In other words, tax subsidies for these forms
of energy generation are sufficiently generous
that investors may use them to offset tax liabilities
for capital gains and income derived from non-energy
investments. It is worth noting that wind capacity,
a highly tax-favored source of energy, grew
by nearly 50 percent in 2007 and accounted for
one-third of all new electrical capacity added
in that year. Independent oil companies that
are able to use percentage depletion to the
fullest extent have also received significant
tax benefits at the margin.
Still, the positive impact of these tax subsidies
is to some extent vitiated by the codes
relatively ungenerous treatment of investment
in the electric grid, which carries electricity
produced by any type of energy source to businesses
and households. Given the great distance of
the steadiest sources of wind and solar power
from the largest energy consumers, the economics
of these cleaner sources depend on the further
development of high-voltage transmission lines
and other features of the grid. Yet the code
continues to tax income realized from investments
in high-voltage power transmission lines more
heavily than capital gains or most ordinary
Gilbert E. Metcalf is a professor of
economics at Tufts University and a research
associate at the National Bureau of Economic
Research. He is also a research associate at
the Joint Program on the Science and Policy
of Global Change at MIT. Metcalf has taught
at Princeton University and the Kennedy School
of Government at Harvard University and been
a visiting scholar at MIT.
Metcalf has served as a consultant to numerous
organizations including, among others, the U.S.
Department of the Treasury, the U.S. Department
of Energy, and Argonne National Laboratory.
He currently serves as a member of the National
Academy of Sciences Committee on Health, Environmental,
and Other External Costs and Benefits of Energy
Production and Consumption. In addition he serves
or has served on the editorial boards of
The Journal of Economic Perspectives, The
American Economic Review, and the Berkeley
Electronic Journals in Economic Analysis and
Metcalfs primary research area is applied
public finance, with a particular focus on taxation,
energy, and environmental economics. His current
research focuses on policy evaluation and design
in the area of energy and climate change. He
has published papers in numerous academic journals,
has edited two books, and has contributed chapters
to several books on tax policy. Metcalf received
a B.A. in mathematics from Amherst College,
an M.S. in agricultural and resource economics
from the University of Massachusetts Amherst,
and a Ph.D. in economics from Harvard University.
Federal tax policy has historically played a large
role in shaping energy markets in the United States.
A recent analysis by the U.S. Energy Information Administration
(2008c) shows that the largest subsidies to the energy
sector can be found in the tax code. How much do different
sectors benefit from these subsidies, and what is
their likely impact on investment? This paper explores
The popular press is full of stories about federal
subsidies to nuclear power, to coal, to renewablesin
fact, to every energy source employed in the United
States. What is not clear from these stories is the
extent to which any fuel source is disproportionately
favored in the tax code. One difficulty that arises
in assessing the tax treatment of any fuel source
or energy investment is the necessity of distinguishing
between the statutory and the effective tax rate.
The statutory tax rate simply measures the tax bracket
of a firm or an individual. The effective tax rate,
on the other hand, takes into account the various
deductions and credits that influence the after-tax
cash flow of a project.
A large gap can exist between the statutory tax rate
and the effective tax rate. It is the latter that
matters in measuring how investment behavior, for
example, responds to the tax code. The effective tax
rate can help us determine whether a fuel is appropriately
taxed in light of various national energy policy goals.
The tax treatment of energy sources is important
for a number of reasons. First, a basic precept of
efficiency in taxation is that under perfect competition,
the tax system should provide a level playing field
for investment. One source of efficiency losses in
the tax code is the codes favorable treatment
of one energy source over another. In order to measure
the magnitude of this loss, it is necessary to measure
the extent to which the playing field for energy investment
It may be desirable, however, to provide an uneven
playing field at times. If the use of a particular
fuel has environmental impacts that are not captured
in the price of the fuel, then government intervention
through taxes can enhance efficiency. This is the
rationale for environmental taxes to address pollution
externalities. It is not enough, however, to compare
tax rates across fuels with estimates of the social
damages from the use of these fuels, given the complexity
of the tax code.
Another reason to focus on the tax codes treatment
of energy is the critical energy investment needs
that must be addressed in the next few decades. The
International Energy Agency (2007) estimates that
the world will need to invest over $20 trillion (in
year 2006 dollars) between 2006 and 2030 in energy
infrastructure. Of that, over $4 trillion is required
in North America, with half of that in the power sector
(electricity, heat, and heat and power).
The U.S. Energy Information Administration (EIA)
estimates that electricity demand will rise by nearly
30 percent between 2006 and 2030 (U.S. Energy Information
Administration, 2008a). In addition to investment
in new power plants to generate the energy necessary
to meet this growing demand (and to replace retiring
plants), significant new investment will be needed
to upgrade the nations transmission and distribution
network. Doing this is particularly important, given
the growing supply of renewable power. Wind power,
for example, can most efficiently be produced in areas
where the wind is strong and steady. These areas typically
are distant from areas of high electricity demand.
Already the U.S. power grid is struggling to handle
this new electricity (see Wald, 2008); without expensive
upgrades to the network, it would be highly inefficient
to develop significant amounts of new wind and solar
capacity in remote sites optimal for generation.
Demand for liquid fuels is also projected to rise.
Much of this demand will be for alternatives to gasoline.
Biofuels will require significant investment in new
refineries as well as in R&D to develop second-generation
biofuel technology. We are also seeing new investment
in liquefied natural gas (LNG) facilities to meet
a growing demand for this fuel. All of this points
to the importance of new capital to meet our growing
In this paper, I provide disaggregated estimates
of the effective tax rate for energy investments.
An effective tax rate compares the before-tax return
with the difference between the before- and after-tax
return on a marginal investment. It is a comprehensive
measure of the effect of the tax code on decisions
to make incremental investments in new capital.
My analysis builds on other work in the literature
on effective tax rates in a couple of important ways.
First, it provides more detailed disaggregated estimates,
which allow us to compare and contrast the tax codes
treatment of different fuels. Second, it incorporates
important tax provisions specific to the energy sector,
including production and investment tax credits as
well as depletion in the petroleum and gas sectors.
None of the other recent measures of effective tax
rates that focus in whole or in part on the energy
sector takes these detailed provisions into account.
I find that the distribution of tax subsidies across
fuel types has shifted over time, with renewables
and conservation receiving greater support through
the tax code than they have historically. Whether
the distribution of subsidies is optimal, given the
various externalities associated with energy production
and consumption, is not addressed in this paper.
I also find that the effective tax rate on new energy
investment varies widely across different fuel sources.
Many investments receive large subsidies at the margin,
with nuclear power, wind, and solar especially advantaged.
Independent oil companies that are able to use percentage-depletion
allowances to the fullest extent receive significant
benefits at the margin that are greater than those
available to firms unable to use percentage depletion.
In addition, the effective-tax-rate analysis suggests
that investments in the transmission grid receive
among the least favorable treatments of all energy
capital. This is particularly worrisome, given the
current grid congestion in certain parts of the country
and the need for a modern grid infrastructure to handle
the challenges of intermittent energy supply from
renewables such as wind and solar.
In the next section, I construct detailed summary
measures of the tax codes comprehensive impact
on energy investment incentives. These are followed
by, in section III, a detailed survey of the tax-code
provisions enacted to direct capital to particular
kinds of energy capital projects. Section IV provides
a discussion of the implications of my tax-rate measures
for future energy investment. I provide some concluding
thoughts in section V.
THE IMPACT OF THE TAX CODE ON ENERGY
The tax treatment of energy is extremely complex,
with multiple provisions affecting production, distribution,
and consumption that have evolved in a somewhat ad
hoc fashion over time. Two questions arise when thinking
about these subsidies. What is the absolute size of
federal subsidies for different fuel sources? What
impact do these subsidies have on investment in energy
capital and, ultimately, on energy supply? In this
section, I present two measures to get at these questions.
First, I discuss estimates of energy-related tax expenditures
as reported by the federal government. Tax expenditures
are estimates of the reduction in federal tax revenue
arising from various deductions and credits. As discussed
below, tax expenditures are a subjective concept and
suffer from a number of measurement problems. Perhaps
more important, they provide scant information on
how the tax code affects behavior.
Second, I construct effective-tax-rate measures for
energy-specific capital, which is the main contribution
of this paper. These measures provide information
on the degree to which the tax code favors one type
of new energy capital over other types. As discussed
below, my measures build on an existing literature,
including recent papers by the Congressional Budget
Office (2005, 2006) and Ernst & Young (2007).
My measures improve on these in two ways: I provide
finer detail on types of energy capital than do the
CBO reports, which look at very broad classes of investment;
and my measures include greater detail than does the
Ernst & Young report. While Ernst & Young
looks at narrower investment classes than do the CBO
reports, it does not look at wind or solar, for example.
None of these reports takes into account as many energy-related
provisions of the tax code as I do.
A. Energy Tax Expenditures
A first measure is the value of tax expenditures
associated with energy subsidies in the tax system.
The various deductions and credits described above
are examples of tax expenditures tracked by the Department
of the Treasury. This measure is not entirely comprehensive.
While the excess of percentage depletion over cost
depletion is treated as a tax expenditure, accelerated
depreciation (e.g., the five-year recovery period
for renewable electricity property) is only partially
accounted for. Nor does the
measure register the gains in federal tax revenue
that would occur if the preference were eliminated,
since behavior is treated as fixed when estimates
of tax expenditures are being constructed. Nevertheless,
the tax-expenditure budget is a commonly used measure
of subsidies provided through the tax code.
A recent analysis by the U.S. Energy Information
Administration (2008c) breaks out the subsidies by
fuel source (see Table 1).
Several points emerge from Table 1. First, the total
tax expenditure for energy is modest, totaling less
than $11 billion in 2007. Subsidies for biofuels constitute
the single largest tax expenditure (listed under Renewables).
Second, the distribution of tax expenditures by fuel
source has shifted significantly over the past ten
years, with the share that goes to fossil fuels dropping
by 15 percentage points. Third, on a BTU basis, renewables
receive the largest subsidy.
Measuring subsidies as tax expenditures either in
the aggregate or per dollar of production is problematic
for a number of reasons. Table 1 measures the average
subsidy but provides no information about the subsidys
effect on the production of this fuel. It may be that
production of a particular form of energy would occur
in the absence of any subsidy directed at that fuel
source. Second, the subsidy
doesnt take into account differences in the
quality of fuels. On an energy-content basis, natural
gas is nearly five times the cost of coal. Thus, while
the subsidy to regular coal used in the production
of electricity is roughly two-thirds that of natural
gas on an MWh basis, the coal subsidy is more beneficial
per dollar of spending on coal.
Finally, none of these measures is useful for identifying
the impact of the tax code on marginal decisions.
Do these subsidies affect the choice of energy project
investment? Do they influence the flows of capital
investment into different forms of energy capital?
Effective tax rates are useful for answering these
questions. I turn to this measure next.
B. Effective Tax Rates on Capital Investments
An effective tax rate is a summary measure of the
various provisions in the tax code that affect investment
in new capital. Specifically, it compares the before-tax
return with the difference between the before- and
after-tax return. The before-tax return is the return
that an investment must earn in order to cover its
cost, pay the required return to investors, and pay
taxes on the project. The after-tax return is the
return that savers (the source of funds for investment)
expect to receive after taxes are paid on marginal
investments. Thus, if savers are prepared to accept
7 percent on an investment after tax and the project
must earn 10 percent in order to cover depreciation,
taxes, and required payments to investors, the effective
tax rate is 30 percent (10-7)/10.
Effective tax rates focus on the marginal cost of
funding investments rather than on project cost. In
particular, they focus on the cost of a break-even
investment. Because they summarize the many provisions
of the tax code that affect the returns on capital
investment, effective tax rates are frequently used
to consider how the tax system affects capital investment.
This is a particularly salient issue, given the capital
investment needs of energy infrastructure in the United
States, as noted in the introduction.
I follow the methodology of the Congressional Budget
Office (2005, 2006) to construct effective tax rates
for energy capital. My measures differ from those
reported in the CBO reports in two ways: I analyze
assets at a more disaggregated level than is done
in those reports; and I take into account more provisions
of the tax code than do those reports. In particular,
the CBO studies do not account for energy-specific
production or investment tax credits or for tax rules
specific to the oil and gas industry. An overview
of the construction of effective tax rates is provided
in the Appendix. Readers seeking a fuller description
should read Congressional Budget Office (2006) or
any of the references cited therein. I then discuss
how I modify the standard effective-tax-rate (ETR)
measure for energy-specific tax provisions.
Table 2 below reports my estimates of effective tax
rates on new, energy-related capital investments based
on the formulas in the Appendix. I provide estimates
for different forms of electric generation capital,
other electricity-related capital, and capital used
in the drilling and refining of oil as well as in
the transport of natural gas.
The first part of Table 2 provides estimates of effective
tax rates for electric generation capital. Under current
law, solar thermal and wind capital are subsidized
to the greatest extent, with effective subsidy rates
of 245 and 164 percent, respectively.
Nuclear power is also heavily subsidized, with a subsidy
rate of nearly 100 percent. The effective tax rates
for coal and gas are substantially higher than they
are for nuclear or renewables. Integrated gasification
combined-cycle (IGCC) capital is subsidized, while
pulverized coal (PC) capital faces a positive tax.
The major difference here is the 20 percent investment
tax credit for new IGCC investments. Finally, PC and
natural-gas combined-cycle plants face an effective
tax rate very close to the statutory tax rate (39.3
percent, accounting for both state and federal taxes).
The next two columns in Table 2 indicate the impact
on effective tax rates of removing the production
and investment tax credits (column 2) and replacing
accelerated depreciation with economic depreciation.
The production or investment tax credits are the most
significant source of subsidyas evidenced by
the size of the change in the effective tax rate when
the credits are removed. The effective tax rate for
wind, for example, rises from -164 percent to -14
percent if economic depreciation replaces accelerated
depreciation, while it rises to +13 percent if the
production tax credit is eliminated. With economic
depreciation and no production or investment tax credits,
the effective tax rate in all cases equals the statutory
tax rate of 39.3 percent.
The effective-tax-rate methodology can be used for
other types of energy capital. In the electric-utility
section, I also construct effective tax rates for
transmission and distribution. Transmission lives
are allowed a fifteen-year recovery period, while
distribution lines are allowed a twenty-year recovery
period. The former face an effective tax rate modestly
lower than the statutory rate, while the latter receive
very little in the form of a subsidy.
Effective tax rates in the petroleum sector depend
in large part on whether the firms taking the credits
are integrated or nonintegrated (independent) firms.
Independent firms benefit from full expensing of their
intangible drilling costs, while the integrated firms
can expense only 70 percent of their IDCs and must
write off the rest over a five- year period. In addition,
the independents are allowed to take percentage depletion,
while the integrated firms must use cost depletion.
The effective tax rate on oil-drilling equipment depends
importantly on a firms ability to take percentage
rather than cost depletion. For independent firms
taking percentage depletion, the effective tax rate
is -13 percent, whereas firms taking cost depletion
face effective tax rates of 15 percent. The rate for
integrated firms is a bit lower than the effective
tax rate on refining capital. The effective tax rate
for refining capital assumes use of the temporary
50 percent expensing provision for capacity additions.
This assumption reflects the fact that most new investment
in refineries has been in increasing the capacity
of existing refineries rather than in building new
refineries. In the absence
of the temporary expensing provision, the effective
tax rate on refinery capital would rise from 19 to
32 percent. The seven-year recovery period for gathering
pipelines, which bring gas from the field to central
processing plants or large distribution pipelines,
gives them a lower tax rate than other kinds of pipelines,
which have a fifteen-year recovery period.
The effective tax rate for independent firms taking
percentage depletion is sensitive to the ratio of
price to operating profit per barrel. Figure 1 shows
how the effective tax rate changes as this ratio changes.
Percentage depletion drives the effective tax rate
down as the oil price relative to per-barrel operating
profits rises. The rising cost of extracting oil in
the United States means that the effective tax rate
for independent firms able to take percentage depletion
is falling, holding other factors constant.
The estimates in this paper are highly disaggregated
estimates of effective tax rates for energy capital
investments that take into account important tax benefits
specific to the energy sector. My effective-tax-rate
estimates in Table 2 can be compared with estimates
from the recent Congressional Budget Office (2005)
analysis of capital income taxation. The estimates
are not directly comparable but are suggestive of
the importance of production and investment tax credits
as well as the treatment of depletion. While not reported
in Table 2, I compute an effective tax rate for nuclear-power
structures of -58.9 percent. If I do not account for
the production tax credit available to new nuclear-power
plants, the tax rate rises to 26.3 percent, an estimate
not too far from the CBO estimate for electric structures
(Table 3). These calculations indicate the importance
of the new nuclear-power production tax credit in
lowering the effective tax rate on nuclear power.
The estimate for petroleum and natural-gas structures
lies between my estimates for integrated and nonintegrated
firms. CBO estimates for electric transmission and
distribution lines are about 10 percentage points
below my estimates. The discrepancy can most likely
be explained by the different assumptions that the
CBO and I make about rates of returns and other underlying
parameters in the tax-rate formulas.
recent study by Ernst & Young (2007) provides
more disaggregated estimates of effective tax rates
and so is more comparable with my results. Table 4
below provides some ETR estimates from this study.
The Ernst & Young estimates for coal- and gas-fired
generation are similar to my estimates, but its nuclear-power
estimate is much higher, reflecting our different
treatment of the production tax credit added by the
Energy Policy Act of 2005. Our estimates for other
assets are quite similar. Ernst & Young did not
provide estimates of wind- or solar-powered electric
OF ENERGY TAX PROVISIONS
In this section, I review the current treatment of
energy in the tax code at the federal and state level.
Broadly speaking, firms benefit from two types of
tax benefits in the federal tax code: rapid tax-depreciation
rules; and various production and investment tax credits.
A. Federal Tax Provisions
To begin, income earned in the production or distribution
of energy is subject to the U.S. income tax, mostly
that on corporate income, which has a top federal
marginal rate of 35 percent. Table 5 indicates the
share of assets in various energy-related industries
subject to the corporate income tax. The vast bulk
of assets in the mining, utilities, and petroleum
and coal-manufacturing sectors is subject to corporate
analyze energy investments in this paper assuming
that firms are subject to federal and state corporate
income taxes. Many energy
firms are subject to the corporate alternative minimum
tax (AMT). While I do not analyze the corporate AMT
in detail in this paper, I do note in various places
where my analytic results can be affected by the AMT.
Under the current tax code, capital assets are depreciated
according to the Modified Accelerated Cost Recovery
System (MACRS), with recovery periods ranging from
three to thirty-nine years. A declining-balance method
is used to depreciate most capital, at either 200
percent (three-, five-, seven-, and ten-year property)
or 150 percent (fifteen- and twenty-year property),
with the option to shift to straight-line depreciation
at whichever point it becomes advantageous to do so.
Assuming that firms switch to straight-line depreciation
at the point where straight-line provides a larger
deduction than declining-balance, the two key parameters
are the recovery period of the asset and the declining-balance
deduction rate. Table 6 illustrates how an asset with
a value of $1 would be depreciated under straight-line
and double-declining-balance rules, assuming a seven-year
Under straight-line depreciation, the taxpayer is
allowed to deduct one-seventh of the value of an asset
with a recovery period of seven years. The remaining
basis in each year is the share of the asset that
has not yet been depreciated and that can be depreciated
in future years. At the end of seven years, all the
asset has been depreciated, and zero basis remains.
Under the double-declining-balance method, two-sevenths
of the value of the asset may be depreciated in the
first year. In subsequent years, two-sevenths of the
remaining basis may be taken as a deduction. With
these rules, the asset would never be fully depreciated.
Thus taxpayers at any point may switch to applying
straight-line depreciation to the remaining basis.
After year three, it is not advantageous to switch
to straight-line, since the deduction allowed in year
four would equal 0.364/4 = 0.091, which is less than
the amount allowed under double-declining balance
(0.104). In the following year, it is advantageous
to switch, and the remaining basis is depreciated
over the final three years of the asset.
Tax depreciation effectively reduces the purchase
price of an asset.
Electric generating capital is depreciated over different
tax lives, depending on the type of plant. Recovery
periods range from five years for renewable energy
to twenty years for coal. High-voltage electricity
transmission lines received a fifteen-year recovery
period in the Energy Policy Act of 2005. That act
also clarified the depreciation of natural-gas gathering
(seven years) and reduced the recovery period of distribution
pipelines from twenty years to fifteen. In addition,
the new law contains a provision allowing partial
expensing of new refinery capacity placed in service
before 2012. The provision allows for 50 percent expensing,
with the remainder deducted, as under current law.
New deprecation provisions for smart grid
technology were included in the Emergency Economic
Stabilization Act of 2008, passed last October. The
tax lives of smart meters and other demand-response
technology were reduced from twenty years to ten.
2. Depreciation and Fossil-Fuel Production
Depreciation of assets in the production of fossil
fuels (oil and gas drilling and coal mining) requires
additional attention. Chief among the depreciation
preferences are percentage depletion and the ability
to expense intangible drilling costs. As noted in
Metcalf (2007), these preferences are less generous
than they have been historically, but they continue
to be significant. Some background will help explain
these tax benefits.
Capital investments in developing oil and gas production
sites fall into one of three categories for federal
tax purposes. Costs incurred in finding and acquiring
the rights to oil or gas are treated as depletable
property and are written off over the life of the
oil or gas site. These include exploration costs to
identify promising sites as well as the cost of up-front
(or bonus) bids to acquire sites. Once a site is identified
and purchased, its oil or gas enters a firms
proven reserves. As natural resources are extracted
from booked reserves, the value of those reserves
is diminished. Cost depletion allows a firm to write
off depletable costs as the reserve is drawn down.
As an alternative to cost depletion, independent oil,
gas, and coal producers are allowed to take percentage
depletion. Rather than take
a depletion deduction based on actual costs, the firm
is allowed to take a certain percentage of revenue
as a deduction. The current rate for percentage depletion
is 15 percent for oil and gas and 10 percent for coal.
Percentage depletion is allowed on production of up
to 1,000 barrels of average daily production of oil
(or its equivalent for natural gas). In addition,
the depletion allowance cannot exceed 100 percent
of taxable income from the property (50 percent for
coal) and 65 percent of taxable income from all sources.
Continuing with the example above, assume that an
independent firm owns this oil reserve and sells the
110,000 barrels of oil pumped in the first year for
$100 per barrel. Assuming no taxable-income limitations,
the firm could take a deduction for 15 percent of
the revenue from the sale of the oil, or $1.65 million.
If the firm were to sell the entire reserve of oil
at $100 per barrel, its cumulative depletion allowance
would be $15 million, 50 percent greater than the
depletable costs of the field.
Limits on percentage depletion have been added over
time, including a reduction in its rate and restriction
to independent producers. Despite the curtailed availability
of percentage depletion, it continues to be a significant
energy tax expenditure, costing $4.4 billion between
2009 and 2013, according to the most recent administration
budget submission (Office of Management and Budget,
2008). On the evidence of production data reported
in U.S. Energy Information Administration (2007b),
roughly two-thirds of domestic crude-oil production
in 2006 came from independent producers (Table A6)
potentially eligible to take percentage depletion.
Once a property has been identified, the firm incurs
significant costs in developing the site. These costs,
which might include site improvement, construction
costs, wages, drilling mud (used to keep the drill
bit cool and to flush out cuttings), fuel, and other
expenses, are called intangible drilling costs (or
IDCs). Intangible drilling costs are those with no
salvage value. Typically, noncapital costs associated
with developing a capital asset are depreciated over
the life of the asset. In the energy sector, intangible
drilling costs may be expensed by independent producers.
Integrated producers may expense 70 percent of IDCs
and write off the remainder over a five-year period.
The last capital expense category is the drilling
equipment itself. This is written off over a seven-year
period under double-declining-balance depreciation
rules. Drilling equipment constituted in 2006 roughly
5 percent of the total capital costs of new projects,
according to U.S. Energy Information Administration
(2007a) (table B14). Depletable costs constituted
roughly 28 percent of total costs, and IDCs accounted
for 67 percent of costs.
Oil and gas drilling receives an additional depreciation
benefit from the ability to expense dry holes. One
can view dry holes as part of the cost of drilling
a successful well. This tax provision raises the effective
value of the depreciation deductions for oil rigs.
Technology, however, has reduced the percentage of
dry holes. In 1960, 40 percent of all wells drilled
were dry holes. By 2007, that percentage had fallen
to 12 percent, reducing the tax advantage of dry-hole
3. Production and Investment Tax Credits
The federal tax code includes a number of production
and investment tax credits on fossil, alternative,
nuclear, and renewable fuels. These are included as
part of the general business credit (GBC) and subject
to AMT limitations. Carlson and Metcalf (2008) provide
evidence that energy firms are restricted in their
ability to use all their GBCs. While the AMT plays
a role, regular tax limitations play a more significant
role in limiting the use of GBCs. The important energy-related
production and investment credits include the following:
a. Nonconventional Oil-Production Credit
The Alternative Fuel Production Credit for production
of nonconventional oil (e.g., shale oil, synthetic
fuel oils from coal) provides for an oil-equivalent
production tax credit of $3.00 per barrel (indexed
in 1979 dollars and worth $6.79 in 2005). The 2005
energy act adds coke and coke gas to the list of qualified
fuels and makes the credit part of the general business
credit. The credit phases
out for oil prices above $23.50 in 1979 dollars ($53.20
in 2005). With higher crude-oil prices in 2006 and
2007, the credit was partially phased out, with a
loss of 32 percent of its value in 2006 and 67 percent
in 2007. The credit for coke and coke gas does not
phase out and was worth $3.28 last year (in nominal
b. Production Tax Credits for Electricity Provided
from Renewable Sources
Production tax credits are provided at a rate of 1.5¢
per kWh of electricity (indexed in 1992 dollars) generated
from wind, biomass, poultry waste, solar, geothermal
and other renewable sources.
Currently, the rate is 2.0¢ per kWh. Firms may
take the credit for ten years. Refined coal is also
eligible for a production credit at the current rate
of $5.877 per ton. The Energy
Policy Act of 2005 added new hydropower and Indian
coal, with the latter receiving a credit of $1.50
per ton for the first four years and $2.00 per ton
for three additional years (in real dollars).
Production tax credits have historically been authorized
by Congress for a two- year period. Considerable uncertainty
has arisen a number of times as to whether Congress
would reauthorize the credit. The credit actually
lapsed in three years (2000, 2002, and 2004), though
it was subsequently reauthorized retroactively. Distinct
declines in wind investment occurred in each of those
periods of uncertainty, as documented in Wiser and
Bolinger (2008). The credit for wind and other renewables
was renewed in the Emergency Economic Stabilization
Act of 2008, passed in October 2008. The credit for
solar was extended for eight years, through 2016,
while wind received a one-year extension and other
renewables a two-year extension.
c. Other Production Tax Credits
The 2005 energy act provided a production tax credit
for electricity produced at nuclear-power plants (section
45J). Qualifying plants are eligible for a 1.8¢
per kWh production tax credit for eight years, up
to an annual limit of $125 million per 1,000 megawatts
of installed capacity. This limit will be binding
on a nuclear-power plant with a capacity factor of
80 percent or higher. The law places an aggregate
limit of 6,000 megawatts of capacity eligible for
The American Jobs Creation Act of 2004 (PL 108-357)
created a production credit (section 45I) for marginal
oil and gas producers of $3.00 per barrel of oil ($0.50
per thousand cubic feet [mcf] of natural gas) in year
2005 dollars. The full credit is available when oil
(gas) prices fall below $15 per barrel ($1.67 per
mcf) and phases out when prices reach $18 per barrel
($2.00 per mcf). Marginal
wells produce, on average, fifteen or fewer barrels
of oil (or oil equivalent) per day.
This same law provided for small-refinery expensing
of 75 percent of capital costs associated with low-sulfur
diesel-fuel production and a 5¢ per gallon small-refiners
credit for the remaining 25 percent of qualified capital
costs for the production of low-sulfur diesel fuel.
The 2005 Energy Policy Act allowed a pass-through
of this credit to owners of cooperatives.
d. Investment Tax Credits
A 30 percent investment tax credit is available for
solar installations as well as fuel cells used to
produce electricity. A 10 percent credit is available
for qualifying microturbine power plants. In addition
to credits for renewable energy, the Energy Policy
Act of 2005 enacted credits for investments in certain
clean-coal facilities. Integrated gasification combined-cycle
(IGCC) plants are eligible for a 20 percent credit
(up to a maximum of $800 million in credits); other
advanced coal-based projects are eligible for a 15
percent credit (up to a maximum of $500 million in
credits); and certified gasification projects are
also eligible for a 20 percent credit (to a maximum
of $350 million in credits).
As it did with respect to the production tax credit
for renewable electricity, uncertainty existed last
year over the fate of the 30 percent investment tax
credit for solar power. Hassett and Metcalf (1999)
analyze a model in which government tax policy is
randomized (or appears random to investors). Their
model predicts that as the probability increases that
an investment tax credit will be allowed to expire,
firms will speed up investment to take advantage of
it in time. This phenomenon appeared to occur last
year, when it was unclear whether the tax credits
would be renewed. Johnson (2008) notes that a rush
to ensure the installation of solar panels before
the end of the year occurred, and that it drove up
the panels price.
The Omnibus Budget Reconciliation Act of 1990 contained
a provision for a 15 percent credit (section 43) for
expenditures on enhanced oil-recovery tangible property
and intangible drilling and development costs and
other related capital expenditures. The credit is
phased out when the section 29 reference oil price
exceeds $28 in 1990 dollars ($37.44 for 2005). Given
the run-up in oil prices over the past five years,
producers cannot currently take this credit.
e. Section 40 Alcohol and Biodiesel Fuels Credit
The Energy Policy Act of 1978 included an exemption
from the motor fuels excise tax for alcohol and alcohol-blended
fuels, generically known as gasohol.
The Windfall Profits Tax allowed an immediate tax
credit in lieu of the exemption.
The credit was set at a rate equivalent to the tax
exemption. The alcohol-fuel-mixture credit is currently
$0.51 per gallon of ethanol in gasohol and $0.60 for
other alcohol-based fuels (excluding petroleum-based
alcohol fuels). In addition, small producers may take
a credit of $0.10 per gallon. The 2005 Energy Policy
Act increased the small-producer production-capacity
limit from 30 million to 60 million gallons per year.
The American Jobs Creation Act also added section
40A to the code to provide an income-tax credit for
biodiesel fuels at a rate of $0.50 per gallon of biodiesel
(other than agri-biodiesel) and $1.00 for agri-biodiesel.
Like the alcohol-fuel tax credit, it is first applied
to motor-fuel excise tax payments, with the excess
added to the general business credit.
B. State Tax Provisions
Most states levy a corporate income tax, with top
rates in 2006 that varied from 2 to 12 percent. Thirty-five
states impose severance taxes on mineral extraction
within their borders, and forty-five states impose
public-utilities taxes in some form. Table 7 lists
the top ten states in severance-tax and public-utilities-tax
collections ranked by amount of collections in fiscal
year 2007. Texas, Alaska, and Oklahoma lead the list
in severance taxes and account for over half of total
U.S. severance-tax collections in that year. These
three states were among the top five oil-producing
states in 2007 (the other two states are Louisiana
and California). Wyoming is a significant oil-and-gas-producing
state as well as the largest coal-producing state
in the country. While I do not have detailed data
breaking out severance-tax collections by fuel, it
appears that oil and gas are responsible for the lions
share of revenue. The ten states in Table 7 account
for over 90 percent of severance-tax collections in
2006. For many of these states, severance taxes account
for a large fraction of total state tax revenues.
Public-utilities taxes are less concentrated. The
top three states account for under 40 percent of total
public-utilities taxes, and the top ten states account
for 82 percent of total collections. In aggregate,
severance-tax collections are roughly the same as
public-utilities tax collections.
In my analysis below of the impact of taxes on energy
investment, I use an average state corporate tax rate
of 6.6 percent, which, when combined with the federal
corporate tax rate of 35 percent, gives a total corporate
tax rate of 39.3 percent.
I assume that severance taxes reduce the price paid
to owners of land on which the taxed energy sources
are found for the right to extract the resource. This
assumption follows from the inelasticity of each states
supply of reserves and the ease with which consumers
can substitute one states supply for anothers.
I also assume that public-utilities taxes (excise
taxes on the sale of energy, for the most part) are
passed forward to consumers in the form of higher
energy prices and so do not affect the return on investment.
The effective rate measures help explain several
facts about recent trends in energy capital investment.
First, the recent boom in wind and solar renewable
investment, especially in wind, is consistent with
the large negative rates for wind and solar. Wind
capacity grew by nearly 50 percent in 2007 and accounted
for one-third of all new electrical capacity added
in that year (Wiser and Bolinger, 2008). This trend
continued in 2008, though it may be partly the result
of decisions to move projects up, if possible, and
into operation before the end of the year because
of uncertainty over the continuation of the production
Second, the production tax credit for new nuclear-power
plants is driving the large negative effective tax
rate on new nuclear-power construction and is likely
contributing to the resurgent interest in nuclear
construction. Combined construction- and operating-license
applications were filed for nine projects totaling
fifteen units, with 18.5 GW of capacity, between March
2007 and June 2008. Permits for over half of this
additional capacity were filed in this calendar year.
Since the Energy Policy Act of 2005 provides the nuclear
production tax credit for only the first 6 GW of capacity,
firms have a clear incentive to move early, before
the available credits are used up. While high natural-gas
prices and the possibility of carbon pricing make
nuclear power particularly attractive, high hurdles
for the construction and operation of any nuclear-power
plant remain, making the recent surge in interest
even more noteworthy.
Third, domestic oil and gas drilling increased markedly
with the run-up in oil prices. The number of crude-oil
rotary rigs in operation increased 28 percent between
July 2006 and July 2008, while the number of gas rigs
increased 12 percent. During this period, the domestic
first purchase price of crude oil nearly doubled (U.S.
Energy Information Administration, 2008b). The effective-tax-rate
estimates in Table 2 suggest that a strong incentive
exists for capital to flow to independent firms that
can take advantage of the benefits of percentage depletion
and the expensing of intangible drilling costs. Note
also that rising costs of extraction increase the
value of percentage depletion, as illustrated in Figure
Finally, despite the urgent need to upgrade and expand
the electricity transmission network, there is a lack
of investment incentives that would encourage the
flow of financial capital to this asset. This is particularly
worrisome given the need to move electricity from
remote sites that are well suited to renewable electricity
generation to high-demand areas. Generous production
and investment tax incentives for renewable energy
are undermined to the extent that the domestic electricity
transmission network cannot move this new power over
This paper provides a number of estimates of the
tax subsidies provided to different sources of energy
production in the United States. One measure simply
adds up estimates of energy-related tax expenditures
by fuel source in 2007. A review of these estimates
indicates that the distribution of tax subsidies by
fuel type has shifted over the past decade. The share
of tax expenditures for fossil fuels has dropped from
over 60 percent in 1997 to under 50 percent in 2007.
The subsidy share for renewable energy and end use/conservation
has risen from just under 40 percent to over 50 percent
in this same interval.
Effective Tax Rates for Energy Capital (DOWNLOAD PDF)
As for subsidies for electricity generation, refined
coal receives a very high subsidy per MWh of generation
($29.94), while renewable electricity receives a subsidy
on the order of $2 per MWh. Tax-based subsidies for
conventional coal, natural gas and petroleum, and
nuclear power are less than $0.25 per MWh.
The main contribution of this paper is the provision
of estimates of the effective tax rate on energy-related
investment in various types of energy capital. These
estimates differ from previous estimates in looking
at more disaggregated forms of energy capital than
are typically considered in calculations of effective
tax rates. In addition, I consider energy-specific
tax provisions that most previous analyses have not
taken into account. I find that effective tax rates
can vary from as high as 39 percent to as low as -245
percent. For electricity generation, production and
investment tax credits contribute to large negative
effective tax rates. Short recovery periods for depreciation
also contribute to low effective tax rates, but to
a lesser extent than do tax credits. Percentage-depletion
rules produce a negative effective tax rate for independent
oil-drilling firms. With other factors held constant,
an increase in extraction costs for new oil drives
the effective tax rate down for firms taking percentage
The results of this analysis shed light on the differential
tax treatment of energy sources in the United States.
An obvious next step is to investigate the extent
to which variation in tax subsidies by fuel source
affects energy investment. The effective-tax-rate
measures constructed here are necessary inputs for
such an analysis.
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