GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

United States General Accounting Office

Washington, DC 20548

Resources, Community, and

Economic Development Division

B-286311

September 25, 2000

The Honorable Tom Harkin

Ranking Minority Member

Committee on Agriculture,

 Nutrition, and Forestry

United States Senate

Subject: Petroleum and Ethanol Fuels: Tax Incentives and Related GAO Work

Dear Senator Harkin:

Over the years, the federal government has granted tax incentives, direct subsidies, and other

support to the petroleum industry, as well as some tax and other benefits to the ethanol

industry, in an effort to enhance U.S. energy supplies. The tax incentives generally decrease

revenues accruing to the U.S. Treasury. In earlier reports, we addressed various issues

related to these incentives, including their impact on federal revenues and effectiveness in

accomplishing their objectives.

You requested that we provide you with information on the tax incentives1

 that benefit the

petroleum and ethanol2

 industries. Accordingly, we are providing revenue loss estimates for

tax incentives designed to encourage the exploration and production of petroleum and the

production of ethanol (see enc. I). In addition to this specific information, we are providing a

summary of key findings from our earlier reports on these and related issues (see enc. II).

We used the enclosed material to brief your staff on June 30, 2000. A summary of the tax

incentive information follows.

 1

Tax incentives are federal tax provisions that grant special tax relief designed to encourage certain kinds of behavior by

taxpayers or to aid taxpayers in special circumstances. The revenue losses that result from these provisions--called tax

expenditures--may, in effect, be viewed as spending channeled through the tax system. The Congressional Budget and

Impoundment Control Act of 1974 requires that a list of tax expenditures be included in the budget. The act defines “tax

expenditures” as “revenue losses attributable to provisions of Federal tax laws which allow a special exclusion, exemption, or

deduction from gross income or which provide a special credit, a preferential rate of tax, or a deferral of tax liability.” Each

year, estimates of tax expenditure revenue losses are prepared by the Department of the Treasury and by the staff of the Joint

Committee on Taxation. According to the Committee, these special income tax provisions are referred to as tax expenditures

because they may be considered as analogous to direct outlay programs, and the provisions and programs can be considered as

alternative means of accomplishing similar budget policy objectives.

2

Under the Internal Revenue Code, a tax exemption and/or tax credits are available for any biomass-derived alcohol fuel,

including ethanol and methanol. However, alcohol fuel derived from petroleum or natural gas does not qualify for the

exemption or the credits.
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2 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Table 1 shows inflation-adjusted summations of estimated revenue losses for petroleum and

ethanol fuel tax incentives from 1968 to 2000. We developed these data from unadjusted

annual revenue loss estimates made by the Department of the Treasury and the staff of the

Joint Committee on Taxation (JCT).3

 Specific petroleum tax incentives range from about

$330 million for the expensing of tertiary injectants4

 (1980-2000) to about $82 billion for

certain cost depletion deductions (1968-2000). Some of the tax incentives for the petroleum

industry have been in place for many decades, but over the past 25 years, these incentives

have generally been scaled back.

Table 1: Tax Incentives for Petroleum and Ethanol Fuels: Estimates of Revenue Losses Over Time

Dollars in millions

Tax incentive Summed over years Adjusted to year 2000 dollars

Petroleum industry

Excess of percentage over cost depletiona 1968-2000 $81,679-$82,085

Expensing of exploration and development

costsa

1968-2000 42,855-54,580

Alternative (nonconventional) fuel production

credit

1980-2000 8,411-10,542

Oil and gas exception from passive loss

limitation

1988-2000 1,065b

Credit for enhanced oil recovery costs 1994-2000 482-1,002

Expensing of tertiary injectants 1980-2000 330c

Ethanol industry

Partial exemption from the excise tax for

alcohol fuels

1979-2000 7,523-11,183

Income tax credits for alcohol fuels 1980-2000 198-478

Note: When two figures are provided for an incentive, they represent the estimates developed from Treasury’s and JCT’s data.

The lower figure is presented first, regardless of which agency’s data it is based on. Some of the estimated revenue losses for

the tax incentives have a considerable range because of, among other things, (1) differences between Treasury’s and JCT’s

estimates of individual and corporate gross income, deductions and expenditures, and (2) differences in the lower bound for

the annual revenue loss estimates they present. See enclosure I for details.

a

In some years, revenue losses associated with other fuels and nonfuel minerals were included with revenue losses from oil

and gas. See enclosure I for details.

b

There is no JCT revenue estimate because only Treasury recognizes this tax code provision as a separate tax incentive. See

enclosure I for details.

c

There is no Treasury revenue estimate because only JCT recognizes this tax code provision as a separate tax incentive. See

enclosure I for details.

Source: GAO’s compilations based on annual estimates of tax expenditures published by Treasury and JCT.

Ethanol fuel tax incentives ranged from $198 million for alcohol fuel tax credits (1980-2000)

to about $11 billion for the excise tax exemption for alcohol fuels (1979-2000). These tax

incentives were instituted in 1979-80. In the past decade, these incentives have been

extended, but the rates of exemption and credit have been reduced somewhat.

 3

For each tax incentive, the years over which we report annual revenue loss estimates are limited to the years for which both

Treasury and JCT made estimates. Thus, the first year is the first period for which revenue loss estimates are available from

both Treasury and JCT; it may not be the year when the incentive was first implemented. Estimates include both corporate and

individual income tax revenue losses except for the partial exemption from the excise tax for alcohol fuels, which represents

revenue losses from the federal excise tax on gasoline.

4

Tertiary injectants are fluids, gases, and other chemicals that are pumped into oil and gas reservoirs to extract reserves that

cannot be extracted by conventional primary or secondary recovery techniques.
B-286311

3 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

The estimated revenue losses for these tax incentives should not be added together. The

estimate for each tax incentive is made independently of any other tax incentive, and the

effect of making more than one change might be greater than or less than the sum of the

changes. Enclosure I contains more detailed information on these estimates of revenue

losses from the petroleum and ethanol tax incentives (see tables 2-9), as well as descriptions

of the incentives and summaries of their legislative histories.

Scope and Methodology

To prepare the information for this report, we compiled Treasury’s and JCT’s yearly revenue

loss estimates for tax incentives received by the petroleum and ethanol industries.

Treasury’s estimates are from annual editions of the Budget of the United States Government,

Analytical Perspectives volume, Tax Expenditures section. JCT’s estimates are from annual

editions of the Estimates of Federal Tax Expenditures. To put the dollar amounts for

different years on a comparable basis, we adjusted these estimates for inflation, using a fiscal

year gross domestic product (GDP) deflator.5

 Descriptions of the tax incentives and their

legislative histories are from JCT’s Present-Law Tax Rules Relating to Domestic Oil and Gas

Exploration and Production and Description of H.R. 53 and H.R. 423 (JCX-8-99, Feb. 23, 1999)

and the Senate Committee on the Budget’s Tax Expenditures: Compendium of Background

Material on Individual Provisions (Dec. 1996). Additionally, we reviewed and summarized

previous GAO studies related to petroleum and ethanol tax incentives and other subsidy

programs. We conducted our work from July through September 2000 in accordance with

generally accepted government auditing standards.

- - - - -

Unless you publicly announce its contents earlier, we plan no further distribution of this

report until 14 days after the date of this letter. At that time, we will send copies to interested

Members of Congress and make copies available to others on request.

If you have any questions about this report or need additional information, please call Daniel

Haas or Godwin Agbara at (202) 512-3841.

Sincerely yours,

Jim Wells

Director, Energy, Resources,

 and Science Issues

Enclosures - 2

 5

The deflator was obtained from the Budget of the United States Government, Fiscal Year 2001, Historical Tables volume, table

10.1.
Enclosure I

4 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Tax Incentives for Petroleum and Ethanol Fuels:

Descriptions, Legislative Histories, and Revenue Loss Estimates

Activities associated with exploring for and producing petroleum--crude oil and natural gas--

within the United States receive several types of favorable tax treatment. The production of

alcohol fuels, such as ethanol, also receives favorable tax treatment. Tax incentives for

petroleum and ethanol take the form of special exemptions, deductions, credits, and deferrals of

tax. Tax incentives result in revenue losses to the federal government. As a result, they may be

viewed as spending programs channeled through the tax system.

Enclosure I contains yearly estimates of revenue losses for the petroleum and ethanol tax

incentives, both unadjusted and adjusted for inflation (see tables 2-9). Also included are a

description and a summary of the legislative history of each tax incentive associated with the

petroleum and ethanol industries.

We use both Treasury’s and JCT’s estimates because they differ in some respects. For example,

Treasury and JCT use slightly different classifications of tax code incentives for petroleum. In

addition, their revenue loss estimates depend on their respective estimates and/or projections of

taxpayers’ gross income, deductions, and spending patterns.1

Also, Treasury and JCT differ in

the way they present their annual revenue loss estimates. Treasury reports its estimates in

millions of dollars. In contrast, after 1985, JCT reports its estimates in billions of dollars

(rounded to one decimal point) and does not report an estimate in years when the estimate is

less than $50 million (in current year dollars). For Treasury, our sources are annual editions of

the Budget of the United States Government. For JCT, our sources are the Committee staff’s

annual Estimates of Federal Tax Expenditures.

2

We provide both unadjusted and inflation-adjusted annual revenue loss estimates for those who

may find it helpful to see the magnitudes of the amounts involved each year. The unadjusted

estimates we used are those most recently published by Treasury or JCT for each year.3

We

adjusted these estimates for inflation in order to put the estimates for earlier years on a

comparable basis with the estimates for later years. This allowed us to sum the estimates over

time. We do not provide summations over time of dollar figures that have not been adjusted for

inflation because we do not consider it appropriate to sum dollar figures over a long period of

time if they have not been adjusted for inflation. We adjusted these estimates for inflation using

a fiscal year gross domestic product (GDP) deflator, which we obtained from the Budget of the

United States Government, Fiscal Year 2001, Historical Tables volume, Table 10.1.

We do not add revenue losses from different tax incentives because it is not appropriate to do so.

The estimate for each tax incentive is made separately, assuming that all other tax incentives

1

JCT’s tax expenditure revenue loss estimates are always forecasts. JCT does not later re-estimate tax expenditure revenue losses on

the basis of the actual economic conditions prevailing at the time. Thus, the JCT estimates we used were based on projected, rather

than actual, economic conditions.

2

For each tax incentive, the years over which we report annual revenue loss estimates are generally limited to the years for which

both Treasury and JCT have made estimates. Estimates are for both corporate and individual income tax revenue losses except in

table 8, which contains revenue losses from the federal excise tax on gasoline.

3

We report annual estimates when available. However, when JCT does not provide an annual revenue loss figure because it estimates

a tax incentive’s revenue loss to be below $50 million in that year, if they provide a 5-year revenue loss estimate, we calculate and

report the average annual loss.
Enclosure I

5 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

remain in the tax code. If two or more incentives were estimated simultaneously, the total

change in tax liability might have a lesser or a greater effect on revenue than the sum of the

amounts shown for each item separately. Neither Treasury nor JCT considers it appropriate to

add revenue loss estimates for different tax incentives.

We note that a revenue loss estimate for a tax incentive--or tax expenditure--is not equivalent to a

revenue estimate for the repeal of that tax expenditure because the two may be confused. A

revenue loss estimate for a tax expenditure is measured by the difference between the tax

liability under present law and the tax liability that would result from a recomputation of tax

assuming that particular tax expenditure did not exist. For the purpose of estimating a tax

expenditure, taxpayer behavior is assumed to remain unchanged. For example, Treasury’s and

JCT’s tax expenditure estimates do not account for any effects that changes to that tax

expenditure might have on investment patterns, consumption, or other aspects of economic

activity. Because tax expenditure estimates do not account for such effects, they do not measure

the amount by which government revenue would change if the tax expenditure were changed.

When Treasury or JCT’s staff do make a revenue estimate for the repeal of a tax expenditure,

they incorporate the effects of the behavioral changes that are anticipated to occur in response

to the repeal of that tax provision.

Excess of Percentage Over Cost Depletion, for Oil and Gas

Independent oil and gas producers and royalty owners are generally allowed to take percentage

depletion deductions rather than cost depletion deductions on limited quantities of domestic

output.

Description

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

investment includes the costs of discovering, purchasing, and developing an oil or a gas reserve.

In both cases, a taxpayer is allowed a deduction because an asset is being expended to produce

income. In the case of depletion for oil and gas, the oil or gas reserve itself is being expended in

order to produce income.

Two methods of depletion are currently allowable under the Internal Revenue Code (IRC)--cost

depletion and percentage depletion. Under cost depletion, the taxpayer recovers the actual

capital investment over the period during which the reserve produces income. Each year, the

taxpayer deducts a portion of the original capital investment, less previous deductions, that is

equal to the fraction of the estimated remaining recoverable reserves that have been extracted

and sold that year. The overall amount recovered under cost depletion can never exceed the

taxpayer's original capital investment.

Under percentage depletion, the deduction for the recovery of the capital investment is a fixed

percentage of the gross income--sales revenue--from the sale of the oil or gas. Because

percentage depletion, unlike cost depletion, is computed without regard to the taxpayer's actual

capital investment in the depletable property, cumulative depletion deductions may be greater

than the amount spent by the taxpayer to acquire or develop the property. Currently, under

percentage depletion, 15 percent of the gross income from certain oil- or gas-producing property

is allowed as a deduction in each taxable year.4

Information on percentage depletion for oil and

gas properties can be found in IRC sections 611, 612, 613, and 613A.

4

Currently, only independent oil and gas producers and royalty owners--those producing less than 50,000 barrels per day--are allowed

to take percentage depletion and only on up to 1,000 barrels of oil output, or its equivalent in gas, per day. The amount deducted
Enclosure I

6 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Legislative History

As part of the Tariff Act of 1913, a “reasonable allowance for depletion,” not to exceed 5 percent

of the value of output, was permitted as a tax deduction for oil and gas and other minerals.

Treasury regulation number 33 limited total deductions to the amount of the original capital

investment. Between 1918 and 1926, depletion was allowed, based on the market value of the

deposit after discovery, which could exceed the value of the original capital investment. The

Revenue Act of 1926 replaced discovery-value depletion with percentage depletion limited to 27.5

percent of the gross income from an oil- or a gas-producing property.

Beginning with the Tax Reform Act of 1969, several changes to the tax code have reduced the

ability of oil and gas producers to use percentage depletion. In 1969, the top depletion rates were

reduced to 22 percent. The 1969 act also made percentage depletion subject to a minimum tax

starting in 1970.5

The Tax Reduction Act of 1975 repealed the deduction for percentage depletion with respect to

much oil and gas production and reduced the rate of depletion on the remaining eligible

production. Following the 1975 act, major integrated oil producers 6 were no longer allowed to

claim the percentage depletion allowance. And, starting in 1984, independent producers and

royalty owners were allowed to claim percentage depletion on only 15 percent of gross income

from the sale of oil or gas. The Tax Reform Act of 1986 denied percentage depletion for lease

bonuses, advance royalties, or other payments unrelated to actual oil and gas production.

The Omnibus Budget Reconciliation Act of 1990 increased the statutory percentage depletion

rate for oil and gas production from marginal properties--that is, “stripper well” properties or

properties producing mostly “heavy oil”--held by independent producers or royalty owners. The

1990 act also raised the limit on the amount deducted from 50 percent to 100 percent of the net

income from the property in any year and made percentage depletion available to transferred

properties. The Energy Policy Act of 1992 repealed the alternative minimum tax (AMT) on

percentage depletion for oil and gas.

Revenue Losses

Table 2 contains estimates of annual revenue losses for this tax incentive, both unadjusted and

adjusted for inflation. Between 1968 and 1980, revenue losses associated with other fuels and

nonfuel minerals were included with revenue losses for oil and gas. After 1980, revenue losses

included only those for oil and gas.

generally may not exceed 100 percent of the net income from that property in any year. Additionally, the percentage depletion

deduction for all oil and gas properties may not exceed 65 percent of the taxpayer's overall taxable income in any year.

5

In 1969, the Congress enacted an add-on minimum tax that served as the predecessor to the current alternative minimum tax (AMT).

The minimum tax was amended a number of times, including in 1976, 1978, 1982, 1986, 1990, and 1993. Through these amendments,

the minimum tax was changed from essentially a surcharge on certain tax preference items (i.e., items excludable from taxable

income under the regular income tax but taxable under the minimum tax) to a separate tax system—the AMT. The AMT, in general,

parallels the regular income tax system, having its own definitions of income subject to tax and its own tax rates. The AMT, like its

predecessor the minimum tax, in effect limits the use of certain tax incentives available under the regular income tax.

6

An integrated oil producer is generally a producer that is not an independent producer.
Enclosure I

7 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Table 2: Revenue Loss Estimates for the Excess of Percentage Over Cost Depletion, Oil and Gas

Dollars in millions

JCT Treasury

Fiscal year

Not adjusted for

inflation

Adjusted to

2000 dollarsa

Not adjusted for

inflation

Adjusted to

2000 dollarsa

1968 $1,300 $5,279 $1,300 $5,279

1969 1,430 5,559 1,430 5,559

1970 1,470 5,424 1,470 5,424

1971 980 3,438 980 3,438

1972 985 3,296 985 3,296

1973 1,700 5,439 1,700 5,439

1974 2,120 6,333 2,120 6,333

1975 2,475 6,724 2,475 6,724

1976 1,580 4,004 1,295 3,282

1977 1,310 3,079 1,395 3,279

1978 1,460 3,214 1,500 3,302

1979 1,625 3,318 1,830 3,737

1980 2,130 4,005 1,490 2,802

1981 2,125 3,645 1,865 3,199

1982 1,970 3,163 2,100 3,372

1983 1,800 2,766 1,280 1,967

1984 1,215 1,800 1,175 1,740

1985 1,140 1,635 1,355 1,944

1986 1,300 1,822 1,105 1,548

1987 700 956 725 990

1988 500 661 450 595

1989 400 509 390 497

1990 300 368 650 797

1991 400 473 555 656

1992 500 578 885 1,023

1993 100 113 995 1,122

1994 600 661 785 865

1995 600 648 945 1,020

1996 400 424 1,125 1,191

1997 600 625 830 864

1998 500 514 250 257

1999 500 507 265 269

2000 700 700 275 275

Total b$81,679 b$82,085

a

Data were adjusted for inflation by GAO.

b

Not applicable. GAO does not consider it appropriate to sum dollar figures that are unadjusted for inflation over several years.

Expensing of Exploration and Development Costs, for Oil and Gas

Independent oil and gas producers are generally allowed to expense--deduct from gross income

in the period incurred, rather than over the productive life of a property--intangible drilling and

development costs, associated with successful investments in domestic oil and gas wells.

Integrated companies can expense 70 percent of such costs and must deduct the remaining 30

percent over 5 years.

Description

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

for income tax purposes, rather than being expensed in the period they are incurred. However,
Enclosure I

8 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

special rules have been provided for the treatment of certain intangible drilling costs and other

intangible exploration and development costs, commonly referred to as “IDCs.” IDCs include all

spending by an operator or contractor for labor, fuel, repairs, hauling, supplies, and other items

incident to and necessary for the drilling of wells and the preparation of wells for the production

of oil and gas.7

Under the special rules for intangible costs, an operator or owner of a working

interest that pays or incurs IDCs may elect to expense rather than capitalize those costs for

property located in the United States, including certain wells drilled offshore.8

The excess of expensed IDCs over their capitalized value is a tax preference item that is subject

to the AMT, to the extent that it exceeds 65 percent of the net income from the property.

Independent producers are required to include only 70 percent of their IDCs as a tax preference

item. Information on the expensing of exploration and development costs for oil and gas

properties can be found in IRC sections 263(c), 291, 616-617, 57(2), and 1254.

Legislative History

Expensing for IDCs was originally established in a 1916 Treasury regulation, number 45, article

223, which stated that such costs were ordinary operating expenses. Expensing for IDCs was

subsequently codified in the IRC of 1954.

The Tax Reform Act of 1976 made expensing for IDCs subject to the minimum tax. Under the

1976 act, the difference between the amount of a taxpayer's IDC deductions and the amount that

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

period became subject to minimum taxation provisions.

The Tax Equity and Fiscal Responsibility Act of 1982 limited the expensing of IDCs for integrated

oil companies to 85 percent of IDCs and required the remaining 15 percent to be deducted over 3

years. The Deficit Reduction Act of 1984 further limited such expensing for integrated

companies to 80 percent. The Tax Reform Act of 1986 repealed the expensing of IDCs for foreign

properties and further limited such expensing for integrated companies to 70 percent. The

Energy Policy Act of 1992 repealed AMT coverage of IDCs for taxpayers other than integrated

companies and limited AMT coverage for integrated companies to 70 percent of IDCs.

Revenue Losses

Table 3 contains estimates of annual revenue losses for this tax incentive, both unadjusted and

adjusted for inflation. Estimates are negative numbers in some years.9

Between 1968 and 1980,

7

Amounts paid for items that have a salvage value, such as pipe, casings, valves and other tangible equipment, or for equipment used

on foreign properties cannot be expensed but must be recovered over time through depletion or depreciation.

8

If IDCs are not expensed but are capitalized, they may be recovered through depletion or depreciation as appropriate. For a

nonproductive well or "dry hole," IDCs may be deducted.

9

Allowing petroleum exploration and development costs to be expensed in the period they are incurred rather than requiring that they

be capitalized and depreciated over time constitutes a deferral of taxes. The methodology used by Treasury and JCT for estimating

the annual values of tax provisions that are deferrals of taxes may not accurately reflect the true economic costs of those provisions.

Treasury and JCT use the same method for estimating the annual value of a tax provision that is a deferral of taxes. They report the

difference between the total amount of taxes deferred through that provision in the current year, aggregated across taxpayers, and

the total amount of incoming revenues that are received due to the deferrals in prior years through that provision, aggregated across

taxpayers. Although such an estimate is useful as an estimate of the cash flow into the government for that tax provision, it does not

accurately reflect the true economic cost of that provision. A feature of tax deferrals, is that they can cause the tax expenditure to be

negatively valued in some years. For, example, for a provision where activity levels have declined, so that incoming tax receipts from

past deferrals are greater than deferred receipts from new activity, the cash-basis tax expenditure estimate will be negative. A

negative tax expenditure implies an increase in government revenues in that year. However, in present-value terms, current deferrals

do have a real, positive cost to the government. For Treasury's discussion of this issue, see the Budget of the United States
Enclosure I

9 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

revenue losses associated with other fuels and nonfuel minerals were included with the revenue

losses for oil and gas. After 1980, revenue losses included only those for oil and gas.

Table 3: Revenue Loss Estimates for the Expensing of Exploration and Development Costs, Oil and Gas

Dollars in millions

JCT Treasury

Fiscal year

Not adjusted for

inflation

Adjusted to

2000 dollarsa

Not adjusted for

inflation

Adjusted to

2000 dollarsa

1968 $300 $1,218 $300 $1,218

1969 330 1,283 330 1,283

1970 340 1,255 340 1,255

1971 325 1,140 325 1,140

1972 325 1,087 325 1,087

1973 650 2,080 650 2,080

1974 830 2,479 830 2,479

1975 620 1,684 620 1,684

1976 805 2,040 800 2,027

1977 715 1,681 1,030 2,421

1978 1,185 2,608 1,390 3,060

1979 1,490 3,043 1,745 3,563

1980 2,190 4,118 2,175 4,090

1981 2,735 4,691 3,525 6,046

1982 4,070 6,534 3,430 5,507

1983 1,535 2,359 3,160 4,856

1984 1,810 2,681 1,415 2,096

1985 2,210 3,170 585 839

1986 2,300 3,223 -510 -715

1987 2,700 3,686 -675 -921

1988 -600 -793 -385 -509

1989 -300 -382 -65 -83

1990 100 123 -500 -613

1991 200 237 -315 -373

1992 600 694 125 145

1993 200 226 185 209

1994 500 551 -85 -94

1995 500 540 -300 -324

1996 100 106 -210 -222

1997 200 208 -160 -167

1998 200 206 -110 -113

1999 400 406 -80 -81

2000 400 400 -15 -15

Total b$54,580 b$42,855

a

Data were adjusted for inflation by GAO.

b

Not applicable.

Alternative (Nonconventional) Fuel Production Credit

A nontaxable credit is provided for the production of several forms of alternative fuels.

Government, Fiscal Year 2001, Analytical Perspectives volume, page 108, section on "Interpreting Tax Expenditure Revenue

Estimates." For JCT’s discussion of this issue, see JCT’s Estimates of Federal Tax Expenditures for Fiscal Years 2000-2004, pages 11-

12, section on "Tax Expenditure Estimates Generally."
Enclosure I

10 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Description

Taxpayers that produce certain qualifying fuels from nonconventional sources, including some

types of oil and gas, are eligible for a tax credit equal to $3 per barrel or Btu oil barrel

equivalent.10 The credit is generally available if the price of oil stays below $29.50 per barrel,

adjusted to 1979 dollars. The credit generally expires on December 31, 2002.

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;11 and (3) various synthetic fuels produced from coal. Fuels qualifying for the credit

must be produced domestically from a well drilled or a facility placed in service before January 1,

1993. The tax credit generally is available for qualified fuels sold to unrelated persons before

January 1, 2003. The amount of the credit generally is multiplied by an inflation adjustment

factor for the calendar year in which the sale occurs.

The credit is offset by benefits from government grants, subsidized or tax-exempt financing,

energy investment credits, and the enhanced oil recovery credit. The credit is nonrefundable and

may not be used to offset AMT liability. Information on the tax credit for producing alternative

fuels can be found in IRC section 29.

Legislative History

The alternative fuel production credit was adopted as part of the Crude Oil Windfall Profit Tax

Act of 1980, with an original placed-in-service deadline of 1989.

Revenue Losses

Table 4 contains estimates of annual revenue losses for this tax incentive, both unadjusted and

adjusted for inflation.

10A BTU oil barrel equivalent is that amount of a qualifying fuel that has a British thermal unit content of 5.8 million.

11Biomass is any organic material other than oil, natural gas, or coal, or any product thereof.
Enclosure I

11 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Table 4: Revenue Loss Estimates for the Alternative (Nonconventional) Fuel Production Credit

Dollars in millions

JCT Treasury

Fiscal year

Not adjusted for

inflation

Adjusted to

2000 dollarsa

Not adjusted for

inflation

Adjusted to

2000 dollarsa

1980 $4 $8 $5 $9

1981 25 43 25 43

1982 95 153 15 24

1983 5 8 10 15

1984 10 15 10 15

1985 25 36 10 14

1986 20 28 20 28

1987 20 27 10 14

1988 20 26 10 13

1989 20 25 10 13

1990 20 25 10 12

1991 20 24 255 302

1992 400 462 680 786

1993 800 902 760 857

1994 1,000 1,102 900 992

1995 1,100 1,187 970 1,047

1996 1,000 1,059 570 604

1997 1,300 1,354 710 739

1998 1,400 1,439 860 884

1999 1,300 1,319 1,025 1,040

2000 1,300 1,300 960 960

Total b$10,542 b$8,411

a

Data were adjusted for inflation by GAO.

b

Not applicable.

Oil and Gas Exception From Passive Loss Limitation

Owners of working interests in oil and gas properties are exempt from the passive income

limitations.

Description

A taxpayer's deductions from passive trade or business activities, to the extent they exceed

income from all such passive activities of the taxpayer (not including portfolio income),

generally may not be deducted against other, nonpassive income. Thus, for example, an

individual taxpayer generally may not deduct losses from a passive activity against income from

wages.12

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 regular, continuous, and substantial basis. However, a working

interest in an oil or a gas property generally is not treated as a passive activity, whether or not

the taxpayer materially participates in the activities related to that property. Moreover, the

12Losses suspended under this passive activity loss limitation may be carried forward and treated as deductions from passive activities

in the following year and thus may offset any income from passive activities generated in that later year. Suspended losses from a

passive activity generally may be deducted in full when a taxpayer disposes of his or her entire interest in that activity.
Enclosure I

12 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

passive activity rules—and, consequently, the oil and gas working interest exception to those

rules—apply to the utilization of tax credits such as the nonconventional fuels production credit

and the enhanced oil recovery credit. Information on exceptions to the passive activity rules for

working interests in oil or gas properties can be found in IRC section 469.

Legislative History

The rules on passive activity losses and the exception to these rules for working interests in oil

and gas properties were included in the Tax Reform Act of 1986.

Revenue Losses

Table 5 contains estimates of annual revenue losses for this tax incentive, both unadjusted and

adjusted for inflation. Revenue loss estimates are available only from Treasury because JCT

does not view exceptions to passive loss activity rules as a separate tax incentive. The passive

loss activity rules have the effect of reducing the magnitude of the tax incentives to which they

apply. Exceptions to the passive loss rules have the effect of restoring the magnitude of the tax

incentives to which they apply. JCT incorporates revenue losses for exceptions to passive loss

rules into its estimates of revenue losses for other tax incentives.

Table 5: Revenue Loss Estimates for the Oil and Gas Exception From Passive Loss Limitation

Dollars in millions

Treasury

Fiscal year Not adjusted for inflation Adjusted to 2000 dollarsa

1988 $55 $73

1989 135 172

1990 180 221

1991 80 95

1992 90 104

1993 50 56

1994 90 99

1995 55 59

1996 50 53

1997 45 47

1998 30 31

1999 30 30

2000 25 25

Total b$1,065

a

Data were adjusted for inflation by GAO.

b

Not applicable.

Credit for Enhanced Oil Recovery Costs

A credit is provided for qualified tertiary oil recovery costs incurred in the production of oil and

gas on U.S. projects.

Description

Taxpayers are permitted to claim a general business credit for a taxable year, one component of

which is the enhanced oil recovery (EOR) credit. The credit is equal to 15 percent of certain

costs attributable to EOR projects undertaken by a taxpayer in the United States during a taxable
Enclosure I

13 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

year. Qualifying costs include tertiary injectant expenses, intangible drilling and development

costs on a qualified EOR project, and amounts incurred for tangible depreciable property. To the

extent that the EOR 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, with respect to these costs. As part of the general business credit, this credit

may not be used to offset AMT liability.13

The amount of the EOR credit is reduced in a taxable year following a calendar year during

which the annual average price per barrel for domestic crude oil from an unregulated wellhead

exceeds a $28 threshold (adjusted for inflation). If the average unregulated wellhead price

exceeds the threshold amount, the credit will be reduced ratably over a $6 phaseout range. The

EOR 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. Information on

the tax credit for enhanced oil recovery costs can be found in IRC section 43.

Legislative History

The enhanced oil recovery costs tax credit was enacted by the Omnibus Budget and

Reconciliation Act of 1990.

Revenue Losses

Table 6 contains estimates of annual revenue losses for this tax incentive, both unadjusted and

adjusted for inflation.

Table 6: Revenue Loss Estimates for the Credit for Enhanced Oil Recovery Costs

Dollars in millions

JCT Treasury

Fiscal year

Not adjusted for

inflation

Adjusted to

2000 dollarsa

Not adjusted for

inflation

Adjusted to

2000 dollarsa

1994 $60 $66 $85 $94

1995 80 86 85 92

1996 60 64 80 85

1997 80 83 95 99

1998 60 62 140 144

1999 60 61 225 228

2000 60 60 260 260

Total b$482 b$1,002

a

Data were adjusted for inflation by GAO.

b

Not applicable.

Expensing of Tertiary Injectants

A deduction is provided for qualified spending incurred for certain tertiary injectants used in the

production of oil and gas in the tax year in which such substances are injected.

13The general business credit is limited under the AMT. The general business credit for a taxable year may not exceed the excess (if

any) of the taxpayer's net income over the greater of (1) the tentative minimum tax or (2) 25 percent of so much of the taxpayer's net

regular tax liability as exceeds $25,000. Any unused general business credit generally may be carried back 3 taxable years and carried

forward 15 taxable years.
Enclosure I

14 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Description

Tertiary oil and gas recovery projects inject fluids, gases, and other chemicals into the oil and gas

reservoir to extract oil too viscous to be extracted by conventional primary and secondary waterflooding techniques. Nine tertiary recovery methods qualify for expensing—that is, deducting

costs when incurred. Expenditures for qualified tertiary injectants also qualify for the 15-percent

EOR credit, although the credit must be subtracted from the deduction if both are claimed for the

same expenditure.

The tax incentive for tertiary injectant spending is a tax deferral. As with certain exploration and

development expenditures, the tax law allows certain tertiary injectant spending to be expensed

rather than capitalized and deducted over the income-producing life of the oil or gas property.

Information on the tax treatment of costs incurred for tertiary injectants used in producing oil or

gas can be found in IRC section 193.

Legislative History

The expensing of tertiary injectants incentive was enacted as part of the Crude Oil Windfall Profit

Tax Act of 1980.

Revenue Losses

Table 7 contains estimates of annual revenue losses for this tax incentive, both unadjusted and

adjusted for inflation. Revenue loss estimates are available only from JCT because Treasury

does not consider the expensing of tertiary injectants to be a tax incentive.
Enclosure I

15 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Table 7: Revenue Loss Estimates for the Expensing of Tertiary Injectants

Dollars in millions

JCT

Fiscal year Not adjusted for inflation Adjusted to 2000 dollarsa

1980 $4 $8

1981 14 24

1982 9 14

1983 8 12

1984 7 10

1985 6 9

1986 0b0

1987 0b0

1988 20 26

1989 20 25

1990 20 25

1991 20 24

1992 20 23

1993 20 23

1994 20 22

1995 20 22

1996 20 21

1997 20 21

1998 20 21

1999 0c0

2000 0c0

Total d$330

a

Data were adjusted for inflation by GAO.

b

Estimated revenue loss of less than $10 million.

c

Estimated revenue loss of less than $50 million over this year plus the following 4 years.

d

Not applicable.

Partial Exemption From the Excise Tax for Alcohol Fuels

A partial exemption from the federal excise tax on motor fuels is provided for alcohol fuels,

including ethanol, that are derived from biomass materials and used as fuel.

Description

The partial exemption from the federal excise tax on gasoline, diesel fuel, and other motor fuels

applies to biomass alcohol—ethanol and methanol derived from renewable resources. Alcohol

derived from petroleum, natural gas, or coal does not qualify for the exemption. The size of the

partial exemption depends on how much and what type of alcohol is contained in each gallon of

fuel. Most of the fuel mixtures that have received excise tax exemptions have been mixtures of

gasoline and ethanol.14

Currently, motor fuels consisting of at least 10 percent biomass-derived ethanol are exempt from

5.4 cents of the 18.4-cents-per-gallon federal excise tax. The exemption is also available at lower

14In 1995, for example, virtually all of the federal excise tax exemptions for alcohol fuels claimed were for fuel mixtures of gasoline

and ethanol.
Enclosure I

16 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

rates per gallon of fuel for blends that are at least 7.7 percent or 5.7 percent ethanol. For all of

these fuel blends, the exemptions provide a subsidy of 54 cents per gallon of ethanol used. 15

In addition to the partial excise tax exemption, there are 3 income tax credits available for motor

fuels containing biomass alcohol. In lieu of the excise tax exemption, an equivalent federal

blender’s income tax credit is available to fuel distributors that blend ethanol with gasoline. Also

available are a credit for pure alcohol fuels, which is typically available to retailers, and a small

ethanol producer’s credit.16 However, the partial excise tax exemption has been much more

important than the income tax credits in terms of the amount of tax benefits claimed.17

Information on the excise tax exemption for ethanol fuels can be found in IRC sections 4041 and

4081.

Legislative History

The partial exemption for ethanol fuel from federal fuel excise taxes was first enacted as part of

the Energy Tax Act of 1978 and first became effective in 1979. It established a 4-cents-per-gallon

exemption from excise taxes for motor fuels that contained at least 10 percent biomass-derived

alcohol. During the 1980s, the rate of exemption was raised to 6 cents per gallon of fuel. Later,

the Omnibus Budget Reconciliation Act of 1990 reduced the rate of exemption to 5.4 cents per

gallon.

The exemption for ethanol fuel was extended to fuel blends containing smaller amounts of

ethanol in the Energy Policy Act of 1992. The 1998 Transportation Equity Act for the 21st Century

extended the exemption through September 30, 2007. The act also reduced the rate of exemption

from 5.4 cents per gallon of gasoline to 5.3 cents for the years 2001 and 2002, 5.2 cents for the

years 2003 and 2004, and 5.1 cents for the years 2005 through 2007.

Revenue Losses

Table 8 contains estimates of annual revenue losses for this tax incentive, both unadjusted and

adjusted for inflation. Revenue loss estimates for the income tax credits for alcohol fuels are

presented in table 9.

Reasons for the difference in Treasury’s and JCT’s estimates of revenue losses for this tax

incentive include possible differences in their respective estimates of taxpayers’ incomes,

deductions, and spending, as discussed above. Another source of difference is that Treasury and

JCT use different methodologies for projecting revenue losses from excise tax incentives. For

this tax incentive, Treasury estimates the reduction in excise tax revenues due to the partial

exemption of alcohol fuels from the motor fuels excise tax. In contrast, JCT estimates the

reduction in total federal revenues due to the excise tax exemption, net of income tax effects.

JCT’s adjustment for income tax effects reduces the magnitude of its estimates, relative to

Treasury’s.18

15Straight, or neat, alcohol fuels—mixtures that contain a minimum of 85 percent alcohol—also qualify for the excise tax exemption.

16Revenue loss estimates for these income tax credits for alcohol fuels are found in table 9.

17See Tax Policy: Effects of the Alcohol Fuels Tax Incentives (GAO/GGD-97-41, Mar. 6, 1997), p. 2.

18For further explanation, see Tax Policy: Effects of the Alcohol Fuels Tax Incentives (GAO/GGD-97-41, Mar. 6, 1997), pp. 43-44.
Enclosure I

17 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

The excise tax revenue loss estimates for alcohol fuel blends in our 1997 report are not directly

comparable to the estimates in table 8. Our report provides annual estimates of the excise tax

revenues forgone because of the partial exemption for alcohol fuels between 1979 and 1995. Our

estimates in that report for 1987-95 are based on IRS’ quarterly reports of excise tax receipts, by

type of fuel. They are not Treasury’s or JCT’s estimates.

Table 8: Revenue Loss Estimates for the Partial Exemption From the Excise Tax for Alcohol Fuels

Dollars in millions

JCT Treasury

Fiscal year

Not adjusted for

inflation

Adjusted to

2000 dollarsa

Not adjusted for

inflation

Adjusted to

2000 dollarsa

1979 b b

1980 b$50 $94

1981 b55 94

1982 $50 $80 55 88

1983 40 61 160 246

1984 145 215 215 318

1985 150 215 375 538

1986 200 280 400 560

1987 200 273 475 648

1988 200 264 480 635

1989 300 382 485 617

1990 400 491 445 546

1991 400 473 465 550

1992 400 462 544 629

1993 400 451 567 639

1994 500 551 575 634

1995 600 648 615 664

1996 600 635 670 710

1997 500 521 675 703

1998 500 514 680 699

1999 500 507 760 771

2000 500 500 800 800

Total c$7,523 c$11,183

Note: Estimated revenue losses are included for all years in which JCT or Treasury made estimates.

a

Data were adjusted for inflation by GAO.

b

No estimate

c

Not applicable.

Income Tax Credits for Alcohol Fuels

Income tax credits are provided for alcohol fuels, including ethanol, that are derived from

biomass materials and used as fuel.

Description

The income tax credits for alcohol-based motor fuels apply to biomass alcohol—ethanol and

methanol derived from renewable resources. Alcohol derived from petroleum, natural gas, or

coal does not qualify for the credits. There are three income tax credits for alcohol fuels: the

alcohol mixtures credit, the pure alcohol fuel credit, and the small ethanol producer’s credit. The

alcohol mixtures--or blender’s--credit and the pure alcohol fuel credit are 54 cents per gallon of
Enclosure I

18 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

ethanol. The alcohol blender’s credit is typically available to the fuel blender, and the pure

alcohol credits is typically available to the retail fuel seller. The small ethanol producer’s credit

is 10 cents per gallon of ethanol produced, used, or sold for use as a transportation fuel. This

credit is limited to 15 million gallons of annual alcohol production for each small producer,

defined as one with a production capacity of under 30 million gallons.

In lieu of the blender’s credit, fuel ethanol blenders may claim the 5.4-cents-per-gallon excise tax

exemption for blends of ethanol and gasoline. The three income tax credits for alcohol fuels are

components of the general business credit, which is limited under the AMT.19 Information on the

income tax credits for alcohol fuels can be found in IRC sections 38, 40, and 87.

Legislative History

Two income tax credits for ethanol fuels--including the alcohol mixtures (or blender’s) tax credit

and the pure alcohol fuel credit--were enacted as part of the Crude Oil Windfall Profit Tax Act of

1980. The rate of credit was 40 cents per gallon of alcohol that was 190 proof or more and 30

cents for alcohol that was between 150 and 190 proof. The credit was increased during the

1980s. Later, the Omnibus Budget Reconciliation Act of 1990 reduced the rate of credit to 54

cents and 40 cents, respectively. The 1990 act also introduced a small ethanol producer’s income

tax credit of 10 cents per gallon of alcohol.

The 1998 Transportation Equity Act for the 21st Century extended the ethanol tax credits through

December 31, 2007. The act also reduced the rate of credit from 54 cents per gallon of alcohol to

53 cents for the years 2001 and 2002, 52 cents for the years 2003 and 2004, and 51 cents for the

years 2005 through 2007.

Revenue Losses

Table 9 contains estimates of annual revenue losses for these tax incentives, both unadjusted and

adjusted for inflation. Revenue loss estimates for the excise tax exemption for ethanol are in

table 8.

19See footnote 13 above.
Enclosure I

19 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Table 9: Revenue Loss Estimates for the Income Tax Credits for Alcohol Fuels

Dollars in millions

JCT Treasury

Fiscal year

Not adjusted for

inflation

Adjusted to

2000 dollarsa

Not adjusted for

inflation

Adjusted to

2000 dollarsa

1980 $1 $2 b

1981 2 3 $5 $9

1982 20 32 5 8

1983 5 8 1 2

1984 5 7 2 3

1985 5 7 11 16

1986 13 18 6 8

1987 14 19 6 8

1988 33 44 5 7

1989 10 13 1 1

1990 13 16 1 1

1991 8 9 1 1

1992 100 116 10 12

1993 50 56 15 17

1994 40 44 15 17

1995 40 43 10 11

1996 20 21 10 11

1997 5 5 20 21

1998 5 5 15 15

1999 5 5 15 15

2000 5 5 15 15

Total c$478 c$198

Note: Estimated revenue losses are included for all years in which JCT or Treasury made estim ates.

a

Data were adjusted for inflation by GAO.

b

No estimate.

c

Not applicable.
Enclosure II

20 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Petroleum and Ethanol Tax Incentives, Subsidies, and Other Programs:

A Review of GAO Studies, 1990-September 2000

GAO report Issues examined Summary of findings

Petroleum and

related studies

Tax Policy:

Additional

Petroleum

Production Tax

Incentives Are of

Questionable

Merit

(GAO/GGD-90-

75, July 1990)

Responding to concerns about the

implications for U.S. energy

security of declining domestic oil

production and rising oil imports,

this study assessed the potential

impact of a range of additional tax

incentives on U.S. petroleum

production and federal revenues.

Specifically, the study examined

• the effects of a range of

possible tax incentives on

U.S. petroleum production

and other industries,

• the effective federal corporate

tax rates on investments in

petroleum production and

other industries, and

• the comparative tax treatment

of petroleum investments in

the United States and other

nations.

Additional federal tax incentives for petroleum investments would

probably increase U.S. petroleum production to only a limited

extent but would cause substantial federal revenue losses. For

example, the study found that two tax incentives proposed in

1989—repeal of the transfer rule (a rule governing depletion

allowances) and eased tax treatment of certain intangible drilling

costs—could, at the time, increase future U.S. petroleum

production by an estimated 25,000 to 40,000 barrels per day.

However, estimated revenue losses from these proposals could

be $3 to $14 per barrel of additional production resulting from

these proposals.

The study also found that additional incentives for petroleum

investments would further contribute to a federal tax system that

already favors such investments over those in most other

industries. The favorable tax treatments received by both the

industry as a whole and by certain activities within the industry

provide incentives for relatively inefficient investments within the

industry.

U.S. producers are investing in petroleum production abroad,

rather than in the United States, largely because of factors other

than taxes, such as more favorable geologic characteristics.

Gasoline

Marketing:

Uncertainties

Surround

Reformulated

Gasoline as a

Motor Fuel

(GAO/RCED-90-

153, June 1990)

Shortly after the administration

proposed legislation in July 1989

to amend the Clean Air Act to

include an initiative promoting the

use of cleaner-burning alternative

fuels for motor vehicles (e.g.,

ethanol, methanol, and

compressed natural gas (CNG)),

the petroleum and automobile

industries countered with a

suggestion that gasoline could be

reformulated to burn as cleanly as

alternative fuels. Because little

was known about reformulated

gasoline, the Chairman of the

Subcommittee on Energy and

Power, House Committee on

Energy and Commerce, asked

GAO to provide information on

• what reformulated gasoline is,

• when it would become

available and how it would be

produced, and

• what the impacts of producing

and using it would be.

Reformulated gasoline generally refers to gasoline whose

chemical makeup has been changed for a specific purpose, such

as improving its emissions characteristics.

As of 1990, both the petroleum and automobile industries were

just beginning in-depth research on possible reformulations,

potentially leading to several recipes for reformulated gasoline.

As a result, the exact formulations and likely dates of availability

were uncertain. Although much remained to be learned about

the benefits and costs of various possible reformulations,

government and industry officials agreed that, in general,

reformulated gasoline could make a positive contribution to air

quality by helping to reduce some vehicle emissions. But they

further agreed that producing large quantities and more effective

formulations would require at least several years’ lead time and

large investments in new refinery equipment. In addition, they

believed that the production of reformulated gasoline could

adversely affect small refiners, increase the cost of gasoline to

consumers, and increase crude oil imports. Government

officials also expressed concern that the emergence of

reformulated gasoline might discourage the development of

alternative fuels, such as ethanol and methanol, that are not

made from petroleum.

Because of uncertainties about the composition and potential

impacts of reformulated gasoline, the study determined that it
Enclosure II

21 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

would be premature to draw conclusions about the relative

potential of reformulated gasoline and other alternative fuels.

Energy Security

and Policy:

Analysis of the

Pricing of Crude

Oil and

Petroleum

Products

(GAO/RCED-93-

17, Mar. 1993)

During the first week after Iraq

invaded Kuwait on August 2,

1990, crude oil prices in the

United States rose from about $22

per barrel to $30 per barrel—an

increase of about 36 percent. The

prices of petroleum products also

rose, by between 28 percent and

30 percent. A number of

congressional requesters asked

GAO to, among other things,

• explain the pricing of crude oil

and selected petroleum

products under normal

market conditions and market

shocks and

• describe the federal

government’s authorities to

respond to disruptions in the

supply of oil and the

government’s use of these

authorities during the Persian

Gulf crisis.

Since their decontrol in late 1981, U.S. crude oil prices have

been linked to world oil prices. The world price of oil is not

necessarily related to the cost of its production or acquisition.

Rather, it is mostly determined by the Organization of Petroleum

Exporting Countries’ (OPEC) supply decisions; the relative

scarcity of oil; the lack of substantial substitutes for oil in certain

uses (transportation), especially in the short term; and seasonal

demand. The price of crude oil, seasonal demand, and the

extent of local market competition largely determine the prices of

refined products.

The Energy Policy and Conservation Act (EPCA), which

authorized the United States in 1975 to develop and use the

Strategic Petroleum Reserve (SPR) and to participate in the

International Energy Agency (IEA), is a key federal law

addressing oil supply disruptions. The SPR was created to

reduce the impact of severe interruptions of petroleum supplies

on the U.S. economy. Current U.S. policy relies on the free

market during an oil supply disruption to allocate the supply to

meet demand at the current price. If necessary, an early and

large release of oil from the SPR can be authorized. As of

August 1992, the SPR contained 569.5 million barrels and a total

of about $20.7 billion had been appropriated for the SPR through

fiscal year 1992.

Energy Security:

Evaluating U.S.

Vulnerability to

Oil Supply

Disruptions and

Options for

Mitigating Their

Effects

(GAO/RCED-97-

6, Dec 1996)

Since the early 1970s, the world

has experienced three major oil

supply disruptions that harmed the

U.S. economy. Concerned that

the nation’s growing dependence

on low-cost imported oil,

especially from the Persian Gulf,

increases the economy’s

vulnerability to oil supply

disruptions and price shocks, the

Clinton Administration, through its

1995 National Energy Policy Plan

(NEPP), adopted policies and

programs intended to reduce that

vulnerability and its associated

economic costs. At the request of

the Chairman, House Committee

on the Budget, GAO addressed

the following questions:

• What are the economic

benefits of importing oil

compared with the potential

economic costs of

vulnerability to oil shocks?

• To what extent would the

U.S. economy’s vulnerability

to oil shocks be likely to

change over time, given the

policies and programs

contained in the 1995 NEPP

and other relevant factors?

• What options exist to reduce

GAO estimated that the U.S economy realizes hundreds of

billions of dollars in benefits annually by using relatively low-cost

imported oil rather than relying on more expensive domestic

sources of energy. By comparison, oil shocks impose large but

infrequent economic costs that, when annualized, are estimated

to cost the U.S. economy tens of billions of dollars per year.

More importantly, substituting more costly domestic oil for

imported oil without lowering overall oil consumption would be

unlikely to substantially lower the costs of oil supply disruptions.

In essence, the economic costs of oil price shocks depend

largely on the rise in the price of oil coupled with the nation’s

level of oil consumption, rather than on the level of imports. As

long as market forces prevail, the prices of domestic and world

oil will be the same and will rise and fall with changes in world oil

market conditions. However, this report also pointed out that

studies by other researchers have estimated, using different

assumptions, that the cost of preserving the stability of oil

supplies ranges from a few billion dollars per year to as much as

$65 billion per year.

While adopting NEPP’s initiatives may keep the economy’s

vulnerability to oil supply disruptions below what it otherwise

would be, according to the Department of Energy’s (DOE)

Energy Information Administration (EIA), by most measures, the

economy would not likely be significantly less vulnerable through

2015, primarily because U.S. oil demand is projected to

increase. (Among the NEPP’s initiatives were programs to

increase domestic oil production, as well as promote alternative

and renewable fuels and energy efficiency). Only over a longer

period do energy analysts anticipate significant improvement—

and that depends on technological advances in such areas as

energy efficiency and alternative fuels.
Enclosure II

22 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

the economy’s vulnerability to

oil shocks?

While their views varied, almost all of the experts consulted by

GAO about options for reducing the economy’s vulnerability to oil

supply disruptions said that, in the short run, the United States

should rely on rapid and large releases of oil from the SPR to

blunt price increases at the onset of an oil supply disruption.

Monetary policy tools, such as adjusting interest rates and the

money supply, were also cited as potentially helpful. In the long

run, the experts generally favored research to develop costcompetitive alternatives to petroleum, particularly in the

transportation sector, which accounts for most of the nation’s oil

consumption. While some experts suggested raising taxes on

domestic gasoline consumption to increases the price, lower the

demand, and make alternatives more cost-competitive, they also

recognized the existence of opposing views on this option and

the potential for public opposition to it.

Department of

Energy: Fossil

Energy Programs

(GAO/RCED-98-

63, Jan 1998)

At the request of the Chairman,

House Committee on the Budget,

this study, among other things,

provided information on

• the research and

development (R&D) goals

and technologies being

developed by DOE’s Fossil

Energy R&D programs and

• the level of funding committed

to R&D activities within these

programs from fiscal year

1996 through fiscal year

1998.1

DOE’s overall R&D goal for its Fossil Energy R&D programs is to

improve the efficiency and environmental performance of current

methods for producing and using petroleum and natural gas.

The oil technology subprogram addresses exploration and

production research; recovery and demonstrations; exploration

and production environmental research; and processing

research and downstream operations. The natural gas research

subprogram addresses exploration and production; delivery and

storage; ultilization; turbines; and environmental regulation.

Total funding for basic and applied R&D for both the oil and gas

programs was $165.64 million for fiscal year 1996, $170.61

million for fiscal year 1997, and $157.09 million for fiscal year

1998.

Ethanol and

related studies

Air Pollution: Air

Quality

Implications of

Alternative Fuels

(GAO/RCED-90-

143, July 1990)

This study examined the impact of

alternative motor fuels on air

quality.2

The study found that using ethanol as a motor fuel would have

some advantages and disadvantages. For example, using

ethanol mixed with gasoline (85 percent ethanol and 15 percent

gasoline) reduces ozone-forming hydrocarbon and toxic

emissions by up to 40 percent. Using ethanol also reduces

carbon dioxide emissions. However, ethanol emits more

acetaldehyde, would cost consumers substantially more without

a federal tax exemption, and would require vehicle modifications

estimated to cost $300 per vehicle.

Alcohol Fuels:

Impacts From

Increased Use of

Ethanol-Blended

Fuels

(GAO/RCED-90-

156, July 1990)

Congressional proposals to

encourage greater use of

alternative motor fuels could

increase the demand for ethanol.

In view of this, the study examined

• the ability of the domestic

ethanol industry to expand to

meet the increased demand

that such legislation could

create,

• the effects of expanded

ethanol production on the

The study found that the ethanol industry would be capable of

doubling or tripling domestic ethanol production to 2.2 billion or

3.3 billion gallons per year during the next 8 years and U.S.

farmers could supply the corn needed for this production

increase. However, industry officials cautioned that continued

government incentives and/or a legislative requirement for the

use of alternative fuels, such as ethanol, would be needed to

maintain such growth.

GAO’s modeling showed that the expanded use of ethanol fuels

would have mixed effects on various sectors of American

agriculture. Corn producers would benefit the most because of

the increased demand for corn to make ethanol and the resulting

1 The study also provided information on clean coal technology.

2 The fuels examined included methanol, ethanol, liquefied petroleum gas, compressed natural gas,

oxygenated fuels, and reformulated gasoline. These other alternative fuels had their own advantages and

disadvantages, and some had more disadvantages than ethanol.
Enclosure II

23 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

agricultural sector and on

consumer food prices, and

• the effects of increased

ethanol production and use

on the federal budget.

higher corn prices. However, through a complex system of

economic relationships, some other sectors would not fare as

well. For example, soybean processors and producers would

face lowered demand and prices for their products because the

conversion of corn into ethanol generates protein-rich feed and

corn oil by-products that compete with soybean meal and

soybean oil. Increased corn prices would raise feed costs and

hurt cattle producers, but the lower cost of high-protein feeds

could benefit poultry producers. Overall, net farm income would

increase, and there would be a slight increase in consumer food

prices.

GAO’s modeling also showed that expanded ethanol production

would, with some fluctuations, decrease federal farm program

outlays because increases in the demand for and price of grains,

primarily corn, would cause fewer farmers to participate in these

support programs. At the same time, the increased use of

ethanol fuels would reduce federal motor fuel tax revenues

because of ethanol’s partial tax exemption. On average, the

reductions in farm program outlays would exceed the increased

tax revenue losses over the 8-year period.

Alternative Fuels:

Experience of

Brazil, Canada,

and New Zealand

in Using

Alternative Motor

Fuels

(GAO/RCED-92-

119, May 1992)

Worldwide, ethanol; liquid

propane gas (LPG), also known

as propane; and CNG are the

most commonly used alternative

fuels, with far more ethanol- and

LPG-based vehicles than others.

This study assessed the

experiences of other countries

that have used alternative fuels.

In particular, it examined the

perspectives of

• their respective governments,

in encouraging the use of

alternative fuels and

alternative-fuel vehicles;

• industry, in developing and

marketing them; and

• consumers, in using them.

The oil price and supply crises in the 1970s prompted the

governments of Brazil, Canada, and New Zealand to look to

domestic alternatives for their motor fuels. Their experiences,

however, have shown that introducing and sustaining the use of

alternative fuels would most likely not be achieved easily or

quickly.

Each government was the catalyst for action on alternative fuels,

and this leadership proved important in helping remove

economic and technological barriers and persuading industry

and consumers that alternative fuels were important.

Government planning and cooperation with industry was also

important in developing technologies and marketing these fuels.

But consistent, long-term government commitment was

somewhat difficult to maintain because of resource constraints

and other reasons. Failing to maintain this commitment, in some

cases, had a strong negative impact on sustaining the use of

alternative fuels.

Participation by the fuel, automotive, and utility industries was

vital in attracting and retaining consumers for alternative fuels

and alternative-fuel vehicles in each country. Alternative-fuel

initiatives struggled when industry was not actively involved in

developing vehicle technologies, building a fueling infrastructure,

and marketing programs.

Consumer acceptance was essential to the use of alternative

fuels in these countries. A favorable price for the fuel relative to

gasoline created a strong incentive for private motorists and fleet

operators to use alternative fuels. Regulations, lower taxes on

alternative fuels, higher taxes on gasoline, or subsidies were

used to create or enlarge a price advantage. Consumer

acceptance was also influenced by such factors as vehicle

performance and reliability and the availability of convenient

fueling. When the price of alternative fuels did not compare

favorably with the price of gasoline, or when these other factors

made alternative fuels less attractive, their use was adversely

affected, according to officials in each country.
Enclosure II

24 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

Ethanol Tax

Exemption

(GAO/RCED-95-

273R, Sept.

1995)

This study analyzed the possible

effects of eliminating the current

tax exemption for ethanol.

Specifically, the study estimated

• the decline in ethanol use if

the tax exemption were

eliminated and

• the net fiscal effect on the

U.S. Treasury and the

changes in farm income that

would result from a decline in

ethanol use.

The study found that it was not possible to calculate with

precision the decline in ethanol use that could be expected if the

ethanol tax exemption were eliminated. However, GAO’s

interviews of experts from industry and government indicated

that the decline would be at least 50 percent. On the basis of

GAO’s discussions with these experts, the study further analyzed

declines in ethanol use for two Acreage Reduction Program

(ARP) scenarios—reductions in use of 50 percent and 90

percent--to represent possible immediate and significant

declines.

Under both of the ARP scenarios, eliminating the tax exemption

results in a net loss to the U.S. Treasury and lower farm income

from corn. Using the ARP levels set forth in a baseline

developed by the Food and Agriculture Policy Research Institute,

GAO estimated that the losses to the Treasury from 1996

through 2000 would be $2.5 billion if ethanol use dropped by 50

percent and $5.4 billion if it dropped by 90 percent. With no ARP

for corn, the losses to the Treasury would be $3.2 billion for a 50-

percent decline in ethanol use or $6.3 billion for a 90-percent

decline. In both scenarios, farm income from corn declined.

However, if different assumptions about the ARP were used, the

model’s results would differ.

Motor Fuels:

Issues Related to

Reformulated

Gasoline,

Oxygenated

Fuels, and

Biofuels

(GAO/RCED-96-

121, June 1996)

Reformulated gasoline is required

for use in those areas of the

United States with the most

severe ozone air pollution. To

meet this requirement,

oxygenates, such as MTBE, or

ethanol, are added to gasoline to

enhance combustion and reduce

the vehicle emissions that cause

ground-level ozone problems as

well as reduce air toxic emissions.

Oxygenates are also sometimes

added to gasoline to increase

octane levels and, according to

DOE, can also help reduce the

growing U.S. need for petroleum.

Biofuels—primarily ethanol

developed from corn or biomass

(such as fast-growing trees or

grasses)—also have the potential

to reduce air pollution and the

demand for petroleum. Such

ethanol can be used as an

oxygenate or, in its pure form, as

an alternative transportation fuel.

This study responded to Senator

Daschle’s request for GAO to,

among other things, summarize

• the results of federal and

other studies on the costeffectiveness of using

reformulated gasoline

compared to other measures

to control automotive

emissions and compare the

price estimates used in the

studies for reformulated

Studies by the Environmental Protection Agency (EPA), the

American Petroleum Institute (API), and others suggest that

reformulated gasoline may be more cost-effective than some

automotive emission control measures and less cost-effective

than other measures, but the studies varied in approaches and

assumptions, making comparisons difficult. Projected versus

actual incremental prices for reformulated gasoline varied but

were close to the range of the actual prices experienced during

the first 14 months of the reformulated gasoline program, which

began in January 1995. Estimates varied from a low of 3.3 cents

to 4.0 cents per gallon more for phase I reformulated gasoline

than for conventional gasoline (cited by DOE) to a high of 8.1

cents to 13.7 cents per gallon more (cited by API). EPA

estimated an increase of 3.0 cents to 4.9 cents per gallon.

Actual prices, monitored by EIA, showed that reformulated

gasoline prices were as much as 12 cents per gallon over

conventional gasoline prices during the early weeks of the

program but narrowed to about 5 cents per gallon by March

1996.

According to estimates based on EIA’s projections, oxygenates

would potentially displace about 305,000 barrels per day of

petroleum used to produce gasoline in 2000, and 311,000

barrels per day in 2010. This displacement would amount to 3.7

percent and 3.6 percent of the estimated gasoline consumption

in those years.

At the time of this study, DOE and USDA were the primary

federal agencies with ongoing research on biofuels. DOE

focused primarily on reducing the cost of growing and converting

biomass feedstocks, such as trees and grasses, into ethanol.

USDA focused primarily on reducing the cost of growing and

converting agricultural feedstocks, such as corn, into ethanol.

DOE and USDA data indicated that research had reduced the

cost of producing ethanol from both cellulosic biomass and from

corn. Further cost reductions in producing ethanol from corn,

and subsequent increases in the demand for corn-based

ethanol, may be constrained by the price of corn and its use for
Enclosure II

25 GAO/RCED-00-301R Tax Incentives for Petroleum and Ethanol Fuels

gasoline with more recent

actual prices;

• the results of studies

estimating the potential for

oxygenates to reduce the use

of petroleum; and

• ongoing federal research into

biofuels, including any related

past or projected costreduction goals, and any

increased demand estimates

based on such research

goals.

other purposes. DOE believed that the demand for ethanol

made from cellulosic biomass for use as an oxygenate and as an

alternative fuel could increase significantly, assuming the

successful development and commercialization of biofuels

technologies and the achievement of the agency’s cost-reducing

goals.

Tax Policy:

Effects of the

Alcohol Fuels

Tax Incentives

(GAO/GGD-97-

41, Mar. 1997)

In the late 1970s and early 1980s,

the Congress enacted tax

incentives for biomass-derived

alcohol fuels. This study

addressed the following

questions:

• Whom do the incentives

benefit and disadvantage

economically?

• What environmental benefits,

if any, have the incentives

produced?

• Have the incentives

increased the nation’s

energy independence?

• To what extent has the

partial exemption from the

excise tax for alcohol fuels

reduced the flow of revenue

into the Highway Trust

Fund?

The study found the following:

The value of the ethanol tax incentives is shared, directly or

indirectly, among different groups in the economy, including

alcohol fuel blenders, ethanol producers, and corn farmers. The

tax incentives allow ethanol to be priced to compete with

substitute fuels, such as gasoline and MTBE; thus, without the

incentives, ethanol fuel production would largely cease.

Available evidence, including the views of analysts interviewed

by GAO, indicates that the ethanol tax incentives have had little

effect on the environment.

Although the available evidence suggests that the tax incentives

for alcohol fuels increase ethanol fuel use, it also indicates that

these incentives do not significantly reduce petroleum imports.

Therefore, the tax incentives do not significantly contribute to

U.S. energy independence. The share of oil imports in total U.S.

energy or petroleum consumption has remained the same or

higher than it was before ethanol incentives were offered.

Ethanol currently accounts for less than 1 percent of U.S. motor

vehicle fuel consumption. In addition, ethanol tax incentives

have not significantly enhanced U.S. energy security because

they have not created enough usage to reduce the likelihood of

oil price shocks and their consequences, which are increased

U.S. fuel prices and reduced economic output and employment.

According to GAO’s estimates, the partial exemption for alcohol

fuels reduced motor fuels excise tax revenues by about $7.1

billion from fiscal year 1979 through fiscal year 1995.

(141472)