Petroleum and Ethanol Fuels: Tax Incentives and Related GAO Work
(Correspondence, 09/25/2000, GAO/RCED-00-301R).
Pursuant to a congressional request, GAO provided information on the tax
incentives that benefit the petroleum and ethanol industries.
GAO noted that: (1) specific petroleum tax incentives range from about
$330 million for the expensing of tertiary injectants to about $82
billion for certain cost depletion deductions; (2) 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; (3) ethanol fuel tax incentives ranged from $198
million for alcohol fuel tax credits to almost $11 billion for the
excise tax exemption for alcohol fuels; (4) these tax incentives were
instituted in 1979-1980; (5) in the past decade, these incentives have
been extended, but the rates of exemption and credit have been reduced
somewhat; (6) the estimated revenue losses for these tax incentives
should not be added together; and (7) 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.
--------------------------- Indexing Terms -----------------------------
REPORTNUM: RCED-00-301R
TITLE: Petroleum and Ethanol Fuels: Tax Incentives and Related
GAO Work
DATE: 09/25/2000
SUBJECT: Petroleum products
Fuel taxes
Alcohol fuels
Tax credit
Subsidies
Petroleum industry
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GAO/RCED-00-301R
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 incentives 1
that benefit the petroleum and ethanol 2 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.
B- 286311
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 2 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 injectants 4 (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 depletion a 1968- 2000 $81,679-$ 82,085
Expensing of exploration and development costs a
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 1,065 b Credit for enhanced oil recovery costs 1994- 2000 482-
1,002 Expensing of tertiary injectants 1980- 2000 330 c
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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 3 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 4
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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 5 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 6
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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 7
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 dollars a Not adjusted for
inflation Adjusted to
2000 dollars a 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 8 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 9 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 dollars a Not adjusted for
inflation Adjusted to 2000 dollars a 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 1112, section on
"Tax Expenditure Estimates Generally."
Enclosure I
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 10
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.
10 A BTU oil barrel equivalent is that amount of a qualifying fuel that has
a British thermal unit content of 5. 8 million. 11 Biomass is any organic
material other than oil, natural gas, or coal, or any product thereof.
Enclosure I
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 11
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 dollars a Not adjusted for
inflation Adjusted to 2000 dollars a 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
12 Losses 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 12
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 dollars a
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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 13 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 dollars a Not adjusted for
inflation Adjusted to 2000 dollars a 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.
13 The 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 14
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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 15
Table 7: Revenue Loss Estimates for the Expensing of Tertiary Injectants
Dollars in millions
JCT Fiscal year Not adjusted for inflation Adjusted to 2000 dollars a 1980
$4 $8 1981 14 24 1982 9 14 1983 8 12 1984 7 10 1985 6 9 1986 0 b 0 1987 0 b
0 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 0 c 0 2000 0 c 0
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
14 In 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 16 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 21 st 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
15 Straight, or neat, alcohol fuels- mixtures that contain a minimum of 85
percent alcohol- also qualify for the excise tax exemption. 16 Revenue loss
estimates for these income tax credits for alcohol fuels are found in table
9. 17 See Tax Policy: Effects of the Alcohol Fuels Tax Incentives( GAO/ GGD-
97- 41, Mar. 6, 1997), p. 2. 18 For further explanation, see Tax Policy:
Effects of the Alcohol Fuels Tax Incentives (GAO/ GGD- 97- 41, Mar. 6,
1997), pp. 43- 44.
Enclosure I
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 17 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 dollars a Not adjusted for
inflation Adjusted to 2000 dollars a 1979 b b 1980 b $50 $94 1981 b 55 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 18
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 21 st 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.
19 See footnote 13 above.
Enclosure I
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 19
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 dollars a Not adjusted for inflation
Adjusted to 2000 dollars a 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 estimates. a Data were adjusted for inflation by GAO.
b No estimate. c Not applicable.
Enclosure II
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 20
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- 9075, 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- 90153, 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 21
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- 9317, 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- 976, 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 22
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- 9863,
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-
90143,
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- 90156,
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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 23
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- 92119,
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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 24
Ethanol Tax Exemption
(GAO/ RCED- 95273R, 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- 96121, 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
GAO/ RCED- 00- 301R Tax Incentives for Petroleum and Ethanol Fuels 25
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- 9741, 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)
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