Oil and Gas Tax Subsidies: Current Status and Analysis

Congressional research reportFeb 27, 2007

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Prepared for Members and Committees of Congress

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The CLEAN Energy Act of 2007 (H.R. 6) was introduced by the House Democratic leadership to

revise certain tax and royalty policies for oil and natural gas and to use the resulting revenue to

support a reserve for energy efficiency and renewable energy. Title I proposes to repeal certain oil

and natural gas tax subsidies, and use the resulting revenue stream to support the reserve. The

Congressional Budget Office (CBO) estimates that Title I would repeal about $7.7 billion in oil

and gas tax subsidies over the 10-year period from 2008 through 2017. In House floor debate,

opponents argued that the cut in oil and natural gas subsidies would dampen production, cause

job losses, and lead to higher prices for gasoline and other fuels. Proponents counterargued that

record profits show that the oil and natural gas subsidies were not needed. The bill passed the

House on January 18 by a vote of 264-123. This report presents a detailed review of oil and gas

tax subsidies, including those targeted for repeal by H.R. 6.

The Energy Policy Act of 2005 (EPACT05, P.L. 109-58) included several oil and gas tax

incentives, providing about $2.6 billion of tax cuts for the oil and gas industry. In addition,

EPACT05 provided for $2.9 billion of tax increases on the oil and gas industry, for a net tax

increase on the industry of nearly $300 million over 11 years. Energy tax increases comprise the

oil spill liability tax and the Leaking Underground Storage Tank financing rate, both of which are

imposed on oil refineries. If these taxes are subtracted from the tax subsidies, the oil and gas

refinery and distribution sector received a net tax increase of $1,356 million ($2,857 million

minus $1,501 million).

EPACT05 was approved and signed into law at a time of very high petroleum and natural gas

prices and record oil industry profits. The House approved the conference report on July 28,

2005, and the Senate on July 29, 2005, clearing it for the President’s signature on August 8 (P.L.

109-58). However, the tax sections originated in the106th Congress, with its effort in 1999 to help

the ailing domestic oil and gas producing industry, particularly small producers, deal with

depressed oil prices. Subsequent price spikes prompted concern about insufficient domestic

energy production capacity and supply. All the early bills appeared to be weighted more toward

stimulating the supply of conventional fuels, including capital investment incentives to stimulate

production and transportation of oil and gas.

In addition to the tax subsidies enacted under EPACT05, the U.S. oil and gas industry qualifies

for several other targeted tax subsidies (FY2006 revenue loss estimates appear in parenthesis): (1)

percentage depletion allowance ($1 billion); (2) expensing of intangible drilling costs for

successful wells and non-geological and geophysical costs for dry holes, including the exemption

from the passive loss limitation rules that apply to all other industries ($1.1 billion); (3) a tax

credit for small refiners of low-sulfur diesel fuel that complies with Environmental Protection

Agency (EPA) sulfur regulations ($ 50 million); (4) the enhanced oil recovery tax credit ($0); and

(5) marginal oil and gas production tax credits ($0).

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Action in the 110th Congress ........................................................................................................... 1

Background ..................................................................................................................................... 1

Policy Context and Analysis............................................................................................................ 2

Oil and Gas Tax Provisions in EPACT05 and their Revenue Effects.............................................. 4

Amortization of Geological and Geophysical Expenditures..................................................... 5

Determination of Independent Producer Status for Purposes of the Oil Depletion

Deduction............................................................................................................................... 6

Natural Gas Distribution Lines Treated as 15-Year Property.................................................... 7

Temporary Expensing for Equipment Used in Oil Refining..................................................... 8

Arbitrage Rules Not To Apply to Prepayments for Natural Gas ............................................... 8

Natural Gas Gathering Lines Treated as Seven-Year Property ................................................. 8

Pass Through to Owners of Deduction for Capital Costs Incurred by Small Refiner

Cooperatives in Complying with EPA Sulfur Regulations .................................................... 9

Modification and Extension of Credit for Producing Fuel from a Nonconventional

Source for Facilities Producing Coke or Coke Gas.............................................................. 10

Revenue Effects .......................................................................................................................11

Tax Increases........................................................................................................................... 13

Other Oil and Gas Tax Subsidies................................................................................................... 13

Other Oil and Gas Tax Subsidies ............................................................................................ 14

General Tax Provisions that May Benefit the Oil and Gas Industry ............................................. 17

Table 1. Energy Tax Provisions in the Energy Tax Act of 2005 (P.L. 109-58): 11-Year

Estimated Revenue Loss, by Type of Incentive ......................................................................... 12

Table 2. Special Tax Incentives Targeted for the Oil and Gas Industry and Estimated

Revenue Losses, FY2006........................................................................................................... 15

Author Contact Information .......................................................................................................... 19

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The CLEAN Energy Act of 2007 (H.R. 6) was introduced by the House Democratic leadership to

revise certain tax and royalty policies for oil and natural gas and to use the resulting revenue to

support a reserve for energy efficiency and renewable energy. The bill is one of several

introduced on behalf of the Democratic leadership in the House as part of its “100 hours” package

of legislative initiatives conducted early in the 110th Congress.

Title I proposes to repeal certain oil and natural gas tax subsidies, and use the resulting revenue

stream to support the reserve. According to the Congressional Budget Office (CBO), the

provisions in Title I would make about $7.7 billion available for the reserve over the 10-year

period from 2008 through 2017.1

H.R. 6 came to the House floor for debate on January 18, 2007. In the floor debate, opponents

argued that the reduction in oil and natural gas incentives would dampen production, cause job

losses, and lead to higher prices for gasoline and other fuels. Opponents also complained that the

proposal for the Reserve does not identify specific policies and programs that would receive

funding. Proponents of the bill counterargued that record profits show that the oil and natural gas

incentives were not needed. They also contended that the language that would create the Reserve

would allow it to be used to support a variety of research and development (R&D), deployment,

tax incentives, and other measures for renewables and energy efficiency, and that the specifics

would evolve as legislative proposals come forth to draw resources from the Reserve. The bill

passed the House on January 18 by a vote of 264-123.

The Energy Policy Act of 2005 (P.L. 109-58), enacted on August 8, 2005, expanded some of the

existing tax subsidies for the oil and gas industry and created several new ones.2 The oil and gas

tax incentives in EPACT05 were added on top of several existing special tax subsidies for oil and

gas. The industry also benefits from provisions of current tax law that are not strictly tax

subsidies (or tax expenditures) but that nevertheless provide advantages for and reduce effective

tax rates of the oil and gas industry.

The remainder of this report discusses these tax provisions in detail. The first section, below,

discusses the origin and evolution of the oil and gas tax subsidies that were incorporated into the

2005 act. The second section summarizes each of the oil and gas tax subsidy provisions in the

2005 energy act and reports its corresponding revenue loss estimate. Section three describes other

oil and gas tax subsidies, those that existed before EPACT05 and were generally not affected by

it. The final section describes several tax provisions that benefit the oil and gas industry; these are

not tax subsidies per se—they are not considered to be tax expenditures—but are deemed by

some observers to confer excessive (or unfair) benefits for the industry.

U.S. Congress. Congressional Budget Office. H.R. 6, CLEAN Energy Act of 2007. (Letter to Chairman Nick Rahall,

Committee on Natural Resources.) Jan. 12, 2007. 4 p. http://www.cbo.gov/ftpdocs/77xx/doc7728/hr6prelim.pdf

For a summary and analysis of this law, see CRS Report RL33302, Energy Policy Act of 2005: Summary and Analysis

of Enacted Provisions. The two-year amortization period was slowed down to five years for integrated producers under

2006 tax legislation, as discussed in the text.

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Tax incentives for oil and gas supply have historically been an integral (if not the primary)

component of the nation’s energy policy. The domestic oil and gas industry was granted three tax

code preferences, or subsidies: (1) expensing of intangible drilling costs (IDCs) and dry hole

costs, introduced in 1916; (2) the percentage depletion allowance, first enacted in 1926 (coal was

added in 1932); and (3) capital gains treatment of the sale of oil and gas properties.3 These tax

subsidies reduced marginal effective tax rates in the oil and gas industries, reduced production

costs, and increased investments in locating reserves (increased exploration). They also led to

more profitable production, some acceleration of oil and gas production, and more rapid depletion

of energy resources than would otherwise occur. Partially in response to tax incentives, but also

due to the low cost of discovering and developing the huge new resource base, there were

discoveries during the 1930s of vast reserves in Texas, which led to a period of overproduction of

oil and gas and concomitant declines in prices, which led to demand to prorationing under the

Texas Railroad Commission.4

Beginning in the 1970s and through much of the 1990s, energy tax policy shifted away from

fossil fuel supply and moved toward energy conservation through both energy efficiency and the

development of alternative and renewable fuels. However, rising and repeated spikes in

petroleum prices that began around 2000 and were repeated over the next six years (combined

with high and spiking natural gas prices, an electricity crisis, and blackouts) caused policymakers

to focus on increasing energy production and supply of many diverse energy sources, including

oil and gas.

The tax incentives for the oil and gas industry in the EPACT05 originated in the106th Congress’s

effort in 1999 to help the ailing domestic oil and gas producing industry, particularly small

producers, deal with depressed oil prices. This situation fostered proposals for economic relief

through the tax code, particularly for small independent drillers and producers. Proposals focused

mainly on production tax credits for marginal or stripper well oil,5 but they also included carryback provisions for net operating losses, and other fossil fuel supply provisions.6 Subsequent

comprehensive energy policy legislation, including H.R. 4 in the107th Congress, proposed an

expanded list of oil and gas tax incentives. The energy tax breaks in this bill (the Securing

America’s Future Energy Act of 2001, as approved by the House on August 1, 2001) were larger

in terms of tax revenue loss than any other comprehensive energy policy legislation proposed

during this period. They also were larger than those proposed in EPACT05: $33.5 billion of

energy tax cuts, compared with the $14.5 billion loss eventually enacted under P.L. 109-58.

As discussed later, these subsidies were largely eliminated on much of the oil production and assets, but other, less

significant subsidies—the special exemption from the passive loss limitation rules and some special tax credits—were

added to the tax code.

Glasner, David, Politics, Prices, and Petroleum: The Political Economy of Energy, Pacific Institute for Public Policy

Research, 1985, pp. 142-144.

A stripper well is one that produces small quantities of oil and natural gas. The tax law currently defines this limit as

15 barrels of oil or the equivalent amount of natural gas per day; the oil and gas industry defines it 10 barrels per day or

less.

Although no tax bill was passed that reduced taxes on oil and gas, the 106th Congress did enact a package of $500

million in loan guarantees for small independent producers, which became law (P.L. 106-51), in August 1999.

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Interest in incentives and subsidies was boosted by the belief that much of the crisis was caused

by insufficient domestic production capacity and supply. All the early bills appeared to be

weighted more toward stimulating the supply of conventional fuels, including capital investment

incentives to stimulate production and transportation of oil and gas. These proposals were further

repackaged and expanded into the first broadly based energy bills and comprehensive energy

policy legislation, such as H.R. 6 in the 109th, that evolved further and ultimately became

EPACT05.7 The House approved the conference report on July 28, 2005, and the Senate on July

29, 2005, clearing it for the President’s signature on August 8 (P.L. 109-58).

The 2005 act became law at a time of very high prices for crude oil, petroleum products, and

natural gas, and record oil and gas industry profits. This engendered the enmity of the general

public and congressional proposals to (1) revoke the incentives enacted under the 2005 act; (2)

repeal or pare back the historical, but extant, tax subsidies and other tax advantages; and (3)

impose sizeable new taxes on the industry such as a windfall profit tax.8

Public and congressional outcry did lead to a paring back of one of the tax subsidies liberalized in

the 2005 act: two-year amortization, rather than capitalization, of geological and geophysical

(G&G) activity costs, including those associated with abandoned wells (dry holes).9 This

exploration subsidy was the largest upstream tax subsidy (as opposed to a “downstream” or a

refinery subsidy), in terms of federal revenue loss, enacted under the 2005 act, although it was

and still is a relatively small tax subsidy. The Tax Increase Prevention and Reconciliation Act

(P.L. 109-222), signed into law in May 2006, reduced the value of the subsidy by raising the

amortization period for major integrated oil companies from two years to five years, still faster

than the capitalization treatment before the 2005 act, but slower than the treatment under that act.

Independent (nonintegrated) oil companies may continue to amortize all G&G costs over two

years.

This relatively minor cutback has not muted the calls for rolling back oil and gas tax subsidies, as

petroleum prices (and industry profits) remain somewhat high, particularly those of the biggest oil

and gas companies. On September 1, 2006, the House Democratic leadership reportedly sent a

letter to the House Speaker proposing a rollback of all of the 2005 energy act tax subsidies.10 On

October 25, 2006, then-House Democratic Leader Nancy Pelosi, urged the Congress to repeal

those tax breaks.

Many bills were introduced in the 109th Congress to pare back or repeal the oil and gas industry

tax subsidies and other loopholes. Many of the bills focused on the oil and gas exploration and

development (E&D) subsidy—expensing of intangible drilling costs (IDCs). This subsidy, which

has been in existence since the early days of the income tax, is available to integrated and

After some existing energy tax incentives expired in 2003, the 108th Congress enacted retroactive extension of several

of the provisions as part of the Working Families Tax Relief Act of 2004 (P.L. 108-311). That law, which reduced

revenues by about $1.3 billion over 10 years, was enacted on October 4, 2004. About $5 billion in energy tax

incentives—both expansion or liberalization of some of the more popular energy tax provisions, as well as some new

energy tax incentives—were part of the American Jobs Creation Act of 2004 (P.L. 108-357) enacted on October 22,

2004.

For an analysis of the windfall profit tax, see CRS Report RL33305, The Crude Oil Windfall Profit Tax of the 1980s:

Implications for Current Energy Policy, by (name redacted).

Prior to the 2005 act, G&G costs for dry holes were expensed in the first year and capitalized for successful wells.

Bureau of National Affairs, Daily Tax Report. House Democratic Leadership Letter to Speaker Hastert Asking for

Rollback of Tax Breaks for Oil Companies, Sept. 5, 2006.

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independent oil and gas companies, both large and small alike.11 It is an exploration and

development incentive, which allows the immediate tax write-off of what economically are

capital costs, that is, the costs of creating a capital asset (the oil and gas well). On September 18,

2006, Senators Wyden and Bennett introduced a bill (S. 3908) to give consumers a discount on

the purchase of more fuel efficient vehicles that would have been paid for by reducing the IDCs

deduction for major integrated oil companies. Comprehensive energy legislation (S. 2829)

unveiled by Senate Democrats on May 17, 2006, would have not only eliminated expensing of

IDCs, but would have also reduced several other tax benefits (or loopholes) to the oil and gas

industry (such the foreign tax credits). The latter are not subsidies (or tax expenditures) in the

strict sense of special tax measures unavailable generally, but as discussed below, some consider

these unnecessary tax benefits nonetheless.12 H.R. 5234 focused on repealing three of the seven

fossil fuel tax provisions in the 2005 act: temporary expensing of equipment costs for crude oil

refining, the small refiner exception to percentage depletion, and the amortization of geological

and geophysical (G&G) costs. H.R. 5218 would have denied oil and gas companies the new

domestic manufacturing deduction under IRC § 199.

There is speculation that in the 110th Congress, the Democratic leadership in both the House and

Senate will begin to examine these breaks more closely, particularly because many of their

legislative priorities (such as cutting back the increasingly heavy burden of the alternative

minimum tax) will have to be paid for.13

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EPACT05 included a plethora of spending, tax, and deregulatory incentives to stimulate the

production of conventional and unconventional oil and natural gas, such as gas from Alaska, deep

water oil and gas in the outer continental shelf, and oil from marginal wells or private and federal

lands. These incentives include tax breaks, royalty relief, streamlined permitting procedures, and

other measures. The tax incentives include approximately $14.5 billion over 11 years of

incentives to both stimulate domestic production and distribution of fossil fuels and reduce the

demand for these fuels through energy efficiency and production of alternative and renewable

fuels.

Title XIII, subtitle B, of EPACT05 includes the tax incentives for fossil fuel supply—for

production, transportation, and distribution—of oil and gas, as well as capital incentives for

expanded refinery capacity. The subtitle does not include coal supply incentives, which are

subsumed in the electricity infrastructure subtitle. Although many of the oil and gas tax incentives

in EPACT05 are production tax credits and other such “upstream” production incentives, some

are capital incentives for natural gas infrastructure (accelerated depreciation of natural gas

As discussed below, many of the remaining tax subsidies are available only to independent oil and gas producers,

which, however, may be very large.

There is an important economic distinction between a subsidy and a tax benefit. As is discussed elsewhere in this

report, firms receive a variety of tax benefits that are not necessarily targeted subsidies (or tax expenditures) because

they are available generally.

McKinnon, John D. “Are Higher Taxes in the Offing?” The Wall Street Journal, Oct. 30, 2006, p. A-6; Bureau of

National Affairs, “Menu of Proposals Available to Democrats Looking to Roll Back Oil, Energy Tax Breaks,” Daily

Tax Report, Nov. 14, 2006, p. G-2.

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pipelines). In total, the tax incentives alone are worth about $2.6 billion over 11 years to the

industry (an average of about $250 million a year in tax breaks).14

Subtitle B, thus, applies specifically to the oil and gas industry, including the refinery industry, for

increased supply incentives. Tax incentives are provided—again mostly by liberalization of

existing tax code provisions. The incentives are both production incentives (i.e., tax benefits are

based on quantities of oil and gas) and capital incentives (i.e., tax benefits are based on magnitude

of capital investment, such as pipelines). Both unconventional and conventional oil and gas

supply are targeted for tax cuts.

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Firms engaged in the exploration and development (E&D) of oil and gas incur a variety of costs

prior to actual extraction. The tax treatment of these “upstream” E&D costs differs depending on

the specific type of activity and depending on whether they are incurred by an integrated or

nonintegrated (i.e., independent) producer. An independent producer is defined by Internal

Revenue Code (IRC) § 613A(d), as described below.

E&D costs may be generally categorized as four types. First, there are the geological and

geophysical costs (G&G). These are exploratory costs (such as for seismic surveys) associated

with determining the precise location and potential size of a mineral deposit. A second type of

cost is the mineral acquisition or lease rights expenses—the costs of buying or leasing the land

under which deposits are thought to exist—such as lease bonuses.

If a property is considered prospective for containing economically recoverable deposits of oil or

gas, the firm drills exploratory (and, if successful, subsequently development) wells to ascertain

the magnitude of the deposits. These activities have associated various types of drilling costs.

Tangible drilling costs, the third type of E&D costs, are amounts paid for tangible drilling and

nondrilling equipment such as drilling rigs, casings, valves, pipelines, and other tangible

machinery and equipment that have a salvage value. Finally, there are intangible drilling costs, or

IDCs as they are frequently called. IDCs are amounts paid by the lease operator for fuel, labor,

repairs to drilling equipment, materials, hauling, and supplies. They are expenditures incident to

and necessary for the drilling of wells and preparing a site for production of oil and gas. For

example, roads may have to be constructed to move in derricks and other types of drilling

equipment; often a camp may have to be built with residences to house employees. The power for

the equipment and the water supplies are also IDCs. IDCs also may include the cost to operators

of any exploratory drilling or development work done by contractors under any form of contract,

including a turnkey contract.

In general, as noted above, prior to EPACT05, all four types of costs—G&G costs, mineral rights,

tangible equipment, and intangible drilling costs—associated with a dry hole were expensable

(i.e., deductible in the year in which the well was determined to be dry). Under the 2005 act, both

integrated and independent producers were required to amortize the G&G component of the dry

hole costs over two years. This reduced the incentive for G&Gs associated with a dry hole but

increased the incentive for G&Gs associated with most successful wells. This provision became

These are CRS compilations based on Joint Committee on Taxation estimates. See U.S. Congress, Joint Committee

on Taxation, Estimated Budget Effects of the Conference Agreement for Title XIII of H.R. 6, The “Energy Tax

Incentives Act of 2005,” July 27, 2005, JCX-59-05.

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effective for G&G amounts paid or incurred in taxable years beginning after the date of

enactment.

Two-year amortization of G&G costs is still allowed for independent producers, but as a result of

a provision in the Tax Increase Prevention and Reconciliation Act (P.L. 109-222, enacted in May

2006), integrated producers must now amortize such costs over five years.15 Amortization means

that the costs are deducted evenly—the same absolute dollars are taken as deductions every year

over a specified period of time, in this case two or five years. It is also called straight-line

depreciation.16

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Firms that extract oil, gas, or other minerals are permitted a deduction to recover their capital

investment in a mineral reserve, which depreciates due to physical and economic depletion or

exhaustion as the mineral is recovered (IRC § 611). Depletion, like depreciation, is a form of

capital recovery: an asset, the mineral reserve itself, is being expended to produce income. Under

the income tax, such a loss in value or cost is deductible.

There are two methods of calculating this deduction: cost depletion and percentage depletion.

Cost depletion allows for the recovery of the actual capital investment—the costs of discovering,

purchasing, and developing a mineral reserve. Each year, and over the period during which the

reserve produces income, the taxpayer deducts a portion of the adjusted basis (original capital

investment less previous deductions) equal to the fraction of the estimated remaining recoverable

reserves that have been extracted and sold. Under this method, the total deductions cannot exceed

the original capital investment.

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

as set by law of the “gross income” (i.e., revenue) from the sale of the mineral. Under this

method, total deductions typically exceed, despite the limitations, the capital invested to acquire

and develop the reserve.

IRC § 613 states that mineral producers must claim the higher of cost or percentage depletion.

The percentage depletion rate for oil and gas is 15% and is limited to average daily production of

1,000 barrels of oil, or its equivalent in gas. For producers of both oil and gas, the limit applies on

a combined basis. For example, an oil-producing company with 2006 oil production of 100,000

barrels and natural gas production of 1.2 billion cubic feet (the statutory equivalent of 200,000

barrels of oil) has average daily production of 821.92 barrels (300,000 ÷ 365 days). Percentage

depletion is not available to integrated major oil companies; it is available only for independent

producers and royalty owners.

Beginning in 1990, the percentage depletion rate was raised on production from marginal wells—

oil from stripper wells (those producing no more than 15 barrels per day, on average) and heavy

The 2006 amendment constitutes a reduction in the tax benefits and was part of the compromise for allowing the

G&G costs of successful wells to be amortized over two years rather than capitalized.

The term amortization is also used in tax parlance as referring to the depreciation of intangible property, such as

patents and copyrights.

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oil. This rate starts at 15% and increases by one percentage point for each whole $1 that the

reference price of oil for the previous calendar year is less than $20 per barrel (subject to a

maximum rate of 25%). This higher rate is also limited to independent producers and royalty

owners, and for up to 1,000 barrels, determined as before on a combined basis (including nonmarginal production). Small independents operate nearly 400,000 small stripper wells in about 28

states, about 78% of the nearly 510,000 producing wells in the United States. Output from

stripper wells represented about 16% of total domestic production (about 850,000 barrels per day)

in the United States in 2004.17

The percentage depletion deduction is limited to 65% of the taxable income from all properties

for each producer. A second limitation, the 100% net-income limitation, which applied to each

individual property rather than to all the properties, was retroactively suspended for oil and gas

production from marginal wells by the Working Families Tax Relief Act of 2004 (P.L. 108-311)

through December 31, 2005. The 100% net-income limitation also had been suspended from

1998 to 2003. The difference between percentage depletion and cost depletion is considered a

subsidy. It was once a tax preference item for purposes of the alternative minimum tax, but this

was repealed by the Energy Policy Act of 1992 (P.L. 102-486).

The percentage depletion allowance is available for other types of fuel minerals, at rates ranging

from 10% (coal, lignite) to 22% (uranium), and for mined hard rock minerals. The rate for

regulated natural gas and gas sold under a fixed contract is 22%; the rate for geo-pressurized

methane gas is 10%. Oil shale and geothermal deposits qualify for a 15% allowance. The netincome limitation to percentage depletion for coal and other fuels is 50%, compared with 100%

for oil and gas. Under code section 291, percentage depletion on coal mined by corporations is

reduced by 20% of the excess of percentage over cost depletion.

For purposes of percentage depletion, before EPACT05, an independent oil producer was one

that, on any given day, (1) did not refine more than 50,000 barrels of oil and (2) did not have a

retail operation grossing more than $5 million a year (IRC § 613A[d]). EPACT05 raised the

50,000 barrel daily limit to 75,000. In addition, the act changed the refinery limitation from actual

daily production to average daily production for the taxable year. Accordingly, the average daily

refinery runs for the taxable year may not exceed 75,000 barrels. For this purpose, the taxpayer

would calculate average daily refinery runs by dividing total refinery runs for the taxable year by

the total number of days in the taxable year. This is effective for taxable years ending after the

date of enactment.

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For purposes of determining the depreciation deduction, EPACT05 established a 15-year recovery

period for natural gas distribution lines. Prior to this amendment, natural gas distribution lines

were assigned a 20-year recovery period. This provisions is effective for property, the original use

of which begins with the taxpayer after April 11, 2005, which is placed in service after April 11,

2005, and before January 1, 2011, and does not apply to property subject to a binding contract on

or before April 11, 2005.

Both the number of stripper wells and oil output from such wells is reported in American Petroleum Institute, Basic

Petroleum Data Book, vol. 26, no. 2, (section IV, table 3), August 2006.

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Before the enactment of EPACT05, depreciation rules (the Modified Accelerated Cost Recovery

System, MACRS) required oil refinery assets to be depreciated over 10 years using the double

declining balance method.18 Under the 2005 act, refineries are allowed to irrevocably elect to

expense 50% of the cost of qualified refinery property, with no limitation on the amount of the

deduction. This provision was enacted to increase investments in existing refineries so as to

increase petroleum product output and reduce prices.

The expensing deduction is allowed in the taxable year in which the refinery is placed in service.

The remaining 50% of the cost remains eligible for regular cost recovery provisions. To qualify

for the deduction (1) original use of the property must commence with the taxpayer; (2)(a)

construction must be pursuant to a binding construction contract entered into after June 14, 2005,

and before January 1, 2008, (b) in the case of self-constructed property, construction began after

June 14, 2005, and before January 1, 2008, or (c) the refinery is placed in service before January

1, 2008; (3) the property must be placed in service before January 1, 2012; (4) the property must

meet certain production capacity requirements if it is an addition to an existing refinery; and (5)

the property must meet all applicable environmental laws when placed in service. Certain types of

refineries, including asphalt plants, are not eligible for the deduction, and there is a special rule

for sale-leasebacks of qualifying refineries. If the owner of the refinery is a cooperative, it may

elect to allocate all or a part of the deduction to the cooperative owners, allocated on the basis of

ownership interests. This provision is effective for qualifying refineries placed in service after

date of enactment (i.e., it became effective on August 9, 2005).

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EPACT05 creates a safe harbor exception to the general rule that tax-exempt, bond-financed

prepayments violate the tax code’s arbitrage restrictions. The term investment-type property does

not include a prepayment under a qualified natural gas supply contract. The act also provides that

such prepayments are not treated as private loans for purposes of the private business tests. Thus,

a prepayment financed with tax-exempt bond proceeds for the purpose of obtaining a supply of

natural gas for service area customers of a governmental utility would not be treated as the

acquisition of investment-type property. The safe harbor provisions do not apply if the utility

engages in intentional acts to render (1) the volume of natural gas covered by the prepayment to

be in excess of that needed for retail natural gas consumption and (2) the amount of natural gas

that is needed to fuel transportation of the natural gas to the governmental utility. This provision

is effective for obligations issued after date of enactment.

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Under tax law prior to the enactment of EPACT05, the recovery period for natural gas gathering

lines could be either 7 or 15 years, depending on whether they were classified as production or

transportation equipment. Several court cases reflected the ambiguous tax treatment. Natural gas

pipelines had a recovery period of 15 years, whereas natural gas distribution lines had a recovery

Under the double declining balance method of calculating depreciation deductions, the annual deduction is a fixed

percentage (200% or double the straight-line rate) of the difference between asset cost and prior year depreciation

deductions.

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period of 20 years (which, as noted above, was reduced to 15 years). EPACT05 assigned natural

gas gathering lines a seven-year recovery period for MACRS depreciation deductions.

EPACT05 defined a natural gas gathering line as the pipe, equipment, and appurtenances

determined to be a gathering line by the Federal Energy Regulatory Commission (FERC) or used

to deliver natural gas from the well-head or common point to the point at which the gas first

reaches (1) a gas processing plant, (2) an interconnection with an interstate transmission line, (3)

an interconnection with an intrastate transmission pipeline, or (4) a direct connection with a local

distribution company, a gas storage facility, or an industrial consumer. Also, the act requires that

the original use of the property begin with the taxpayer. This provision became effective for

property placed in service after April 11, 2005, excluding property with respect to which the

taxpayer or related party had a binding acquisition contract on or before April 11, 2005.

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IRC § 45H allows a small refiner to claim a tax credit for the production of low-sulfur diesel fuel

that is in compliance with Environmental Protection Agency (EPA) sulfur regulations (the

Highway Diesel Fuel Sulfur Control Requirements). The credit is $2.10 per barrel of low-sulfur

diesel fuel produced; it is limited to 25% of the capital costs incurred by the refiner to produce the

low-sulfur diesel fuel. The 25% limit is phased out proportionately as a refiner’s capacity

increases from 155,000 to 205,000 barrels per day.

Section 179B allows a small refiner to also claim a current year tax deduction (i.e., expensing), in

lieu of depreciation, for up to 75% of the capital costs incurred in producing low-sulfur diesel fuel

that is in compliance with EPA sulfur regulations. This incentive is also prorated for refining

capacity between 155,000 and 205,000 barrels per day. The taxpayer’s basis in the property that

receives the exemption is reduced by the amount of the production tax credit. In the case of a

refinery organized as a cooperative, both the credit and the expensing deduction may be passed

through to patrons.

For both incentives, a small business refiner is a taxpayer who (1) is in the business of refining

petroleum products, (2) employs not more than 1,500 employees directly in refining, and (3) has

less than 205,000 barrels per day (averaged over the year) of total refining capacity. The

incentives took effect retroactively beginning on January 1, 2003.

EPACT05 provided that cooperative refineries that qualify for § 179B expensing of capital costs

incurred in complying with EPA sulfur regulations could elect to allocate all or part of the

deduction to their owners, determined on the basis of their ownership interests. The election is

made on an annual basis and is irrevocable once made. The provision became effective as if

included in § 338(a) of the American Jobs Creation Act of 2004, which introduced the tax credit.

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Section 45K of the Internal Revenue Code (IRC) provides for a production tax credit of $3 per

barrel of oil-equivalent (in 1979 dollars) for certain types of liquid, gaseous, and solid fuels

produced from selected types of alternative energy sources (so-called “non-conventional fuels”)

and sold to unrelated parties. The full credit is available if oil prices fall below $23.50 per barrel

(in 1979 dollars); the credit is phased out as oil prices rise above $23.50 (in 1979 dollars) over a

$6 range (i.e., the inflation-adjusted $23.50 plus $6).

Both the credit and the phase-out ranges are adjusted for inflation (multiplied by an inflation

adjustment factor) since 1979. With an inflation adjustment factor of 2.264 (meaning that prices,

as measured by the Gross Domestic Product deflator, have more than doubled since 1979), the

credit for 2005 production was $6.79 per barrel of oil equivalent, which is the amount of the

qualifying fuel that has a British Thermal Unit (Btu) content of 5.8 million. The credit for gaseous

fuels was $1.23 per thousand cubic feet (mcf). The credit for tight sands gas is not indexed to

inflation; it is fixed at the 1979 level of $3 per barrel of oil equivalent (about $0.50 per mcf). In

2005, the reference price of oil, which was $50.76 per barrel, still below the inflation adjustment

phase-out threshold oil price of $53.20 for 2005 ($23.50 multiplied by 2.264), the full credit of

$6.56 per barrel of equivalent was available for qualifying fuels.

Qualifying fuels include synthetic fuels (liquid, gaseous, and solid) produced from coal, and gas

produced from either geopressurized brine, Devonian shale, tight formations, or biomass. To

qualify for the credit, synthetic fuels from coal must undergo a significant chemical

transformation, defined as a measurable and reproducible change in the chemical bonding of the

initial components. In most cases, producers apply a liquid bonding agent to the coal or coal

waste (coal fines), such as diesel fuel emulsions, pine tar, or latex, to produce a solid synthetic

fuel. The coke made from coal and used as a feedstock, or raw material, in steel-making

operations also qualifies as a synthetic fuel, as does the breeze (small pieces of coke) and the coke

gas (produced during the coking process). Depending on the precise Btu content of these

synfuels, the § 45K tax credit could be as high as $26 per ton or more, which is a significant

fraction of the market price of coal. Qualifying fuels must be produced within the United States.

The credit for coke and coke gas is also $3 per barrel of oil equivalent and is also adjusted for

inflation, but the credit is set to a base year of 2004, making the nominal unadjusted tax credit

less than for other fuels.

The section 45K credit for gas produced from biomass, and synthetic fuels produced from coal or

lignite, is available through December 31, 2007, provided that the production facility was placed

in service before July 1, 1998, pursuant to a binding contract entered into before January 1, 1997.

The credit for coke and coke gas is available through December 31, 2009, for plants placed in

service before January 1, 1992, and after June 30, 1998. The section 45K credit used to apply to

oil produced from shale or tar sands, and coalbed methane (a colorless and odorless natural gas

Two of the nine special tax subsidies for oil and gas in EPACT05 were for unconventional gases and synfuels from

coal under the § 45K tax credit. These provisions are discussed because the § 45K tax credit has been important to the

development of unconventional gases such as coalbed methane and tight sands gas. However, its revenue losses are

subsumed under the coal category of Table 1 largely because in recent years the provision has benefitted primarily the

coal industry by increasing the demand for coal.

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that permeates coal seams and that is virtually identical to conventional natural gas). However,

the credit for these fuels terminated on December 31, 2002 (and the facilities had to have been

placed in service, or wells drilled, by December 31, 1992).

The section 45K credit is part of the general business credit. It is not claimed separately; it is

added together with several other business credits and is also subject to the limitations of that

credit. The section 45K credit is offset (or reduced) by certain other types of government

subsidies that a taxpayer may benefit from: government grants, subsidized or tax-exempt

financing, energy investment credits, and the enhanced oil recovery tax credit that may be

claimed with respect to such projects. Finally, the credit is nonrefundable and cannot be used to

offset a taxpayer’s alternative minimum tax liability. Any unused section 45K credits generally

may not be carried forward or back to another taxable year. (However, under the minimum tax

section 53, a taxpayer receives a credit for prior-year minimum tax liability to the extent that a

section 45K credit is disallowed as a result of the operation of the alternative minimum tax.)

The Energy Policy Act of 2005 made several amendments to the section 45K tax credit. First, the

credit’s provisions were moved from § 29 of the tax code to new § 45K. Before this, this credit

was commonly known as the “section 29 credit.” Second, the credit was made available for

qualified facilities that produce coke or coke gas that were placed in service before January 1,

1993, or after June 30, 1998, and before January 1, 2010. Coke and coke gas produced and sold

during the period beginning on the later of January 1, 2006, or the date the facility is placed in

service, and ending on the date which is four years after such period begins, are eligible for the

production credit, but at a reduced rate and only for a limited quantity of fuel. The tax credit for

coke and coke gas is $3.00 per barrel of oil equivalent, but the credit is indexed for inflation

starting with a 2004 base year, compared with a 1979 base year for other fuels. A facility

producing coke or coke gas and receiving a tax credit under the previous § 29 rules is not eligible

to claim the credit under the new section 45K. The new provision also requires that the amount of

credit-eligible coke produced not exceed an average barrel-of-oil equivalent of 4,000 barrels per

day. Third, the 2005 act provided that with respect to the IRS moratorium on taxpayer-specific

guidance concerning the credit, the IRS should consider issuing rulings and guidance on an

expedited basis to those taxpayers who had pending ruling requests at the time that the IRS

implemented the moratorium. Finally, the 2005 legislation made the general business limitations

applicable to the tax credit. Any unused credits can be carried back one year and forward 20

years, except that the credit cannot be carried back to a taxable year ending before January 1,

2006. These new rules were made effective for fuel produced and sold after December 31, 2005,

in taxable years ending after that date.

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Table 1 shows the revenue effects of the tax provisions in EPACT05, organized by type of

incentive. These are the original revenue effects estimated for EPACT05, signed into law on

August 8, 2005, by the Joint Committee on Taxation (JCT). Because of changes to energy prices,

energy markets, and general economic conditions, revenue loss estimates of the same provisions

calculated today would most likely differ from those original estimates.

JCT’s estimated revenue losses were projected over an 11-year time frame, from FY2005 to

FY2015. The total revenue losses are reported in two ways: the absolute dollar value of tax cuts

over 11 years, and the percentage distribution of total revenue losses by type of incentive. Each of

the seven tax subsidies for the oil and gas industry are shown separately, as well as the aggregate

for upstream (exploration, development, and production) operations and downstream operations

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(refining and transportation/distribution). Also, for perspective, the oil and gas tax revenue losses

are compared with those for other industries and with the tax subsidies for energy efficiency and

alternative/renewable fuels.

Table 1. Energy Tax Provisions in the Energy Tax Act of 2005 (P.L. 109-58):

11-Year Estimated Revenue Loss, by Type of Incentive

Amount ($ millions)

Incentives For Fossil Fuels Supply

Percentage

(1) Oil & Gas Production:

a) amortize all G&G costs over 2 years

b) liberalize the definition of independent producer

(2) Oil & Gas Refining and Distribution:

a) gas pipelines treated as 15-year property

b) temporary expensing in refining of liquid fuels

c) exempt prepayment of natural gas from arbitrage

d) gas gathering lines treated as 7-year property

e) expensing for coop refinery of low-sulfur diesel

(3) Coal

-1,132

-974

-158

-1,501

-1,019

-406

-53

-16

-7

-2,948

7.8%

(4) Subtotal

-5,581

38.6%

(5) Nuclear

-1,571

10.9%

(6) Other

-1,549

10.7%

(7) Subtotal

-3,120

21.6%

10.4%

20.4%

Electricity Restructuring Provisions

Incentives For Efficiency, Renewables, And Alternative Fuels

(8) Energy Efficiency

(9) Renewable Energy & Alternative Fuels

(10) Subtotal

(11) Net Energy Tax Cuts

(12) Non Energy Tax Cutsa

(13) Total Energy and Non-Energy Tax Cuts

(14) Energy Tax Increasesb

(15) Other Tax Increases

(15) NET TAX CUTS

-1,260

8.7%

-4,500

-5,760

-14,461

-92

-14,553

+2,857

171

-11,525

31.1%

39.8%

100.0%

CRS compilation based on Joint Committee of Taxation estimates.

a. The act includes a provision to expand R&D for all energy activities. This provision is listed as a non energy

tax cut to simplify the table.

b. Energy tax increases comprise the oil spill liability tax and the Leaking Underground Storage Tank financing

rate, both of which are imposed on oil refineries. If these taxes are subtracted from the tax subsidies (row

2), the oil and gas refinery and distribution sector received a net tax increase of $1,356 ($2,857-$1,501).

Source:

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The JCT estimates that the 2005 act provides about $2.6 billion in tax cuts for the oil and gas

industry as a whole over 11 years, comprising about $1.1 billion for upstream operations and $1.5

billion for downstream, or refining and distribution, operations. For energy conservation and

efficiency, the 2005 act provides about $1.3 billion, including a deduction for energy-efficient

commercial property, fuel cells, and micro-turbines. Renewables incentives include a two-year

extension of the tax code § 45 credit, renewable energy bonds, and business credits for solar. The

total renewable tax subsidies in EPACT05 were about $4.5 billion.

Although the above oil and gas tax subsidies may not be justified based on economic theory, and

considering the high oil and gas prices over much of the policy period, they are not large when

measured relative to the industries’ gross product, which measures in the hundreds of billions of

dollars.20 Another misconception is that industry was the beneficiary of many and significant tax

breaks before these provisions were enacted. The industry did benefit historically from significant

tax subsidies; however, most of these had been either eliminated or pared back since the 1970s.

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Subtitle F of EPACT05 describes the four tax increases or revenue offsets. Two of the tax

increases—modification of the § 197 amortization, and an increase in the excise taxes on tires—

are negligible, raising taxes by just under an estimated $200 million over 11 years. However, the

other two are sizeable tax increases for the oil and gas industry: reinstatement of the Oil Spill

Liability Trust Fund and extension of the Leaking Underground Storage Tank (LUST) trust fund

rate, which would be expanded to all fuels.

The total oil and gas industry tax increases are roughly $2.8 billion over 11 years, for a net

increase in taxes on the industry of about $200 million, according to the JCT estimates. However,

because the oil spill liability tax and the Leaking Underground Storage Tank financing taxes are

excise taxes on oil and petroleum products, and are imposed on oil refineries, the net effect of the

2005 act on the oil and gas refinery sector was a tax increase of about $1.3 billion over 11 years.

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The Energy Policy Act of 2005 expanded some (but not all) of the preexisting tax subsidies for oil

and gas and introduced several new ones. Thus, some of the recent proposals to roll back tax

subsidies to oil and gas focus on the subsidies that were in effect before the 2005 act, and which

continue be in effect.

For the economic theory of taxation of exhaustible natural resources, see CRS Report RL30406, Energy Tax Policy:

An Economic Analysis, by (name redacted).

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A list of the preexisting federal tax subsidies (incentives) available for the U.S. oil and gas

industry—those in effect before EPACT05 and still in effect today—(and their corresponding

revenue loss estimates) appears in Table 2. The corresponding revenue losses, as estimated by the

JCT in its latest tax expenditures compendium, appear in the last column.21 Note that the table

defines tax subsidies or incentives targeted for the oil and gas industry as those that are due to

provisions in the tax law that apply only to this industry and not to others.

U.S. Congress, Joint Committee Print, Estimates of Federal Tax Expenditures for Fiscal Years 2006-2010, prepared

for the House Committee on Ways and Means and the Senate Committee on Finance by the Joint Committee on

Taxation Staff, Apr. 25, 2006.

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. Special Tax Incentives Targeted for the Oil and Gas Industry and Estimated Revenue Losses, FY2006

Table 2

Original Enacting

Federal Revenue Losses

Legislation/Regulation

FY2006 ($ millions)