Statement of the U.S. Department of the Treasury, Office of Tax Policy

Mr Chairman, Mr. McNulty, and Members of the Subcommittee:

It is the goal of this Administration to pursue an energy policy that protects America’s economic, security, and environmental interests. As you know, in May the President’s National Energy Policy Development (NEPD) Group released its report entitled "Reliable, Affordable, and Environmentally Sound Energy for America’s Future." The report sets forth three basic features of a National Energy Policy:

The Policy is a long-term, comprehensive strategy. Our energy crisis has been years in the making, and will take years to put fully behind us.

The Policy will advance new, environmentally friendly technologies to increase energy supplies and encourage cleaner, more efficient energy use.

The Policy seeks to raise the living standards of the American people, recognizing that to do so our country must fully integrate its energy, environmental, and economic policies.

In that context, the Office of Tax Policy appreciates the opportunity to present testimony on tax incentives to promote energy conservation and increase domestic production of oil and gas.

Incentives for energy efficiency and alternative energy sources are essential elements of national energy policy. The continuing strength of our economy over the past two years, despite oil price rises, underscores the dramatic improvements in energy efficiency we have achieved over the past quarter century, as well as the changing economy. While past oil shortages have taken a significant toll on the U.S. economy, the recent increases in oil prices have not affected the economy much. Increased energy efficiency in cars, homes, and manufacturing has helped insulate the economy from these short-term market fluctuations. In 1974, we consumed 15 barrels of oil for every $10,000 of gross domestic product. Today we consume only 8 barrels of oil for the same amount (in constant dollars) of economic output.

Tax incentives currently provide an important element of support for energy-efficiency improvements and increased use of renewable and alternative fuels. Current incentives are estimated to total $1.2 billion for fiscal years 2002 through 2006. They include a tax credit for electric vehicles and expensing for clean-fuel vehicles ($20 million), a tax credit for the production of electricity from wind or biomass and a tax credit for certain solar energy property ($590 million), and an exclusion from gross income for certain energy conservation subsidies provided by public utilities to their customers ($580 million).¹

A 10-percent tax credit is provided for the cost of a qualified electric vehicle, up to a maximum credit of $4,000. 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 electric current, the original use of which commences with the taxpayer, and that is acquired for use by the taxpayer and not for resale. The full amount of the credit is available for purchases prior to 2002. The credit begins to phase down in 2002 and does not apply to vehicles placed in service after 2004.

Certain costs of qualified clean-fuel vehicles and clean-fuel vehicle refueling property may be deducted when such property is placed in service. Qualified electric vehicles do not qualify for the clean-fuel vehicle deduction. The deduction begins to phase down in 2002 and does not apply to property placed in service after 2004.

A 1.5-cent-per-kilowatt-hour tax credit is provided for electricity produced from wind, "closed-loop" biomass (organic material from a plant that is planted exclusively for purposes of being used at a qualified facility to produce electricity), and poultry waste. The electricity must be sold to an unrelated person and the credit is limited to the first 10 years of production. The credit applies only to facilities placed in service before January 1, 2002. The credit amount is indexed for inflation after 1992.

A 10-percent investment tax credit is provided to businesses for qualifying equipment that uses solar energy to generate electricity, to heat or cool or provide hot water for use in a structure, or to provide solar process heat.

An income tax credit and an excise tax exemption are provided for ethanol and renewable source methanol used as a fuel. In general, the income tax credit is 53 cents per gallon for ethanol and 60 cents per gallon for renewable source methanol. As an alternative to the income tax credit, gasohol blenders may claim an equivalent gasoline tax exemption for each ethanol and renewable source methanol that is blended into qualifying gasohol.

The income tax credit expires on December 31, 2007, and the excise tax exemption expires on September 30, 2007. In addition, the ethanol credit and exemption are each reduced by 1 cent per gallon in 2003 and by an additional 1 cent per gallon in 2005. Neither the credit nor the exemption applies during any period in which motor fuel taxes dedicated to the Highway Trust Fund are limited to 4.3 cents per gallon. Under current law, the motor fuel tax dedicated to the Highway Trust Fund will be limited to 4.3 cents per gallon beginning on October 1, 2005.

Subsidies provided by public utilities to their customers for the purchase or installation of energy conservation measures are excluded from the customers’ gross income. An energy conservation measure is any installation or modification primarily designed to reduce consumption of electricity or natural gas or to improve the management of energy demand with respect to a dwelling unit.

The Administration’s budget proposals for fiscal year 2002 include tax incentives for renewable energy resources. The budget also proposes to modify the tax treatment of nuclear decommissioning funds. The Administration’s proposals are described below.²

The Administration proposes to extend the credit for electricity produced from wind and biomass for three years to facilities placed in service before January 1, 2005. In addition, eligible biomass sources would be expanded to include certain biomass from forest-related resources, agricultural sources, and other specified sources. Special rules would apply to biomass facilities placed in service before January 1, 2002. Electricity produced at such facilities from newly eligible sources would be eligible for the credit only from January 1, 2002, through December 31, 2004. The credit for such electricity would be computed at a rate equal to 60 percent of the generally applicable rate. Electricity produced from newly eligible biomass co-fired in coal plants would also be eligible for the credit only from January 1, 2002, through December 31, 2004. The credit for such electricity would be computed at a rate equal to 30 percent of the generally applicable rate.

The Administration proposes a new tax credit for individuals that purchase solar energy equipment used to generate electricity (photovoltaic equipment) or heat water (solar water heating equipment) for use in a dwelling unit that the individual uses as a residence. The credit would be available only for equipment used exclusively for purposes other than heating swimming pools. The proposed credit would be equal to 15 percent of the cost of the equipment and its installation. The credit would be nonrefundable and an individual would be allowed a lifetime maximum credit of $2,000 per residence for photovoltaic equipment and $2,000 per residence for solar water heating equipment. The credit would apply only to solar water heating equipment placed in service after December 31, 2001, and before January 1, 2006, and to photovoltaic systems placed in service after December 31, 2001, and before January 1, 2008.

The Administration proposes to repeal the current law provision that limits deductible contributions to a nuclear decommissioning fund to the amount included in the taxpayer’s cost of service for ratemaking purposes. Thus, unregulated taxpayers would be allowed a deduction for amounts contributed to a qualified nuclear decommissioning fund. The Administration also proposes to permit funding of all decommissioning costs (including pre-1984 costs) through qualified nuclear decommissioning funds. Contributions to fund pre-1984 costs would be deductible except to the extent a deduction (other than under the qualified fund rules) or an exclusion from income has been previously allowed with respect to those costs. The Administration’s proposal would clarify that any transfer of a qualified nuclear decommissioning fund in connection with the transfer of the power plant with which it is associated would be nontaxable and no gain or loss will be recognized by the transferor or transferee as a result of the transfer. In addition, the proposal would permit taxpayers to make deductible contributions to a qualified fund after the end of the nuclear power plant’s estimated useful life and would provide that nuclear decommissioning costs are deductible when paid.

The Report of the NEPD Group also included tax incentives for renewable energy resources and for more efficient energy use. The NEPD Group proposals are described below.³

The NEPD Group proposes to extend the section 29 credit for fuel produced from landfill methane produced at a facility (or portion of a facility) that is placed in service after December 31, 2001. Fuel produced at such facilities would be eligible for the credit through December 31, 2010. The proposal would also expand the credit by permitting the credit for fuel used by the taxpayer to produce electricity. The credit for fuel produced at landfills subject to EPA’s 1996 New Source Performance Standards/Emissions Guidelines would be limited to two-thirds of the otherwise applicable amount. In the case of landfills with facilities that currently qualify for the section 29 credit, this limitation would not apply until after 2007.

The NEPD Group proposes to extend the income tax credit and excise tax exemption for ethanol and renewable source methanol through December 31, 2010. The current law rule providing that neither the credit nor the exemption applies during any period in which motor fuel taxes dedicated to the Highway Trust Fund are limited to 4.3 cents per gallon would be retained. As under current law, the credit and the exemption would each be reduced by 1 cent per gallon in 2003 and by an additional 1 cent per gallon in 2005.

The NEPD Group proposes to provide temporary tax credits for certain hybrid and fuel cell vehicles.

A credit of $250 to $4,000 would be available for purchases of qualifying hybrid vehicles after December 31, 2001, and before January 1, 2008. A hybrid vehicle is a vehicle that draws propulsion from both an on-board internal combustion or heat engine using combustible fuel and an on-board rechargeable energy storage system. To qualify for the minimum credit, a hybrid vehicle would be required to derive at least 5 percent of its maximum available power from the rechargeable energy storage system. Larger credits would be available for vehicles that derive larger percentages of power from the rechargeable energy storage system and for vehicles that meet specified fuel economy standards.

A credit of $1,000 to $8,000 would be available for the purchase of qualifying fuel cell vehicles after December 31, 2001, and before January 1, 2008. A fuel cell vehicle is a motor vehicle propelled by power derived from one or more cells that convert chemical energy directly into electricity by combining oxygen with on-board hydrogen (including hydrogen produced from on-board fuel that requires reformation before use). To qualify for the minimum credit, a fuel cell vehicle would be required to meet a minimum fuel economy standard for its weight class. Larger credits would be available for vehicles that achieve higher fuel economy standards.

To encourage more efficient energy usage, the NEPD Group proposes to provide a 10-percent investment credit for qualifying combined heat and power (CHP) systems. CHP systems are used to produce electricity (and/or mechanical power) and usable heat from the same primary energy source. To qualify for the credit, a system would be required to produce 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 and/or mechanical power and would also be required to satisfy an energy efficiency standard. The credit would apply to CHP equipment placed in service after December 31, 2001, and before January 1, 2007.

Before turning to a discussion of the present tax treatment of oil and gas activities, we would like to provide a brief overview of this sector.

Oil is an internationally traded commodity with its domestic price set by world supply and demand. Domestic exploration and production activity is affected by the world price of crude oil. Historically, world oil prices have fluctuated substantially. From 1970 to the early 1980s, there was a fivefold increase in real oil prices. World oil prices fell sharply in 1986 and were relatively more stable from 1986 through 1997. During that period, average refiner acquisition costs ranged from $14.91 to $23.59 per barrel in real 1992 dollars. In 1998, however, oil costs to the refiner declined to $12.52 per barrel in nominal dollars ($11.14 per barrel in 1992 dollars), their lowest level in 25 years in real terms. Since 1998, the decline has reversed with refiner acquisition costs (in nominal dollars) rising to $17.51 per barrel in 1999 and $27.69 per barrel in 2000 (the price has since dropped to $23.89 per barrel in April 2001, the latest month for which composite figures are available). The equivalent prices in 1992 dollars are $15.31 per barrel in 1999, $24.28 per barrel in 2000, and $20.20 per barrel in April 2001.

Domestic oil production has been on the decline since the mid-1980s. From 1978 to 1983 oil consumption in the United States also declined, but increasing consumption since 1983 has more than offset this decline. In 2000, domestic oil consumption was 28 percent higher than in 1970. The decline in oil production and increase in consumption have led to an increase in oil imports. Net petroleum (crude and product) imports have risen from approximately 38 percent of consumption in 1988 to 52 percent in 2000.

A similar pattern of large recent price increases and increasing dependence on imports has occurred in the natural gas market. During the second half of the 1990s, spot prices for natural gas exceeded $4.00 per million Btu (MMBtu) in only one month (February 1996). The spot price again exceeded $4.00 per MMBtu in May 2000, rose above $5.00 per MMBtu in September 2000, and exceeded $10.00 per MMBtu for several days last winter. Since last winter the price has fallen sharply. The current spot price is approximately $3.71 per MMBtu.⁴

The United States has large natural gas reserves and was essentially self-sufficient in natural gas until the late 1980s. Since 1986, natural gas consumption has increased by more than 30 percent but natural gas production has increased by only 17 percent. Net imports as a share of consumption nearly quadrupled from 1986 to 2000, rising from 4.2 percent to 15.6 percent. Natural gas from Canada makes up nearly all of the imports into the United States.

Although the Administration’s energy plan contains no new tax incentives for oil and gas production, the Internal Revenue Code includes a variety of measures to stimulate domestic exploration and production. They are generally justified on the ground that they reduce vulnerability to an oil supply disruption through increases in domestic production, reserves, exploration activity, and production capacity. The tax incentives contained in present law address the drop in domestic exploratory drilling that has occurred since the mid-1950s and the continuing loss of production from mature fields and marginal properties.

Incentives for oil and gas production are estimated to total $9.8 billion for fiscal years 2002 through 2006.⁵ They include the nonconventional fuels (i.e., oil produced from shale and tar sands, gas produced from geopressured brine, Devonian shale, coal seams, tight formations, or biomass, and synthetic fuel produced from coal) production credit ($2.4 billion), the enhanced oil recovery credit ($4.4 billion), the allowance of percentage depletion for independent producers and royalty owners, including increased percentage depletion for stripper wells ($2.3 billion), the exception from the passive loss limitation for working interests in oil and gas properties ($100 million), and the expensing of intangible drilling and development costs ($640 million). In addition to those tax expenditures, oil and gas activities have largely been eliminated from the alternative minimum tax. These provisions are described in detail below.

Certain costs incurred prior to drilling an oil- or gas-producing property are recovered through the depletion deduction. These include costs of acquiring the lease or other interest in the property, and geological and geophysical costs (in advance of actual drilling). Any taxpayer having an economic interest in a producing property may use the cost depletion method. Under this method, the basis recovery for a taxable year is proportional to the exhaustion of the property during the year. The cost depletion method does not permit cost recovery deductions that exceed the taxpayer’s basis in the property or that are allowable on an accelerated basis. Thus, the deduction for cost depletion is not generally viewed as a tax incentive.

Independent producers and royalty owners (as contrasted to integrated oil companies)⁶ may qualify for percentage depletion. A qualifying taxpayer determines the depletion deduction for each oil or gas property under both the percentage depletion method and the cost depletion method and deducts the larger of the two amounts. Under the percentage depletion method, generally 15 percent of the taxpayer’s gross income from an oil- or gas-producing property is allowed as a deduction in each taxable year. The amount deducted may not exceed 100 percent of the net income from that property in any year (the "net-income limitation").⁷ 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).⁸

A taxpayer may claim percentage depletion with respect to up to 1,000 barrels of average daily production of domestic crude oil or an equivalent amount of domestic natural gas. For producers of both oil and natural gas, this limitation applies on a combined basis. All production owned by businesses under common control and members of the same family must be aggregated; each group is then treated as one producer for application of the 1,000-barrel limitation.

Special percentage depletion provisions apply to oil and gas production from marginal properties. The statutory percentage depletion rate is increased (from the general rate of 15 percent) by one percentage point for each whole dollar that the average price of crude oil (as determined under the provisions of the nonconventional fuels production credit of section 29) for the immediately preceding calendar year is less than $20 per barrel. In no event may the rate of percentage depletion under this provision exceed 25 percent for any taxable year. The increased rate applies for the taxpayer’s taxable year which immediately follows a calendar year for which the average crude oil price falls below the $20 floor. To illustrate the application of this provision, the average price of a barrel of crude oil for calendar year 1999 was $15.56; thus, the percentage depletion rate for production from marginal wells was increased by four percent (to 19 percent) for taxable years beginning in 2000. The 100-percent-of-net-income limitation has been suspended for marginal wells for taxable years beginning after December 31, 1997, and before January 1, 2002. The Administration’s budget for fiscal year 2002 proposes a one-year extension of this provision. Under the Administration proposal, marginal wells would continue to be exempt from the limitation during taxable years beginning in 2002.

Marginal production is defined for this purpose as domestic crude oil or domestic natural gas which is produced during any taxable year from a property which (1) is a stripper well property for the calendar year in which the taxable year begins, or (2) is a property substantially all of the production from which during such calendar year is heavy oil (i.e., oil that has a weighted average gravity of 20 degrees API or less corrected to 60 degrees Fahrenheit). A stripper well property is any oil or gas property for which daily average production per producing oil or gas well is not more than 15 barrel equivalents in the calendar year during which the taxpayer’s taxable year begins.⁹ A property qualifies as a stripper well property for a calendar year only if the wells on such property were producing during that period at their maximum efficient rate of flow.

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

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

Because percentage depletion, unlike cost depletion, is computed without regard to the taxpayer’s basis in the depletable property, cumulative depletion deductions may be far greater than the amount expended by the taxpayer to acquire or develop the property.

In general, costs that benefit future periods must be capitalized and recovered over such periods for income tax purposes, rather than being expensed in the period the costs are incurred. In addition, the uniform capitalization rules require certain direct and indirect costs allocable to property to be included in inventory or capitalized as part of the basis of such property. In general, the uniform capitalization rules apply to real and tangible personal property produced by the taxpayer or acquired for resale.

Special rules apply to intangible drilling and development costs ("IDCs").¹⁰ Under these special rules, an operator (i.e., a person who holds a working or operating interest in any tract or parcel of land either as a fee owner or under a lease or any other form of contract granting working or operating rights) who pays or incurs IDCs in the development of an oil or gas property located in the United States may elect either to expense or capitalize those costs. The uniform capitalization rules do not apply to otherwise deductible IDCs.

If a taxpayer elects to expense IDCs, the amount of the IDCs is deductible as an expense in the taxable year the cost is paid or incurred. Generally, IDCs that a taxpayer elects to capitalize may be recovered through depletion or depreciation, as appropriate; or in the case of a nonproductive well ("dry hole"), the operator may elect to deduct the costs. In the case of an integrated oil company (i.e., a company that engages, either directly or through a related enterprise, in substantial retailing or refining activities) that has elected to expense IDCs, 30 percent of the IDCs on productive wells must be capitalized and amortized over a 60-month period.¹¹

A taxpayer that has elected to deduct IDCs may, nevertheless, elect to capitalize and amortize certain IDCs over a 60-month period beginning with the month the expenditure was paid or incurred. This rule applies on an expenditure-by-expenditure basis; that is, for any particular taxable year, a taxpayer may deduct some portion of its IDCs and capitalize the rest under this provision. This allows the taxpayer to reduce or eliminate IDC adjustments or preferences under the alternative minimum tax.

The election to deduct IDCs applies only to those IDCs associated with domestic properties.¹² For this purpose, the United States includes certain wells drilled offshore.¹³

Intangible drilling costs are a major portion of the costs necessary to locate and develop oil and gas reserves. Because the benefits obtained from these expenditures are of value throughout the life of the project, these costs would be capitalized and recovered over the period of production under generally applicable accounting principles.

Taxpayers that produce certain qualifying fuels from nonconventional sources are eligible for a tax credit ("the section 29 credit") equal to $3 per barrel or barrel-of-oil equivalent.¹⁴ Fuels qualifying for the credit must be produced domestically from a well drilled, or a facility treated as placed in service before January 1, 1993.¹⁵ The section 29 credit generally is available for qualified fuels sold to unrelated persons before January 1, 2003.¹⁶

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

The amount of the section 29 credit generally is adjusted by an inflation adjustment factor for the calendar year in which the sale occurs.¹⁷ There is no adjustment for inflation in the case of the credit for sales of natural gas produced from a tight formation. The credit begins to phase out if the annual average unregulated wellhead price per barrel of domestic crude oil exceeds $23.50 multiplied by the inflation adjustment factor.¹⁸

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

As with most other credits, the section 29 credit may not be used to offset alternative minimum tax liability. Any unused section 29 credit generally may not be carried back or forward to another taxable year; however, a taxpayer receives a credit for prior year minimum tax liability to the extent that a section 29 credit is disallowed as a result of the operation of the alternative minimum tax. The credit is limited to what would have been the regular tax liability but for the alternative minimum tax.

The provision provides a significant tax incentive (currently about $6 per barrel of oil equivalent or $1 per thousand cubic feet of natural gas). Coalbed methane and gas from tight formations currently account for most of the credit.

Taxpayers are permitted to claim a general business credit, which consists of several different components. One component of the general business credit is the enhanced oil recovery credit. The general business credit for a taxable year may not exceed the excess (if any) of the taxpayer’s net income tax over the greater of (1) the tentative minimum tax, or (2) 25 percent of so much of the taxpayer’s net regular tax liability as exceeds $25,000. Any unused general business credit generally may be carried back one taxable year and carried forward 20 taxable years.

The enhanced oil recovery credit for a taxable year is equal to 15 percent of certain costs attributable to qualified enhanced oil recovery ("EOR") projects undertaken by the taxpayer in the United States during the taxable year. To the extent that a credit is allowed for such costs, the taxpayer must reduce the amount otherwise deductible or required to be capitalized and recovered through depreciation, depletion, or amortization, as appropriate, with respect to the costs. A taxpayer may elect not to have the enhanced oil recovery credit apply for a taxable year.

The amount of the enhanced oil recovery credit is reduced in a taxable year following a calendar year during which the annual average unregulated wellhead price per barrel of domestic crude oil exceeds $28 (adjusted for inflation since 1990).¹⁹ In such a case, the credit would be reduced ratably over a $6 phaseout range.

For purposes of the credit, qualified enhanced oil recovery costs include the following costs which are paid or incurred with respect to a qualified EOR project: (1) the cost of tangible property which is an integral part of the project and with respect to which depreciation or amortization is allowable; (2) IDCs that the taxpayer may elect to deduct;²⁰ and (3) the cost of tertiary injectants with respect to which a deduction is allowable, whether or not chargeable to capital account.

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

A project is not considered a qualified EOR project unless the project’s operator submits to the IRS a certification from a petroleum engineer that the project meets the requirements set forth in the preceding paragraph.

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

Conventional oil recovery methods do not recover all of a well’s oil. Some of the remaining oil can be extracted by unconventional methods, but these methods are generally more costly. At current world oil prices, a large part of the remaining oil in place is uneconomic to recover by unconventional methods. In this environment, the EOR credit can increase recoverable reserves. Although recovering oil using EOR methods is more expensive than recovering it using conventional methods, it may be less expensive than producing oil from new reservoirs. Although the credit could phase out at higher oil prices, it is fully effective at present world oil prices.

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

As a general rule, percentage depletion deductions claimed in excess of the basis of the depletable property constitute an item of tax preference in determining the AMT. In addition, the AMTI of a corporation is increased by an amount equal to 75 percent of the amount by which adjusted current earnings ("ACE") of the corporation exceed AMTI (as determined before this adjustment). In general, ACE means AMTI with additional adjustments that generally follow the rules presently applicable to corporations in computing their earnings and profits. As a general rule a corporation must use the cost depletion method in computing its ACE adjustment. Thus, the difference between a corporation’s percentage depletion deduction (if any) claimed for regular tax purposes and its allowable deduction determined under the cost depletion method is factored into its overall ACE adjustment.

Excess percentage depletion deductions related to crude oil and natural gas production are not items of tax preference for AMT purposes. In addition, corporations that are independent oil and gas producers and royalty owners may determine depletion deductions using the percentage depletion method in computing their ACE adjustments.

The difference between the amount of a taxpayer’s IDC deductions and the amount which would have been currently deductible had IDC’s been capitalized and recovered over a 10-year period may constitute an item of tax preference for the AMT to the extent that this amount exceeds 65 percent of the taxpayer’s net income from oil and gas properties for the taxable year (the "excess IDC preference"). In addition, for purposes of computing a corporation’s ACE adjustment to the AMT, IDCs are capitalized and amortized over the 60-month period beginning with the month in which they are paid or incurred. The preference does not apply if the taxpayer elects to capitalize and amortize IDCs over a 60-month period for regular tax purposes.

IDC’s related to oil and gas wells are generally not taken into account in computing the excess IDC preference of taxpayers that are not integrated oil companies. This treatment does not apply, however, to the extent it would reduce the amount of the taxpayer’s AMTI by more than 40 percent of the amount that the taxpayer’s AMTI would have been if those IDCs had been taken into account.

In addition, for corporations other than integrated oil companies, there is no ACE adjustment for IDCs with respect to oil and gas wells. That is, such a taxpayer is permitted to use its regular tax method of writing off those IDCs for purposes of computing its adjusted current earnings.

Absent these rules, the incentive effect of the special provisions for oil and gas would be reduced for firms subject to the AMT. These rules, however, effectively eliminate AMT concerns for independent producers.

A taxpayer’s deductions from passive trade or business activities, to the extent they exceed income from all such passive activities of the taxpayer (exclusive of portfolio income), generally may not be deducted against other income.²¹ Thus, for example, an individual taxpayer may not deduct losses from a passive activity against income from wages. Losses suspended under this "passive activity loss" limitation are carried forward and treated as deductions from passive activities in the following year, and thus may offset any income from passive activities generated in that later year. Losses from a passive activity may be deducted in full when the taxpayer disposes of its entire interest in that activity to an unrelated party in a transaction in which all realized gain or loss is recognized.

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

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

Similar limitations apply to the utilization of tax credits attributable to passive activities. Thus, for example, the passive activity rules (and, consequently, the oil and gas working interest exception to those rules) apply to the nonconventional fuels production credit and the enhanced oil recovery credit. However, if a taxpayer has net income from a working interest in an oil and gas property which is treated as not arising from a passive activity, then any tax credits attributable to the interest in that property would be treated as credits not from a passive activity (and, thus, not subject to the passive activity credit limitation) to the extent that the amount of the credits does not exceed the regular tax liability which is allocable to such net income.

As a result of this exception from the passive loss limitations, owners of working interests in oil and gas properties may use losses from such interests to offset income from other sources.

Taxpayers are allowed to deduct the cost of qualified tertiary injectant expenses for the taxable year. Qualified tertiary injectant expenses are amounts paid or incurred for any tertiary injectant (other than recoverable hydrocarbon injectants) which is used as a part of a tertiary recovery method.

The provision allowing the deduction for qualified tertiary injectant expenses resolves a disagreement between taxpayers (who considered such costs to be IDCs or operating expenses) and the IRS (which considered such costs to be subject to capitalization).

This concludes our testimony. We would be pleased to answer any questions the Subcommittee may have.

Taxpayers that produce gas from biomass (including landfill methane) are eligible for a tax credit ("the section 29 credit") equal to $3 per barrel-of-oil equivalent. For this purpose, a barrel-of-oil equivalent is the amount of gas that has a Btu (British thermal unit) content of 5.8 million. To qualify for the credit, the gas must be produced domestically from a facility placed in service by the taxpayer before July 1, 1998, pursuant to a written binding contract in effect before January 1, 1997. In addition, the gas must be sold to an unrelated person before January 1, 2008.

The amount of the section 29 credit generally is adjusted by an inflation adjustment factor for the calendar year in which the sale occurs. The inflation adjustment factor for the 2000 taxable year was 2.0454, and the inflation-adjusted amount of the credit for that year was $6.14 per barrel or barrel equivalent. The credit begins to phase out if the annual average unregulated wellhead price per barrel of domestic crude oil exceeds $23.50 multiplied by the inflation adjustment factor. For 2000, the inflation adjusted threshold for onset of the phaseout was $48.07 ($23.50 x 2.0454) and the average wellhead price for that year was $26.73.

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

The section 29 credit may not be used to offset alternative minimum tax liability. Any unused section 29 credit generally may not be carried back or forward to another taxable year; however, a taxpayer receives a credit for prior year minimum tax liability to the extent that a section 29 credit is disallowed as a result of the operation of the alternative minimum tax. The credit is limited to what would have been the regular tax liability but for the alternative minimum tax.

The tax credit helps make fuel produced from landfill methane competitive with other fuels. Extending the credit would continue the important contribution of this renewable energy source to the Nation’s long-term energy supply.

The credit would be allowed for fuel produced from landfill methane if the fuel is produced from a facility (or portion of a facility) placed in service after December 31, 2001, and before January 1, 2011, and is sold (or used to produce electricity that is sold) before January 1, 2011. The credit for fuel produced at landfills subject to EPA’s 1996 New Source Performance Standards/Emissions Guidelines would be limited to two-thirds of the otherwise applicable amount beginning on January 1, 2008, if any portion of the facility for producing fuel at the landfill was placed in service before July 1, 1998, and beginning on January 1, 2002, in all other cases. The proposal would clarify, for purposes of determining the extent to which a facility is placed in service after December 31, 2001, that the facility includes the wells, pipes, and related components used to collect landfill methane and that only production attributable to wells, pipes, and related components placed in service after December 31, 2001, is treated as produced from the portion of the facility placed in service after that date.

Extension of Tax Incentives for Ethanol

Current law provides an income tax credit and an excise tax exemption for ethanol and renewable source methanol used as a fuel. In general, the income tax credit for ethanol is 53 cents per gallon, but small ethanol producers (i.e., those producing less than 30 million gallons of ethanol per year) qualify for a credit of 63 cents per gallon on the first 15 million gallons of ethanol produced in a year. A credit of 60 cents per gallon is allowed for renewable source methanol.

As an alternative to the income tax credit, gasohol blenders may claim a gasoline tax exemption of 53 cents for each gallon of ethanol and 60 cents for each gallon of renewable source methanol that is blended into qualifying gasohol.

The income tax credit expires on December 31, 2007, and the excise tax exemption expires on September 30, 2007. In addition, the ethanol credit and exemption are each reduced by 1 cent per gallon in 2003 and by an additional 1 cent per gallon in 2005. Neither the credit nor the exemption applies during any period in which motor fuel taxes dedicated to the Highway Trust Fund are limited to 4.3 cents per gallon. Under current law, the motor fuel tax dedicated to the Highway Trust Fund will be limited to 4.3 cents per gallon beginning on October 1, 2005.

The tax credit and excise tax exemption help make ethanol and renewable source methanol competitive with other fuels. Extending the credit and exemption would continue the important contribution of these renewable energy sources to the Nation’s long-term energy supply.

The income tax credit and the excise tax exemption would be extended through December 31, 2010. The current law rule providing that neither the credit nor the exemption applies during any period in which motor fuel taxes dedicated to the Highway Trust Fund are limited to 4.3 cents per gallon would be retained. As under current law, the credit and the exemption would each be reduced by 1 cent per gallon in 2003 and by an additional 1 cent per gallon in 2005.

No generally available income tax credit for purchases of hybrid vehicles is available currently. A 10-percent tax credit is provided for the cost of a qualified electric vehicle, up to a maximum credit of $4,000. 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 electric current, the original use of which commences with the taxpayer, and that is acquired for use by the taxpayer and not for resale. The full amount of the credit is available for purchases prior to 2002. The credit begins to phase down in 2002 and does not apply to vehicles placed in service after 2004.

Certain costs of qualified clean-fuel property, including clean-fuel vehicles, may be deducted when such property is placed in service. Qualified electric vehicles do not qualify for the clean-fuel vehicle deduction. The deduction begins to phase down in 2002 and does not apply to property placed in service after 2004.

The transportation sector now accounts for 67 percent of U.S. oil consumption. Cars, sport utility vehicles, light trucks, and minivans alone account for 40 percent of U.S. oil consumption, about 20 to 40 percent of all urban smog-forming emissions and 20 percent of greenhouse gas emissions. Almost all of these vehicles use a single gasoline-fueled engine.

Hybrid vehicles, which have more than one source of power on board the vehicle, and electric vehicles have the potential to reduce petroleum consumption, air pollution, and greenhouse gas emissions. The proposed credits will encourage the purchase of highly fuel efficient vehicles that incorporate advanced automotive technologies and will help to move hybrid and fuel cell vehicles from the laboratory to the highway. These vehicles can significantly reduce oil consumption, emissions of air pollutants, and emissions of carbon dioxide, the most prevalent greenhouse gas.

The proposal would provide temporary tax credits for certain hybrid and fuel cell vehicles:

(1) Credit for qualified hybrid vehicles. A credit, of up to $4,000, would be available for purchases of qualified hybrid vehicles after December 31, 2001, and before January 1, 2008. The credit would be:

(a) $250 if the rechargeable energy storage system provides at least 5 percent but less than 10 percent of the maximum available power;

(b) $500 if the rechargeable energy storage system provides at least 10 percent and less than 20 percent of the maximum available power;

(c) $750 if the rechargeable energy storage system provides at least 20 percent and less than 30 percent of the maximum available power; and

(d) $1,000 if the rechargeable energy storage system provides 30 percent or more of the maximum available power.

If the vehicle’s fuel economy exceeds the 2000 model year city fuel economy, the amount of credit shown in (a) through (d) above would be increased by the following amounts:

(i) $500 if the vehicle achieves at least 125 percent but less than 150 percent of the 2000 model year city fuel economy;

(ii) $1,000 if the vehicle achieves at least 150 percent but less than 175 percent of the 2000 model year city fuel economy;

(iii) $1,500 if the vehicle achieves at least 175 percent but less than 200 percent of the 2000 model year city fuel economy;

(iv) $2,000 if the vehicle achieves at least 200 percent but less than 225 percent of the 2000 model year city fuel economy;

(v) $2,500 if the vehicle achieves at least 225 percent but less than 250 percent of the 2000 model year city fuel economy; and

(vi) $3,000 if the vehicle achieves at least 250 percent of the 2000 model year city fuel economy.

(2) Credit for qualified fuel cell vehicles. A credit of up to $8,000 would be available for the purchase of new qualified fuel cell vehicles after December 31, 2001, and before January 1, 2008. The credit would be $4,000, but, if the vehicle’s fuel economy exceeds the 2000 model year city fuel economy, the credit would increase by the following amounts:

(i) $1,000 if the vehicle achieves at least 150 percent but less than 175 percent of the 2000 model year city fuel economy;

(ii) $1,500 if the vehicle achieves at least 175 percent but less than 200 percent of the 2000 model year city fuel economy;

(iii) $2,000 if the vehicle achieves at least 200 percent but less than 225 percent of the 2000 model year city fuel economy;

(iv) $2,500 if the vehicle achieves at least 225 percent but less than 250 percent of the 2000 model year city fuel economy;

(v) $3,000 if the vehicle achieves at least 250 percent but less than 275 percent of the 2000 model year city fuel economy;

(vi) $3,500 if the vehicle achieves at least 275 percent but less than 300 percent of the 2000 model year city fuel economy; and

(vii) $4,000 if the vehicle achieves at least 300 percent of the 2000 model year city fuel economy.

The 2000 model year city fuel economy would be the following:

	The 2000 model year city fuel economy is:
If the vehicle inertia weight class is:	For a passenger automobile:	For a light truck:
1,500 or 1,750 lbs	43.7 mpg	37.6 mpg
2,000 lbs	38.3 mpg	33.7 mpg
2,250 lbs	34.1 mpg	30.6 mpg
2,500 lbs	30.7 mpg	28.0 mpg
2,750 lbs	27.9 mpg	25.9 mpg
3,000 lbs	25.6 mpg	24.1 mpg
3,500 lbs	22.0 mpg	21.3 mpg
4,000 lbs	19.3 mpg	19.0 mpg
4,500 lbs	17.2 mpg	17.3 mp
5,000 lbs	15.5 mpg	15.8 mpg
5,500 lbs	14.1 mpg	14.6 mpg
6,000 lbs	12.9 mpg	13.6 mpg
6,500 lbs	11.9 mpg	12.8 mpg
7,000 or 8,500 lbs	11.1 mpg	12.0 mpg

The "vehicle inertia weight class" is defined in regulations prescribed by the Environmental Protection Agency for purposes of title II of the Clean Air Act.

A qualifying hybrid vehicle is a motor vehicle that draws propulsion energy from on-board sources of stored energy which are both: (1) an internal combustion engine or heat engine using combustible fuel, and (2) a rechargeable energy storage system. A qualifying fuel cell vehicle is a motor vehicle that is propelled by power derived from one or more cells which convert chemical energy directly into electricity by combining oxygen with hydrogen fuel which is stored on board the vehicle and may or may not require reformation prior to use. A qualifying vehicle must meet all applicable regulatory requirements.

Maximum available power means the maximum value available from the battery or other energy storage device, during a standard power test, divided by the sum of the battery or other energy storage device and the SAE net power of the heat engine.

These credits would be available for all qualifying light vehicles including cars, minivans, sport utility vehicles, and light trucks. Taxpayers would be able to claim only one of the credits per vehicle and taxpayers who claim either credit would not be able to claim the qualified electric vehicle credit or the deduction for clean-fuel vehicle property for the same vehicle. Business taxpayers claiming either credit would be subject to the limitations on the general business credit and would be required to reduce the basis of the vehicle by the amount of the credit.

Investment Credit for Combined Heat and Power (CHP) Systems

Combined heat and power (CHP) systems are used to produce electricity (and/or mechanical power) and usable thermal energy from a single primary energy source. Depreciation allowances for CHP property vary by asset use and capacity. Assets employed in the production of electricity used by the taxpayer in an industrial manufacturing process or plant activity (and not ordinarily available for sale to others) have a general cost recovery period of 15 years if rated with total capacity in excess of 500 kilowatts. Electricity production assets of lesser-rated capacity generally are classified with other manufacturing assets and have cost recovery periods of five to ten years. Assets used in the production of electricity for sale have either a 15-year or 20-year recovery period. For assets that are structural components of buildings, however, the recovery period is either 39 years (if nonresidential) or 27.5 years (if residential), and the straight-line method for computing depreciation allowances must be used. For assets with recovery periods of 10 years or less, the 200 percent declining balance method may be used to compute depreciation allowances. The 150 percent declining balance method may be used for assets with recovery periods of 15 or 20 years. No income tax credit is provided currently for investment in combined heat and power property.

Combined heat and power systems utilize thermal energy that is otherwise wasted in producing electricity by more conventional methods. CHP systems achieve a greater level of overall energy efficiency, and thereby lessen the consumption of primary fossil fuels, lower total energy costs, and reduce carbon emissions. An investment tax credit for CHP assets is expected to encourage increased energy efficiency by accelerating planned investments and inducing additional investments in such systems. The increased demand for CHP equipment should, in turn, reduce CHP production costs and spur additional technological innovation in improved CHP systems.

The proposal would establish a 10-percent investment credit for qualified CHP systems with an electrical capacity in excess of 50 kilowatts or with a capacity to produce mechanical power in excess of 67 horsepower (or an equivalent combination of electrical and mechanical energy capacities). CHP property would be defined as property comprising a system that uses the same energy source for the simultaneous or sequential generation of (1) electricity or mechanical shaft power (or both) and (2) steam or other forms of useful thermal energy (including heating and cooling applications). A qualified CHP system would be required to produce at least 20 percent of its total useful energy in the form of thermal energy and at least 20 percent of its total useful energy in the form of electrical or mechanical power (or a combination thereof) and would also be required to satisfy an energy-efficiency standard. For CHP systems with an electrical capacity in excess of 50 megawatts (or a mechanical energy capacity in excess of 67,000 horsepower), the total energy efficiency of the system would have to exceed 70 percent. For smaller systems, the total energy efficiency would have to exceed 60 percent. For this purpose, total energy efficiency would be calculated as the sum of the useful electrical, thermal, and mechanical power produced by the system at normal operating rates, measured on a Btu basis, divided by the lower heating value of the primary fuel source for the system supplied. The credit would be allowed with respect to qualified CHP property only if its eligibility is verified under regulations prescribed by the Secretary of the Treasury.

Investments in qualified CHP assets that are otherwise assigned cost recovery periods of less than 15 years would be eligible for the credit, provided that the taxpayer elected to treat such property as having a 22-year class life. Thus, regular tax depreciation allowances would be calculated using a 15-year recovery period and the 150 percent declining balance method.

The credit would be treated as an energy credit under the investment credit component of the section 38 general business credit, and would be subject to the rules and limitations governing that credit. Taxpayers using the credit for CHP equipment would not be entitled to any other tax credit for the same equipment.

The credit would apply to investments in CHP equipment placed in service after December 31, 2001, but before January 1, 2007.

1. Analytical Perspectives, Budget of the United States Government, Fiscal Year 2002, U.S. Government Printing Office, Washington, DC, 2001, p. 63.
2. For a more detailed description, see General Explanations of the Administration’s Fiscal Year 2002 Tax Relief Proposals, Department of the Treasury, April 2001.
3. For a more detailed description, see the attachments to this testimony.
4. All price references are to the spot price at the Henry Hub and are in nominal dollars.
5. Analytical Perspectives, Budget of the United States Government, Fiscal Year 2002, U.S. Government Printing Office, Washington, DC, 2001, p. 6
6. An independent producer is any producer who is not a "retailer" or "refiner." A retailer is any person who directly, or through a related person, sells oil or natural gas or any product derived therefrom (1) through any retail outlet operated by the taxpayer or related person, or (2) to any person that is obligated to market or distribute such oil or natural gas (or product derived therefrom) under the name of the taxpayer or the related person, or that has the authority to occupy any retail outlet owned by the taxpayer or a related person. Bulk sales of crude oil and natural gas to commercial or industrial users, and bulk sales of aviation fuel to the Department of Defense, are not treated as retail sales for this purpose. Further, a person is not a retailer within the meaning of this provision if the combined gross receipts of that person and all related persons from the retail sale of oil, natural gas, or any product derived therefrom do not exceed $5 million for the taxable year. A refiner is any person who directly or through a related person engages in the refining of crude oil, but only if such person or related person has a refinery run in excess of 50,000 barrels per day on any day during the taxable year.
7. By contrast, for any other mineral qualifying for the percentage depletion deduction, the deduction may not exceed 50 percent of the taxpayer’s taxable income from the depletable property.
8. Amounts disallowed as a result of this rule may be carried forward and deducted in subsequent taxable years, subject to the 65-percent-of-taxable-income limitation for those years.
9. Equivalent barrels is computed as the sum of (1) the number of barrels of crude oil produced, and (2) the number of cubic feet of natural gas produced divided by 6,000. If a well produced 10 barrels of crude oil and 12,000 cubic feet of natural gas, its equivalent barrels produced would equal 12 (i.e., 10 + (12,000 / 6,000)).
10. IDCs include all expenditures made by an operator for wages, fuel, repairs, hauling, supplies, etc., incident to and necessary for the drilling of wells and the preparation of wells for the production of oil and gas. In addition, IDCs include the cost to operators of any drilling or development work (excluding amounts payable only out of production or gross or net proceeds from production, if the amounts are depletable income to the recipient, and amounts properly allocable to the cost of depreciable property) done by contractors under any form of contract (including a turnkey contract). Such work includes labor, fuel, repairs, hauling, and supplies which are used in the drilling, shooting, and cleaning of wells; in such clearing of ground, draining, road making, surveying, and geological works as are necessary in preparation for the drilling of wells; and in the construction of such derricks, tanks, pipelines, and other physical structures as are necessary for the drilling of wells and the preparation of wells for the production of oil and gas. Generally, IDCs do not include expenses for items which have a salvage value (such as pipes and casings) or items which are part of the acquisition price of an interest in the property.
11. The IRS has ruled that if an integrated oil company ceases to be an integrated oil company, it may not immediately write off the unamortized portion of the IDCs capitalized under this rule, but instead must continue to amortize those IDCs over the 60-month amortization period.
12. In the case of IDCs paid or incurred with respect to an oil or gas well located outside of the United States, the costs, at the election of the taxpayer, are either (1) included in adjusted basis for purposes of computing the amount of any deduction allowable for cost depletion or (2) capitalized and amortized ratably over a 10-year period beginning with the taxable year such costs were paid or incurred.
13. The term "United States" for this purpose includes the seabed and subsoil of those submerged lands that are adjacent to the territorial waters of the United States and over which the United States has exclusive rights, in accordance with international law, with respect to the exploration and exploitation of natural resources (i.e., the Continental Shelf area).
14. A barrel-of-oil equivalent generally means that amount of the qualifying fuel which has a Btu (British thermal unit) content of 5.8 million.
15. A facility that produces gas from biomass or produces liquid, gaseous, or solid synthetic fuels from coal (including lignite) generally will be treated as being placed in service before January 1, 1993, if it is placed in service by the taxpayer before July 1, 1998, pursuant to a written binding contract in effect before January 1, 1997. In the case of a facility that produces coke or coke gas, however, this provision applies only if the original use of the facility commences with the taxpayer. Also, the IRS has ruled that production from certain post-1992 "recompletions" of wells that were originally drilled prior to the expiration date of the credit would qualify for the section 29 credit.
16. If a facility that qualifies for the binding contract rule is originally placed in service after December 31, 1992, production from the facility may qualify for the credit if sold to an unrelated person before January 1, 2008.
17. The inflation adjustment factor for the 2000 taxable year was 2.0454. Therefore, the inflation-adjusted amount of the credit for that year was $6.14 per barrel or barrel equivalent.
18. For 2000, the inflation adjusted threshold for onset of the phaseout was $48.07 ($23.50 x 2.0454) and the average wellhead price for that year was $26.73.
19. The average per-barrel price of crude oil for this purpose is determined in the same manner as for purposes of the section 29 credit.
20. In the case of an integrated oil company, the credit base includes those IDCs which the taxpayer is required to capitalize.
21. This provision applies to individuals, estates, trusts, personal service corporations, and closely held C corporations.