of Proposal

The proposal provides a 20-percent nonrefundable credit for the purchase of qualified 

energy efficiency improvements. The maximum credit for a taxpayer with respect to the same 

dwelling for all taxable years is $2,000. A qualified energy efficiency improvement is any energy 

efficiency building envelope component that is certified (in the case of expenditures that exceed 

$1,000) to meet or exceed the prescriptive criteria for such a component established by the 2000 

International Energy Conservation Code (or, in the case of metal roofs with appropriate 

pigmented coatings, meets the Energy Star program requirements), and (1) is installed in or on a 

dwelling located in the United States; (2) is owned and used by the taxpayer as the taxpayer’s 

principal residence; (3) the original use of which commences with the taxpayer; and (4) such 

component reasonably can be expected to remain in use for at least five years. 

Building envelope components are: (1) insulation materials or systems which are 

specifically and primarily designed to reduce the heat loss or gain for a dwelling; (2) exterior 

windows (including skylights) and doors; and (3) metal roofs with appropriate pigmented coating 

which are specifically and primarily designed to reduce the heat loss or gain for a dwelling.

The taxpayer’s basis in the property is reduced by the amount of the credit. Special rules 

apply in the case of condominiums and tenant-stockholders in cooperative housing corporations.

Effective Date

The credit is effective for qualified energy efficiency improvements installed after 

December 31, 2003 and before January 1, 2007.
9

F. Business Credit for Construction of New Energy-Efficient Homes

Present Law

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 

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

respect to a dwelling unit (sec. 136).

There is no present-law credit for the construction of new energy-efficient homes.

Description of Proposal

The proposal provides a credit to an eligible contractor (up to $2,000 per dwelling) of an 

amount equal to the aggregate adjusted bases of all energy-efficient property installed in a 

qualified new energy-efficient home during construction. 

The eligible contractor is the person who constructs the home, or in the case of a 

manufactured home, the producer of such home. Energy efficiency property is any energyefficient building envelope component (insulation materials, exterior windows and doors, metal 

roofs with appropriate pigmented coatings) and any energy-efficient heating or cooling 

appliance.

To qualify as an energy-efficient new home, the home must be: (1) a dwelling located in 

the United States; (2) the principal residence of the person who acquires the dwelling from the 

eligible contractor; (3) certified to have a level of annual heating and cooling energy 

consumption that is at least 30 percent below the annual level of heating and cooling energy 

consumption of a comparable dwelling constructed in accordance with the standards of the 2000 

International Energy Conservation Code; and (4) with respect to the building envelope alone, 

certified to have a level of annual heating and cooling energy consumption that is 10 percent 

below the annual level of heating and cooling energy consumption of a comparable dwelling 
10

constructed in accordance with the standards of the 2000 International Energy Conservation 

Code.

Effective Date

The credit applies to homes whose construction is substantially completed after 

December 31, 2003, and which are purchased during the period beginning on January 1, 2004, 

and ending on December 31, 2006.
11

G. Energy Credit for Combined Heat and Power System Property

Present Law

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 

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

respect to a dwelling unit (sec. 136).

There is no present-law credit for combined heat and power (“CHP”) property.

Description of Proposal

The proposal provides a 10 percent credit for the purchase of combined heat and power 

property. 

CHP property is property: (1) which uses the same energy source for the simultaneous or 

sequential generation of electrical power, mechanical shaft power, or both, in combination with 

the generation of steam or other forms of useful thermal energy (including heating and cooling 

applications); (2) which has an electrical capacity of more than 50 kilowatts or a mechanical 

energy capacity of more than 67 horsepower or an equivalent combination of electrical and 

mechanical energy capacities; (3) which produces at least 20 percent of its total useful energy in 

the form of thermal energy and at least 20 percent in the form of electrical or mechanical power 

(or a combination thereof); and (4) the energy efficiency percentage of which exceeds 60 percent 

(70 percent in the case of a system with an electrical capacity in excess of 50 megawatts or a 

mechanical energy capacity in excess of 67,000 horsepower, or an equivalent combination of 

electrical and mechanical capacities.)

CHP property does not include property used to transport the energy source to the 

generating facility or to distribute energy produced by the facility.
12

If a taxpayer is allowed a credit for CHP property, and the property would ordinarily have 

a depreciation class life of 15 years or less, the depreciation period for the property is treated as 

having a 22-year class life. The present-law carry back rules of the general business credit 

generally apply except that no credits attributable to combined heat and power property may be 

carried back before the effective date of this provision.

Effective Date

The credit applies to property placed in service after December 31, 2003 and before 

January 1, 2007.
13

H. Allow Nonbusiness Energy Credits Against the Alternative Minimum Tax

Present Law

Present law imposes an alternative minimum tax on individuals in an amount equal to the 

excess of the tentative minimum tax over the regular tax liability. The tentative minimum tax is 

an amount equal to specified rates of tax imposed on the excess of the alternative minimum 

taxable income over an exemption amount.

Generally, for taxable years beginning after December 31, 2003, nonrefundable personal 

credits may not exceed the excess of the regular tax liability over the tentative minimum tax.

Description of Proposal

The proposal allows the personal energy credits added by the bill to offset both the 

regular tax and the alternative minimum tax. 

Effective Date

The proposal applies to taxable years beginning after December 31, 2003.
14

I. Repeal Certain Excise Taxes on Rail Diesel Fuel

and Inland Waterway Barge Fuels

Present Law

Under present law, diesel fuel used in trains is subject to a 4.4-cents-per gallon excise tax. 

Revenues from 4.3 cents per gallon of this excise tax are retained in the General Fund of the 

Treasury. The remaining 0.1 cent per gallon is deposited in the Leaking Underground Storage 

Tank (“LUST”) Trust Fund. 

Similarly, fuel used in barges operating on the designated inland waterways system is 

subject to a 4.3-cents-per-gallon General Fund excise tax. This tax is in addition to the 20.1-

cents-per-gallon tax rates that are imposed on fuels used in these barges to fund the Inland 

Waterways Trust Fund and the Leaking Underground Storage Tank Trust Fund.

In both cases, the 4.3-cents-per-gallon excise tax rates are permanent. The LUST Trust 

Fund tax is scheduled to expire after March 31, 2005.

Description of Proposal

The 4.3-cents-per-gallon General Fund excise tax rate on diesel fuel used in trains and 

fuels used in barges operating on the designated inland waterways system is repealed. The 0.1 

cent per gallon for the Leaking Underground Storage Tank (“LUST”) Trust Fund is unchanged 

by the proposal.

Effective Date

The proposal is effective on October 1, 2003.
15

J. Btu-Based Rate for Diesel-Water Fuel Emulsion 

Present Law

A 24.3-cents-per-gallon excise tax is imposed on diesel fuel to finance the Highway Trust 

Fund. Gasoline and most special motor fuels are subject to tax at 18.3 cents per gallon for the 

Trust Fund. The statutory rate for certain special motor fuels is determined on an energy 

equivalent basis, as follows:

Liquefied petroleum gas (propane) 13.6 cents per gallon

Liquefied natural gas 11.9 cents per gallon

Methanol derived from petroleum or natural gas 9.15 cents per gallon

Compressed natural gas 48.54 cents per MCF

No special tax rate is provided for diesel fuel blended with water to form a diesel-water 

fuel emulsion.

Description of Proposal

A special tax rate of 19.7 cents per gallon is provided for diesel fuel blended with water 

into a diesel-water fuel emulsion to reflect the reduced Btu content per gallon resulting from the 

water. Emulsion fuels eligible for the special rate consists of not more than 86 percent diesel 

(and other minor chemical additives to enhance combustion) and at least 14 percent water. 

Anyone who separates the diesel fuel from the diesel-water fuel emulsion on which a reduced 

rate of tax was imposed is treated as a refiner of the fuel and is liable for the difference between 

the amount of tax on the latest removal of the separated fuel and the amount of tax that was 

imposed upon the pre-mixture removal.

Effective Date

The proposal applies to fuels removed after September 30, 2003.
16

II. RELIABILITY

A. Natural Gas Gathering Lines Treated as Seven-Year Property

Present Law

The applicable recovery period for assets placed in service under the Modified 

Accelerated Cost Recovery System is based on the “class life of the property.” The class lives of 

assets placed in service after 1986 are generally set forth in Revenue Procedure 87-56.2 Revenue 

Procedure 87-56 includes two asset classes that could describe natural gas gathering lines owned 

by nonproducers of natural gas. Asset class 46.0, describing pipeline transportation, provides a 

class life of 22 years and a recovery period of 15 years. Asset class 13.2, describing assets used 

in the exploration for and production of petroleum and natural gas deposits, provides a class life 

of 14 years and a depreciation recovery period of seven years. The uncertainty regarding the 

appropriate recovery period of natural gas gathering lines has resulted in litigation between 

taxpayers and the IRS. The 10th Circuit Court of Appeals held that natural gas gathering lines 

owned by nonproducers falls within the scope of Asset class 13.2 (i.e., seven-year recovery 

period).3 More recently, the Tax Court and the U.S. District Court for the Eastern District of 

Michigan, Southern Division, held that natural gas gathering lines owned by nonproducers falls 

within the scope of Asset class 46.0 (i.e., 15-year recovery period).4

Description of Proposal

The proposal establishes a statutory seven-year recovery period and a class life of 10 

years for natural gas gathering lines. In addition, the proposal provides that there would be no 

adjustment to the allowable amount of depreciation for purposes of computing a taxpayer’s 

alternative minimum taxable income with respect to such property. A natural gas gathering line 

is defined to include any pipe, equipment, and appurtenance that is (1) determined to be a 

gathering line by the Federal Energy Regulatory Commission, or (2) used to deliver natural gas 

from the wellhead or a common point to the point at which such gas first reaches (a) a gas 

processing plant, (b) an interconnection with an interstate transmission line, (c) an 

interconnection with an intrastate transmission line, or (d) a direct interconnection with a local 

distribution company, a gas storage facility, or an industrial consumer.

 

2

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

3

 Duke Energy v. Commissioner, 172 F.3d 1255 (10th Cir. 1999), rev’g 109 T.C. 416 

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

4

 Clajon Gas Co., L.P. v. Commissioner, 119 T.C. 197 (2002) and Saginaw Bay Pipeline 

Co. v. United States, 124 F. Supp. 2d 465 (E.D. Mich. 2001).
17

Effective Date

The proposal is effective for property placed in service after the date of enactment. No 

inference is intended as to the proper treatment of natural gas gathering lines placed in service 

before the date of enactment.
18

B. Natural Gas Distribution Lines Treated as Fifteen-Year Property

Present Law

The applicable recovery period for assets placed in service under the Modified 

Accelerated Cost Recovery System is based on the “class life of the property.” The class lives of 

assets placed in service after 1986 are generally set forth in Revenue Procedure 87-56.5 Natural 

gas distribution pipelines are assigned a 20-year recovery period and a class life of 35 years. 

Description of Proposal

The proposal establishes a statutory 15-year recovery period and a class life of 20 years 

for natural gas distribution lines. In addition, the proposal provides that there would be no 

adjustment to the allowable amount of depreciation for purposes of computing a taxpayer’s 

alternative minimum taxable income with respect to such property. 

Effective Date

The proposal is effective for property placed in service after the date of enactment. 

 

5

 1987-2 C.B. 674 (as clarified and modified by Rev. Proc. 88-22, 1988-1 C.B. 785). 
19

C. Transmission Property Treated as Fifteen-Year Property

Present Law

The applicable recovery period for assets placed in service under the Modified 

Accelerated Cost Recovery System is based on the “class life of the property.” The class lives of 

assets placed in service after 1986 are generally set forth in Revenue Procedure 87-56.6 Assets 

used in the transmission and distribution of electricity for sale and related land improvements are 

assigned a 20-year recovery period and a class life of 30 years. 

Description of Proposal

The proposal establishes a statutory 15-year recovery period and a class life of 20 years 

for certain assets used in the transmission of electricity for sale and related land improvements. 

For purposes of the proposal, section 1245 property used in the transmission of electricity for 

sale at 69 kilovolts and above will qualify for the new recovery period. In addition, the proposal 

provides that there would be no adjustment to the allowable amount of depreciation for purposes 

of computing a taxpayer’s alternative minimum taxable income with respect to such property. 

Effective Date

The proposal is effective for property placed in service after the date of enactment. 

 

6

 1987-2 C.B. 674 (as clarified and modified by Rev. Proc. 88-22, 1988-1 C.B. 785). 
20

D. Expensing of Capital Costs Incurred and Credit for Production in Complying

with Environmental Protection Agency Sulfur Regulations

Present Law

Taxpayers generally may recover the costs of investments in refinery property through 

annual depreciation deductions. Present law does not provide a credit for the production of lowsulfur diesel fuel.

Description of Proposal

The proposal permits small business refiners to claim an immediate deduction (i.e., 

expensing) for up to 75 percent of the costs paid or incurred for the purpose of complying with 

the Highway Diesel Fuel Sulfur Control Requirements of the Environmental Protection Agency. 

In addition, the proposal provides that a small business refiner may claim credit equal to five 

cents per gallon for each gallon of low sulfur diesel fuel produced during the taxable year. The 

total production credit claimed by the taxpayer is limited to 25 percent of the capital costs 

incurred to come into compliance with the EPA diesel fuel requirements. The taxpayer’s basis in 

such property is reduced by the amount of production credit claimed. 

For these purposes a small business refiner is a taxpayer who within the business of 

refining petroleum products engages not more than 1,500 persons directly in refining on business 

days and has less that 205,000 barrels per day of total domestic refinery capacity.7 The credit 

and deduction phase out for refiners with capacity in excess of 155,000 barrels per day.

Effective Date

The proposal would be effective for expenses paid or incurred after March 31, 2003.

 

7

 The refining capacities of all persons that are part of a related group are aggregated for 

purposes of this definition. 
21

E. Determination of Small Refiner Exception to Oil Depletion Deduction

Present Law

Present law classifies oil and gas producers as independent producers or integrated 

companies. The Code provides numerous special tax rules for operations by independent 

producers. One such rule allows independent producers to claim percentage depletion 

deductions rather than deducting the costs of their asset, a producing well, based on actual 

production from the well (i.e., cost depletion).

A producer is an independent producer only if its refining and retail operations are 

relatively small. For example, an independent producer may not have refining operations the 

runs from which exceed 50,000 barrels on any day in the taxable year during which independent 

producer status is claimed.

Description of Proposal

The proposal increases the current 50,000 barrel per day limitation to 75,000. In 

addition, the proposal changes the refinery limitation on claiming independent producer status 

from a limit based on actual daily production to a limit based on average daily production for the 

taxable year. Accordingly, the average daily refinery run for the taxable year may not exceed 

75,000 barrels. For this purpose, the taxpayer calculates average daily production by dividing 

total production for the taxable year by the total number of days in the taxable year. 

Effective Date

The proposal is effective for taxable years beginning after December 31, 2003.
22

F. Sales or Dispositions to Implement Federal Energy Regulatory Commission

or State Electric Restructuring Policy

Present Law

Generally, a taxpayer recognizes gain to the extent the sales price (and any other 

consideration received) exceeds the seller’s basis in the property. The recognized gain is subject 

to current income tax unless the gain is deferred or not recognized under a special tax provision. 

Description of Proposal

The proposal permits a taxpayer to elect to recognize gain from a qualifying electric 

transmission transaction ratably over an eight-year period beginning in the year of sale if the 

amount realized from such sale is used to purchase exempt utility property within the applicable 

period8 (the “reinvestment property”). If the amount realized exceeds the amount used to 

purchase reinvestment property, any realized gain shall be recognized to the extent of such 

excess in the year of the qualifying electric transmission transaction. Any remaining realized 

gain is recognized ratably over the eight-year period. 

A qualifying electric transmission transaction is the sale or other disposition of property 

used by the taxpayer in the trade or business of providing electric transmission services, or an 

ownership interest in such an entity, to an independent transmission company prior to January 1, 

2007. In general, an independent transmission company is defined as: (1) an independent 

transmission provider9 approved by the FERC; (2) a person (i) who the FERC determines under 

section 203 of the Federal Power Act (or by declaratory order) is not a “market participant” and 

(ii) whose transmission facilities are placed under the operational control of a FERC-approved 

independent transmission provider before the close of the period specified in such authorization, 

but not later than January 1, 2007; or (3) in the case of facilities subject to the jurisdiction of the 

Public Utility Commission of Texas, (i) a person which is approved by that Commission as 

consistent with Texas State law regarding an independent transmission organization, or (ii) a 

political subdivision, or affiliate thereof, whose transmission facilities are under the operational 

control of an organization described in (i).

Exempt utility property is defined as: (1) property used in the trade or business of 

generating, transmitting, distributing, or selling electricity or producing, transmitting, 

distributing, or selling natural gas, or (2) stock in a controlled corporation whose principal trade 

or business consists of the activities described in (1).

 

8

 The applicable period for a taxpayer to reinvest the proceeds is four years after the 

close of the taxable year in which the qualifying electric transmission transaction occurs.

9

 For example, a regional transmission organization, an independent system operator, or 

and independent transmission company. 
23

If a taxpayer is a member of an affiliated group of corporations filing a consolidated 

return, the proposal permits the reinvestment property to be purchased by any member of the 

affiliated group (in lieu of the taxpayer). 

If a taxpayer elects the provisions of the proposal, then the statutory period for the 

assessment of any deficiency, for any taxable year in which any part of the gain eligible for the 

proposal is realized, attributable to such gain shall not expire prior to the expiration of three 

years from the date the Secretary of the Treasury is notified by the taxpayer of the reinvestment 

property or an intention not to reinvest. 

A taxpayer electing the provisions of the proposal is required to attach a statement to that 

effect in the tax return for the taxable year in which the transaction takes place in the manner as 

the Secretary shall prescribe. The election shall be binding for that taxable year and all 

subsequent taxable years. 10 In addition, a taxpayer electing the provisions of the proposal is 

required to attach a statement that identifies the reinvestment property in the manner as the 

Secretary shall prescribe.

Effective Date

The proposal is effective for transactions occurring after the date of enactment.

 

10 The proposal also provides that the installment sale rules shall not apply to any 

qualifying electric transmission transaction that elects the provisions of this proposal.
24

G. Modification to Special Rules for Nuclear Decommissioning Costs

Present Law

Overview

Special rules dealing with nuclear decommissioning reserve funds were adopted by 

Congress in the Deficit Reduction Act of 1984 (“1984 Act”), when tax issues regarding the time 

value of money were addressed generally. Under general tax accounting rules, a deduction for 

accrual basis taxpayers is deferred until there is economic performance for the item for which the 

deduction is claimed. However, the 1984 Act contains an exception under which a taxpayer 

responsible for nuclear powerplant decommissioning may elect to deduct contributions made to a 

qualified nuclear decommissioning fund for future decommissioning costs. Taxpayers who do 

not elect this provision are subject to general tax accounting rules.

Qualified nuclear decommissioning fund

A qualified nuclear decommissioning fund (a “qualified fund”) is a segregated fund 

established by a taxpayer that is used exclusively for the payment of decommissioning costs, 

taxes on fund income, management costs of the fund, and for making investments. The income 

of the fund is taxed at a reduced rate of 20 percent for taxable years beginning after December 

31, 1995.11

Contributions to a qualified fund are deductible in the year made to the extent that these 

amounts were collected as part of the cost of service to ratepayers (the “cost of service 

requirement”).12 Funds withdrawn by the taxpayer to pay for decommissioning costs are 

included in the taxpayer’s income, but the taxpayer also is entitled to a deduction for 

decommissioning costs as economic performance for such costs occurs.

Accumulations in a qualified fund are limited to the amount required to fund 

decommissioning costs of a nuclear powerplant for the period during which the qualified fund is 

in existence (generally post-1984 decommissioning costs of a nuclear powerplant). For this 

purpose, decommissioning costs are considered to accrue ratably over a nuclear powerplant’s 

estimated useful life. In order to prevent accumulations of funds over the remaining life of a 

nuclear powerplant in excess of those required to pay future decommissioning costs of such 

 

11 As originally enacted in 1984, a qualified fund paid tax on its earnings at the top 

corporate rate and, as a result, there was no present-value tax benefit of making deductible 

contributions to a qualified fund. Also, as originally enacted, the funds in the trust could be 

invested only in certain low risk investments. Subsequent amendments to the provision have 

reduced the rate of tax on a qualified fund to 20 percent and removed the restrictions on the types 

of permitted investments that a qualified fund can make.

12 Taxpayers are required to include in gross income customer charges for 

decommissioning costs (sec. 88).
25

nuclear powerplant and to ensure that contributions to a qualified fund are not deducted more 

rapidly than level funding (taking into account an appropriate discount rate), taxpayers must 

obtain a ruling from the IRS to establish the maximum annual contribution that may be made to a 

qualified fund (the “ruling amount”). In certain instances (e.g., change in estimates), a taxpayer 

is required to obtain a new ruling amount to reflect updated information.

A qualified fund may be transferred in connection with the sale, exchange or other 

transfer of the nuclear powerplant to which it relates. If the transferee is a regulated public utility 

and meets certain other requirements, the transfer will be treated as a nontaxable transaction. No 

gain or loss will be recognized on the transfer of the qualified fund and the transferee will take 

the transferor’s basis in the fund.13 The transferee is required to obtain a new ruling amount from 

the IRS or accept a discretionary determination by the IRS.14

Nonqualified nuclear decommissioning funds

Federal and State regulators may require utilities to set aside funds for nuclear 

decommissioning costs in excess of the amount allowed as a deductible contribution to a 

qualified fund. In addition, taxpayers may have set aside funds prior to the effective date of the 

qualified fund rules.15 The treatment of amounts set aside for decommissioning costs prior to 

1984 varies. Some taxpayers may have received no tax benefit while others may have deducted 

such amounts or excluded such amounts from income. Since 1984, taxpayers have been required 

to include in gross income customer charges for decommissioning costs (sec. 88), and a 

deduction has not been allowed for amounts set aside to pay for decommissioning costs except 

through the use of a qualified fund. Income earned in a nonqualified fund is taxable to the fund’s 

owner as it is earned. 

Description of Proposal

Repeal of cost of service requirement 

The proposal repeals the cost of service requirement for deductible contributions to a 

nuclear decommissioning fund. Thus, all taxpayers, including unregulated taxpayers, are 

allowed a deduction for amounts contributed to a qualified fund. 

Permit contributions to a qualified fund for pre-1984 decommissioning costs

The proposal also repeals the limitation that a qualified fund only accumulate an amount 

sufficient to pay for a nuclear powerplant’s decommissioning costs incurred during the period 

that the qualified fund is in existence (generally post-1984 decommissioning costs). Thus, any 

 

13 Treas. reg. sec. 1.468A-6.

14 Treas. reg. sec. 1.468A-6(f).

15 These funds are generally referred to as “nonqualified funds.”
26

taxpayer is permitted to accumulate an amount sufficient to cover the present value of 100 

percent of a nuclear powerplant’s estimated decommissioning costs in a qualified fund. The 

proposal does not change the requirement that contributions to a qualified fund not be deducted 

more rapidly than level funding. 

Exception to ruling amount for certain decommissioning costs 

The proposal permits a taxpayer to make contributions to a qualified fund in excess of the 

ruling amount in one circumstance. Specifically, a taxpayer is permitted to contribute up to the 

present value of the amount required to fund a nuclear powerplant’s decommissioning costs 

which, under present law, is not permitted to be accumulated in a qualified fund (generally pre1984 decommissioning costs).16 It is anticipated that an amount that is permitted to be 

contributed under this special rule shall be determined using the estimate of total 

decommissioning costs used for purposes of determining the taxpayer’s most recent ruling 

amount. Any amount transferred to the qualified fund under this special rule that has not 

previously been deducted, or excluded from gross income is allowed as a deduction over the 

remaining useful life of the nuclear powerplant.17 If a qualified fund that has received amounts 

under this rule is transferred to another person, the transferor will be permitted a deduction for 

any remaining deductible amounts at the time of transfer. 

Contributions to a qualified fund after useful life of powerplant

The proposal also allows deductible contributions to a qualified fund subsequent to the 

end of a nuclear powerplant’s estimated useful life. Such payments are permitted to the extent 

they do not cause the assets of the qualified fund to exceed the present value of the taxpayer’s 

allocable share (current or former) of the nuclear decommissioning costs of such nuclear 

powerplant.

Clarify treatment of transfers of qualified funds

The proposal clarifies the Federal income tax treatment of the transfer of a qualified fund. 

No gain or loss would be recognized to the transferor or the transferee as a result of the transfer 

 

16 The ability to transfer property into a qualified fund under this special rule is available 

only to the extent the taxpayer has not obtained a new ruling amount incorporating the repeal of 

the limitation that a qualified fund only accumulate an amount sufficient to pay for 

decommissioning costs of a nuclear powerplant incurred during the period that the fund is in 

existence (generally post 1984 decommissioning costs).

17 A taxpayer recognizes no gain or loss on the contribution of property to a qualified 

fund under this special rule. The qualified fund will take a transferred (carryover) basis in such 

property. Correspondingly, a taxpayer’s deduction (over the estimated life of the nuclear 

powerplant) is to be based on the adjusted tax basis of the property contributed rather than the 

fair market value of such property.
27

of a qualified fund in connection with the transfer of the power plant with respect to which such 

fund was established. 

Effective Date

The proposal is effective for taxable years beginning after December 31, 2003. 
28

H. Treatment of Certain Income of Electric Cooperatives

Present Law

In general

Under present law, an entity must be operated on a cooperative basis in order to be 

treated as a cooperative for Federal income tax purposes. Although not defined by statute or 

regulation, the two principal criteria for determining whether an entity is operating on a 

cooperative basis are: (1) ownership of the cooperative by persons who patronize the 

cooperative; and (2) return of earnings to patrons in proportion to their patronage. The IRS 

requires that cooperatives must operate under the following principles: (1) subordination of 

capital in control over the cooperative undertaking and in ownership of the financial benefits 

from the cooperative; (2) democratic control by the members of the cooperative; (3) vesting in 

and allocation among the members of all excess of operating revenues over the expenses 

incurred to generate revenues in proportion to their participation in the cooperative (patronage); 

and (4) operation at cost (not operating for profit or below cost).18

In general, cooperative members are those who participate in the management of the 

cooperative and who share in patronage capital. As described below, income from the sale of 

electric energy by an electric cooperative may be member or non-member income to the 

cooperative, depending on the membership status of the purchaser. A municipal corporation 

may be a member of a cooperative.

For Federal income tax purposes, a cooperative generally computes its income as if it 

were a taxable corporation, with one exception--the cooperative may exclude from its taxable 

income distributions of patronage dividends. In general, patronage dividends are the profits of 

the cooperative that are rebated to its patrons pursuant to a pre-existing obligation of the 

cooperative to do so. The rebate must be made in some equitable fashion on the basis of the 

quantity or value of business done with the cooperative.

Except for tax-exempt farmers' cooperatives, cooperatives that are subject to the 

cooperative tax rules of subchapter T of the Code (sec. 1381, et seq.) are permitted a deduction 

for patronage dividends from their taxable income only to the extent of net income that is derived 

from transactions with patrons who are members of the cooperative (sec. 1382). The availability 

of such deductions from taxable income has the effect of allowing the cooperative to be treated 

like a conduit with respect to profits derived from transactions with patrons who are members of 

the cooperative.

Cooperatives that qualify as tax-exempt farmers’ cooperatives are permitted to exclude 

patronage dividends from their taxable income to the extent of all net income, including net 

income that is derived from transactions with patrons who are not members of the cooperative, 

 

18

 Announcement 96-24, Proposed Examination Guidelines Regarding Rural Electric

Cooperatives, 1996-16 I.R.B. 35.
29

provided the value of transactions with patrons who are not members of the cooperative does not 

exceed the value of transactions with patrons who are members of the cooperative (sec. 521).

Taxation of electric cooperatives exempt from subchapter T

In general, the cooperative tax rules of subchapter T apply to any corporation operating 

on a cooperative basis (except mutual savings banks, insurance companies, other tax-exempt 

organizations, and certain utilities), including tax-exempt farmers' cooperatives (described in sec. 

521(b)). However, subchapter T does not apply to an organization that is “engaged in furnishing 

electric energy, or providing telephone service, to persons in rural areas" (sec. 1381(a)(2)(C)). 

Instead, electric cooperatives are taxed under rules that were generally applicable to cooperatives 

prior to the enactment of subchapter T in 1962. Under these rules, an electric cooperative can 

exclude patronage dividends from taxable income to the extent of all net income of the 

cooperative, including net income derived from transactions with patrons who are not members 

of the cooperative.19

Tax exemption of rural electric cooperatives

Section 501(c)(12) provides an income tax exemption for rural electric cooperatives if at 

least 85 percent of the cooperative's income consists of amounts collected from members for the 

sole purpose of meeting losses and expenses of providing service to its members. The IRS takes

the position that rural electric cooperatives also must comply with the fundamental cooperative 

principles described above in order to qualify for tax exemption under section 501(c)(12).20 The 

85-percent test is determined without taking into account any income from qualified pole rentals 

and cancellation of indebtedness income from the prepayment of a loan under sections 306A, 

306B, or 311 of the Rural Electrification Act of 1936 (as in effect on January 1, 1987). The 

exclusion for cancellation of indebtedness income applies to such income arising in 1987, 1988, 

or 1989 on debt that either originated with, or is guaranteed by, the Federal Government. Rural 

electric cooperatives generally are subject to the tax on unrelated trade or business income under 

section 511.

Description of Proposal

Treatment of income from open access transactions

The proposal provides that income received or accrued by a rural electric cooperative 

(other than income received or accrued directly or indirectly from a member of the cooperative) 

from the provision or sale of electric energy transmission services or ancillary services on a 

nondiscriminatory open access basis under an independent transmission provider agreement 

approved by FERC (including an agreement providing for the transfer of control--but not 

 

19

 See Rev. Rul. 83-135, 1983-2 C.B. 149.

20 Rev. Rul. 72-36, 1972-1 C.B. 151.
30

ownership--of transmission facilities)21 is excluded in determining whether a rural electric 

cooperative satisfies the 85-percent test for tax exemption under section 501(c)(12).

For purposes of the 85-percent test, the proposal also provides that income received or 

accrued by a rural electric cooperative is treated as an amount collected from members for the 

sole purpose of meeting losses and expenses if the income is received or accrued indirectly from 

a member of the cooperative, provided that such income is derived from a “like organization” 

activity of the cooperative under present law.22

Treatment of income from nuclear decommissioning transactions

The proposal provides that income received or accrued by a rural electric cooperative 

from any “nuclear decommissioning transaction” also is excluded in determining whether a rural 

electric cooperative satisfies the 85-percent test for tax exemption under section 501(c)(12). The 

term “nuclear decommissioning transaction” is defined as--

(1) any transfer into a trust, fund, or instrument established to pay any nuclear 

decommissioning costs if the transfer is in connection with the transfer of the 

cooperative’s interest in a nuclear powerplant or nuclear powerplant unit;

(2) any distribution from a trust, fund, or instrument established to pay any nuclear 

decommissioning costs; or

(3) any earnings from a trust, fund, or instrument established to pay any nuclear 

decommissioning costs.

Treatment of income from asset exchange or conversion transactions

The proposal provides that gain realized by a tax-exempt rural electric cooperative from a 

voluntary exchange or involuntary conversion of certain property is excluded in determining 

whether a rural electric cooperative satisfies the 85-percent test for tax exemption under section 

501(c)(12). This proposal only applies to the extent that: (1) the gain would qualify for deferred 

recognition under section 1031 (relating to exchanges of property held for productive use or 

investment) or section 1033 (relating to involuntary conversions); and (2) the replacement 

property that is acquired by the cooperative pursuant to section 1031 or section 1033 (as the case 

may be) constitutes property that is used, or to be used, for the purpose of generating, 

transmitting, distributing, or selling electricity or methane-based natural gas.

 

21 Under this proposal, references to FERC are treated as including references to the 

Public Utility Commission of Texas.

22

 See, e.g., Rev. Rul. 2002-54, 2002-37 I.R.B. 527; Rev. Rul. 83-170, 1983-2 C.B. 97; 

Rev. Rul. 65-201, 1965-2 C.B. 170
31

Treatment of income from load loss transactions

Tax-exempt rural electric cooperatives–The proposal provides that income received or 

accrued by a tax-exempt rural electric cooperative from a “load loss transaction” is treated under 

501(c)(12) as income collected from members for the sole purpose of meeting losses and 

expenses of providing service to its members. Therefore, income from load loss transactions is 

treated as member income in determining whether a rural electric cooperative satisfies the 85-

percent test for tax exemption under section 501(c)(12). The proposal also provides that income 

from load loss transactions does not cause a tax-exempt electric cooperative to fail to be treated 

for Federal income tax purposes as a mutual or cooperative company under the fundamental 

cooperative principles described above.

The term “load loss transaction” is generally defined as any wholesale or retail sale of 

electric energy (other than to a member of the cooperative) to the extent that the aggregate 

amount of such sales during a seven-year period beginning with the “start-up year” does not 

exceed the reduction in the amount of sales of electric energy during such period by the 

cooperative to members. The “start-up year” is defined as the calendar year which includes the 

date of enactment of this provision or, if later, at the election of the cooperative: (1) the first year 

that the cooperative offers nondiscriminatory open access; or (2) the first year in which at least 

10 percent of the cooperative’s sales of electric energy are to patrons who are not members of the 

cooperative.

The proposal also excludes income received or accrued by rural electric cooperatives 

from load loss transactions from the tax on unrelated trade or business income.

Taxable electric cooperatives–The proposal provides that the receipt or accrual of income 

from load loss transactions by taxable electric cooperatives is treated as income from patrons 

who are members of the cooperative. Thus, income from a load loss transaction is excludible 

from the taxable income of a taxable electric cooperative if the cooperative distributes such 

income pursuant to a pre-existing contract to distribute the income to a patron who is not a 

member of the cooperative. The proposal also provides that income from load loss transactions 

does not cause a taxable electric cooperative to fail to be treated for Federal income tax purposes 

as a mutual or cooperative company under the fundamental cooperative principles described 

above.

Effective Date

This proposal is effective for taxable years beginning after the date of enactment.
32

I. Exempt Certain Prepayments for Natural Gas

From Tax-Exempt Bond Arbitrage Rules

Present Law

Interest on bonds issued by States or local governments to finance activities carried out or 

paid for by those entities generally is exempt from income tax.23 Restrictions are imposed on the 

ability of States or local governments to invest the proceeds of these bonds for profit (the 

"arbitrage restrictions"). One such restriction limits the use of bond proceeds to acquire 

"investment-type property." The term investment-type property includes the acquisition of 

property in a transaction involving a prepayment. A prepayment can produce prohibited 

arbitrage profits when the discount received for prepaying the costs exceeds the yield on the taxexempt bonds. In general, prohibited prepayments include all prepayments that are not 

customary in an industry by both beneficiaries of tax-exempt bonds and other persons using 

taxable financing for the same transaction.

On April 17, 2002, the Department of the Treasury issued proposed regulations regarding 

arbitrage and private activity restrictions applicable to tax-exempt bonds issued by State and 

local governments. The proposed regulations add an exception to the definition of investmenttype property for certain natural gas prepayments that are made by or for one or more utilities 

that are owned by a governmental person.24 The exception applies if at least 95 percent of the 

natural gas purchased with the prepayment is to be (1) consumed by retail customers in the 

service area of a municipal gas utility, or (2) used to produce electricity that will be furnished to 

retain customers that a municipal electric utility is obligated to serve under State or Federal law. 

An obligation that arises solely because of a contract is not an obligation to serve under State or 

Federal law. For this purpose, the service area of a municipal gas utility is defined as (1) any 

area throughout which the municipal utility provided (at all times during the five-year period 

ending on the issue date) gas transmission or distribution service, and any area that is contiguous 

to such an area, or (2) any area where the municipal utility is obligated under State or Federal 

law to provide gas distribution services as provided in such law. Issuers may apply principles 

similar to the rules governing private use to cure a violation of the 95 percent requirement.25

A prepayment will not fail to meet the requirements for prepaid gas contracts by reason 

of any commodity swap contract that may be entered into between the issuer and an unrelated 

party (other than the gas supplier), or between the gas supplier and an unrelated party (other than 

the issuer), so long as each swap contract is an independent contract. A swap contract is an 

independent contract if it is not dependent on performance by any person (other than the party to 

the swap contract) under another contract (for example, a gas contract or another swap contract). 

 

23 Sec. 103.

24 Prop. Treas. Reg. sec. 1.148-1(e)(2)(ii).

25 See Treas. Reg. 1.141-12.
33

A natural gas commodity swap contract will not fail to be an independent contract solely because 

the swap contract may terminate in the event of a failure of a gas supplier to deliver gas for 

which the swap contract is a hedge.26 The Commissioner may, by published guidance, set forth 

additional circumstances in which a prepayment does not give rise to investment-type property.

Description of Proposal

In general 

The proposal creates a safe harbor exception to the general rule that tax-exempt bondfinanced prepayments violate the arbitrage restrictions. The term “investment type property” 

does not include a prepayment under a qualified natural gas supply contract. The proposal also 

provides such prepayments are not treated as private loans for purposes of the private business 

tests. 

Under the proposal, a prepayment financed with tax-exempt bond proceeds for the 

purpose of obtaining a supply of natural gas for service area customers of a governmental utility 

is not treated as the acquisition of investment-type property. A contract is a qualified natural gas 

contract if the volume of natural gas secured for any year covered by the prepayment does not 

exceed the sum of (1) the average annual natural gas purchased (other than for resale) by 

customers of the utility within the service area of the utility (“retail natural gas consumption”) 

during the testing period, and (2) the amount of natural gas that is needed to fuel transportation 

of the natural gas to the governmental utility. The testing period is the 5-calendar-year period 

immediately preceding the calendar year in which the bonds are issued. A retail customer is one 

who does not purchase natural gas for resale. Natural gas used to generate electricity by a 

governmental utility is counted as retail natural gas consumption if the electricity was sold to 

retail customers within the service area of the governmental electric utility. 

Adjustments

The volume of gas permitted by the general rule is reduced by natural gas otherwise 

available on the date of issuance. Specifically, the amount of natural gas permitted to be 

acquired under a qualified natural gas contract for any period is to be reduced by natural gas held 

by the utility on the date of issuance of the bonds and natural gas that the utility has a right to 

acquire for the prepayment period (determined as of the date of issuance).27 For purposes of the 

 

26 Internal Revenue Service, Clarification of Proposed Regulations Relating to TaxExempt Bonds Issued by State or Local Governments, Notice 2002-52, 2002-30 IRB 1 (July 03, 

2002).

27 For example, natural gas otherwise available on the date the bonds are issued includes 

supply covered by other prepayment contracts for the period, and supply held in storage or 

subject to an option to purchase by such utility that is available for retail natural gas consumption 

during the period covered by the prepayment. It does not include supply that could be purchased 

on the open market during the prepayment period.
34

preceding sentence, applicable share means, with respect to any period, the natural gas allocable 

to such period if the gas were allocated ratably over the period to which the prepayment relates. 

For purposes of the safe harbor, if after the close of the testing period and before the issue 

date of the bonds (1) the government utility enters into a contract to supply natural gas (other 

than for resale) for a commercial person for use at a property within the service area of such 

utility and (2) the gas consumption for such property was not included in the testing period or the 

ratable amount of natural gas to be supplied under the contract is significantly greater than the 

ratable amount of gas supplied to such property during the testing period, then the amount of gas 

permitted to be purchased may be increased to accommodate the contract. 

The average annual retail natural gas consumption calculation for purposes of the safe 

harbor, however, is not to exceed the annual amount of natural gas reasonably expected to be 

purchased (other than for resale) by persons who are located within the service area of such 

utility and who, as of the date of issuance of the issue, are customers of such utility.

Intentional acts

The safe harbor does not apply if the utility engages in intentional acts to render (1) the 

volume of natural gas covered by the prepayment to be in excess of that needed for retail natural 

gas consumption, and (2) the amount of natural gas that is needed to fuel transportation of the 

natural gas to the governmental utility.

Definition of service area

Service area is defined as (1) any area throughout which the governmental utility 

provided (at all times during the testing period) in the case of a natural gas utility, natural gas 

transmission or distribution service, or in the case of an electric utility, electric distribution 

service; (2) limited areas contiguous to such areas, and (3) any area recognized as the service 

area of the governmental utility under State or Federal law. Contiguous areas are limited to any 

area within a county contiguous to the area described in (1) in which retail customers of the 

utility are located if such area is not also served by another utility providing the same service.

Ruling request for higher prepayment amounts

Upon written request, the Secretary may allow an issuer to prepay for an amount of gas 

greater than that allowed by the safe harbor based on objective evidence of growth in gas 

consumption or population that demonstrates that amount permitted by the exception is 

insufficient.

Effective Date

The proposal is effective for obligations issued after the date of enactment.
35

J. Prepayment of Premium Liability for Coal Miner Health Benefits

Present Law

The United Mine Workers of America (“UMWA”) Combined Benefit Fund was 

established by the Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”) to assume 

responsibility of payments for medical care expenses of retired miners and their dependents who 

were eligible for heath care from the private 1950 and 1974 UMWA Benefit Plans. The 

Combined Benefit Fund is financed by assessments on current and former signatories to labor 

agreements with the UMWA, past transfers from an overfunded United Mine Workers pension 

fund, and transfers from the Abandoned Mine Reclamation Fund. The Social Security 

Administration is responsible for assigning eligible retired miners and their dependents to current 

and former signatories to labor agreements with the UMWA and calculating annual contributions 

to be paid by each such signatory for each beneficiary assigned to the signatory. The Coal Act 

uses the term “assigned operator” to refer to the signatory to which liability for a particular 

beneficiary of the Combined Benefit Fund has been assigned. Under the Coal Act, related 

persons to signatories to the relevant labor agreements may have liability for premium payments. 

In addition, successors to assigned operators may also have such liability.

Description of Proposal

The proposal allows assigned operators that are members of a controlled group of 

corporations to prepay their premium liability to the Combined Benefit Fund. Under the 

proposal, only the common parent (and no other person) is liable for the premiums of an 

assigned operator which is a member of the parent’s controlled group if: (1) the assigned 

operator makes a payment to the Combined Benefit Fund meeting certain requirements; (2) the 

parent is jointly and severally liable for any premium which would otherwise be required to be 

paid by the operator; and (3) the parent provides certain security.

Under the proposal, in order for the relief from liability to apply to the assigned operator: 

(1) the payment by the assigned operator (described in (1) above) must be no less than the 

present value of the total premium liability of the assigned operator, as determined by the 

operator’s enrolled actuary, using actuarial methods and assumptions each of which is reasonable 

and which are reasonable in the aggregate (as determined by such actuary); (2) the enrolled 

actuary must file with the Department of Labor an actuarial report regarding the valuation made 

by the actuary; and (3) the parent must file a description of the security provided with the 

Secretary of Labor. The Secretary of Labor has 30 days after the filing of the reports in (2) and 

(3) to notify the operator if the Secretary believes the applicable requirements have not been 

satisfied. 

The security provided by the parent must be provided to the trustees of the 1992 UMWA 

Benefit Plan, solely for the purpose of paying premiums for eligible beneficiaries, and must be 

equal to one year’s premium liability of the assigned operator (determined using the average cost 

of the operator’s liability during the prior three years). The security must remain in place for five 

years. The security must in the form of a bond, letter of credit or cash escrow.
36

Any prepayment made under the provision is to be used exclusively to pay premiums for 

which the operator would otherwise be liable. 

Effective Date

The provision is effective on the date of enactment.
37

III. PRODUCTION

A. Tax Credit for Oil and Gas Production From Marginal Wells

Present Law

There is no credit for the production of oil and gas from marginal wells. The costs of 

such production may be recovered under the Code's depreciation and depletion rules and in other 

cases as a deduction for ordinary and necessary business expenses.

[Present law imposes an alternative minimum tax on individuals and corporations in an 

amount equal to the excess of the tentative minimum tax over the regular tax liability. The 

tentative minimum tax is an amount equal to specified rates of tax imposed on the excess of the 

alternative minimum taxable income over an exemption amount. Generally, business credits 

may not exceed the excess of the regular tax liability over the tentative minimum tax.]

Description of Proposal

The proposal creates a new, $3 per barrel credit for the production of crude oil and a 

$0.50 per 1,000 cubic feet of qualified natural gas production. The maximum amount of 

production on which credit can be claimed is 1,095 barrels or barrel equivalents. In both cases, 

the credit is available only for production from a "qualified marginal well." The credit is not 

available to production occurring if the reference price of oil exceeds $18 ($2.00 for natural gas). 

The credit is reduced proportionately for reference prices between $15 and $18 ($1.67 and $2.00 

for natural gas). Reference prices are determined on a one-year look-back basis.

A qualified marginal well is defined as (1) a domestic well the production from which is 

treated as marginal production for purposes of the Code percentage depletion rules or (2) a 

domestic well that during the taxable year had (a) average daily production of not more than 25 

barrel equivalents and (b) produced water at a rate of not less than 95 percent of total well 

effluent. 

The credit is treated as a general business credit but is allowed against the alternative 

minimum tax. Additionally, unused credits can be carried back for up to 10 years rather than the 

generally applicable carryback period of one year.

Effective Date

The proposal is effective for production in tax years beginning after December 31, 2003.
38

B. Temporary Suspension of Limitation Based on 65 Percent of Taxable

Income and Extension of Suspension of Taxable Income Limit

With Respect to Marginal Production

Present Law

In general

Overview of Depletion

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.28 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.29 Generally, under the percentage depletion method 

15 percent of the taxpayer's gross income from an oil- or gas-producing property is allowed as a 

 

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

29 Sec. 613A.
39

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 

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, 2004. 

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)).30 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 of oil and gas percentage depletion to independent producers and royalty 

owners

Generally, only independent producers and royalty owners (as contrasted to integrated oil 

companies) are allowed to claim percentage depletion. Percentage depletion for eligible 

taxpayers is allowed only with respect to up to 1,000 barrels of average daily production of 

domestic crude oil or an equivalent amount of domestic natural gas (sec. 613A(c)). For 

producers of both oil and natural gas, this limitation applies on a combined basis.

In addition to the independent producer and royalty owner exception, certain sales of 

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

geopressured brine,31 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.

 

30 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.

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

1978, and January 1, 1984.
40

Description of Proposal

The limit on percentage depletion deductions to no more than 65 percent of the 

taxpayer’s overall taxable income is suspended for taxable years beginning after December 31, 

2003, and before January 1, 2007. The suspension of the 100-percent net-income limitation for 

marginal wells is extended an additional three years, through taxable years beginning before 

January 1, 2007.

Effective Date

The proposal is effective for taxable years beginning after December 31, 2003.
41

C. Amortization of Delay Rental Payments

Present Law

Present law generally requires costs associated with inventory and property held for 

resale to be capitalized rather than currently deducted as they are incurred. (sec. 263). Oil and 

gas producers typically contract for mineral production in exchange for royalty payments. If 

mineral production is delayed, these contracts provide for “delay rental payments” as a condition 

of their extension. The Treasury Department has taken the position that the uniform 

capitalization rules of section 263A require delay rental payments to be capitalized.

Description of Proposal

The proposal allows delay rental payments incurred in connection with the development 

of oil or gas within the United States to be amortized over two years. In the case of abandoned 

property, remaining basis may no longer be recovered in the year of abandonment of a property 

as all basis is recovered over the two-year amortization period.

Effective Date

The proposal applies to delay rental payments paid or incurred in taxable years beginning 

after December 31, 2003. No inference is intended from the prospective effective date of this 

proposal as to the proper treatment of pre-effective date delay rental payments.
42

D. Amortization of Geological and Geophysical Expenditures

Present Law

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.32

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

property33 acquired or retained.34 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 77-18835 (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 

 

32 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).

33 "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.

34 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.

35 1977-1 C.B. 76.
43

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.

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 
44

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 83-105,36 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."

Description of Proposal

The proposal allows geological and geophysical costs incurred in connection with oil and 

gas exploration in the United States to be amortized over two years. In the case of abandoned 

property, remaining basis may no longer be recovered in the year of abandonment of a property 

as all basis is recovered over the two-year amortization period.

Effective Date

The proposal is effective for G&G costs paid or incurred in taxable years beginning after 

December 31, 2003. No inference is intended from the prospective effective date of this 

proposal as to the proper treatment of pre-effective date geological and geophysical costs.

 

36 1983-2 C.B. 51.
45

E. Extension and Modification of Credit for Producing Fuel

From a Non-Conventional Source

Present Law

Certain fuels produced from "non-conventional sources" and sold to unrelated parties are 

eligible for an income tax credit equal to $3 (generally adjusted for inflation)37 per barrel or BTU 

oil barrel equivalent (sec. 29). Qualified fuels must be produced within the United States. 

Qualified fuels include:

(1) oil produced from shale and tar sands;

(2) gas produced from geopressured brine, Devonian shale, coal seams, tight 

formations ("tight sands"), or biomass; and

(3) liquid, gaseous, or solid synthetic fuels produced from coal (including lignite).

In general, the credit is available only with respect to fuels produced from wells drilled or 

facilities placed in service after December 31, 1979, and before January 1, 1993. An exception 

extends the January 1, 1993 expiration date for facilities producing gas from biomass and 

synthetic fuel from coal if the facility producing the fuel is placed in service before July 1, 1998, 

pursuant to a binding contract entered into before January 1, 1997. 

The credit may be claimed for qualified fuels produced and sold before January 1, 2003 

(in the case of non-conventional sources subject to the January 1, 1993 expiration date) or 

January 1, 2008 (in the case of biomass gas and synthetic fuel facilities eligible for the extension 

period).

Description of Proposal

The proposal permits taxpayers to claim the sec. 29 credit for production of certain nonconventional fuels produced at wells placed in service after the date of enactment and before 

January 1, 2007. Qualifying fuels are oil from shale or tar sands, and gas from geopressured 

brine, Devonian shale, coal seams or a tight formation. The value of the credit is $3.00 for 

production in 2003 and is indexed for inflation commencing with the credit amount for 2004. 

The credit could be claimed for production from the well for each of the first four years of 

production, but not for any production occurring after December 31, 2009.

 

37 The value of the section 29 credit for production in 2001 was $6.28 per barrel of oil 

equivalent.
46

The proposal further permits production from certain existing wells (any well drilled after 

December 31, 1979 and before January 1, 1993) to claim a credit equal to the newly, re-indexed 

value of $3.00 for production in 2003 after date of enactment through 2006. 

The proposal also permits landfill gas sold to a third party from facilities placed in 

service after June 30, 1998 and before January 1, 2007 to be eligible for the taxpayer to claim 

five years of credit from the later of the date of enactment or the date the facility is placed in 

service. The amount of credit is $3.00 per barrel equivalent in 2003 and is indexed for inflation 

commencing with the credit amount for 2004. In the case of a landfill subject to the 

Environmental Protection Agency’s 1996 New Source Performance Standards/Emissions 

Guidelines the amount of credit is $2.00 per barrel equivalent in 2003 and is indexed for inflation 

commencing with the credit amount for 2004. 

Under the proposal, the taxpayer may not claim any credit for production in excess of a 

daily average of 200,000 cubic feet of gas (or barrel of oil equivalent) from a qualifying well or 

facility.38

Effective Date

The proposal applies to fuel sold from qualifying wells and facilities after the date of 

enactment.

 

38 The daily average is computed as total production divided by the total number of days 

the well or facility was in production during the year.
47

F. Allow Business Energy Credits Against the Alternative Minimum Tax

Present Law

Present law imposes an alternative minimum tax on individuals and corporations in an 

amount equal to the excess of the tentative minimum tax over the regular tax liability. The 

tentative minimum tax is an amount equal to specified rates of tax imposed on the excess of the 

alternative minimum taxable income over an exemption amount.

Generally, business credits may not exceed the excess of the regular tax liability over the 

tentative minimum tax.

Description of Proposal

The proposal makes the minimum tax limitation inapplicable to the business energy 

credits added by the bill. 

Effective Date

The proposal applies to taxable years ending after the date of enactment of the Act.
48

G. Repeal Alternative Minimum Tax Intangible Drilling Costs ("IDC")

Preference for Oil and Gas Production

Present Law

Taxpayers who pay or incur intangible drilling or development costs (“IDCs”) in the 

development of domestic oil or gas production may elect to either expense or capitalize these 

amounts. 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.

The difference between the amount of a taxpayer’s IDC deduction and the amount which 

would have been currently deductible had IDCs been capitalized and recovered over a 10-year 

period is an item of tax preference for the alternative minimum tax (“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. This preference applies to taxpayers other than integrated oil companies only to the 

extent that the failure to apply the preference would result in a reduction of the taxpayer’s 

alternative minimum taxable income by more than 40 percent.

Description of Proposal

The proposal repeals the AMT preference for intangible drilling costs for oil and gas 

wells for taxpayers other than integrated oil companies.

Effective Date

The proposal applies to taxable years beginning after December 31, 2003, and beginning 

before January 1, 2006.
49

H. Allow Enhanced Oil Recovery Credit Against the Alternative Minimum Tax

Present Law

Present law imposes an alternative minimum tax on individuals and corporations in an 

amount equal to the excess of the tentative minimum tax over the regular tax liability. The 

tentative minimum tax is an amount equal to specified rates of tax imposed on the excess of the 

alternative minimum taxable income over an exemption amount.

Generally, business credits may not exceed the excess of the regular tax liability over the 

tentative minimum tax. One of these credits is the enhanced oil recovery credit (sec. 43).

Description of Proposal

The proposal repeals the minimum tax limitation on the enhanced oil recovery credit.

Effective Date

The proposal applies to taxable years beginning after December 31, 2003, and beginning 

before January 1, 2006.