Fossil Fuel Tax Benefits

Fossil Fuel Tax Benefits

Fossil Fuel Tax Benefits

April 29, 2026 (IF13211)

In recent years, lawmakers have expressed interest in federal subsidies for the domestic fossil fuel industry. This In Focus provides high-level descriptions of fossil fuel income tax benefits and their costs, including tax benefits that discourage greenhouse gas (GHG) emissions and other fossil fuel tax benefits. More detailed descriptions of all relevant provisions are in CRS Report R46865, Energy Tax Provisions: Overview and Budgetary Cost.

Introduction

Tax benefits—credits, deductions, and other ways of lowering a company's or individual's tax bill—are the primary type of subsidy used by fossil fuel producers. A 2023 study from the Energy Information Administration found that tax benefits constituted 85% of all federal subsidies for fossil fuel interests from FY2016 to FY2022.

Estimates from the Joint Committee on Taxation (JCT) suggest that the largest fossil fuel tax benefits total about $19.1 billion over FY2025-FY2029, an average of $3.8 billion per year. Not included in that total are some provisions that are described as having de minimis costs (i.e., less than $250 million over five years) or that do not have JCT estimates. Each provision is described below with JCT estimates when available. Also, companies with fossil fuel operations at times invest in geothermal, offshore wind, and other energy sources that may qualify for renewable energy tax credits. Those credits are not discussed below.

Fossil Fuel Tax Benefits Designed to Reduce Pollution and GHG Emissions

Credit for carbon oxide sequestration—$9.2 billion over FY2025-FY2029
Taxpayers may claim the carbon oxide sequestration credit for captured carbon dioxide and monoxide amounts. For taxpayers meeting prevailing wage and apprenticeship (PWA) requirements, the credit amounts are $180 per metric ton that is captured using Direct Air Capture (DAC) technologies and $85 per ton captured using non-DAC technologies. Captured carbon oxides must be geologically sequestered or reused by the taxpayer. Credit amounts will be adjusted for inflation starting in 2027 and are reduced if the taxpayer receives financing from tax-exempt bonds or does not meet the PWA requirements. This credit may be used by fossil-fuel-powered electricity facilities, but it may also be claimed by owners of industrial facilities and DAC facilities. The cost of the credit is $9.2 billion over five years, an average of $1.8 billion per year, though some of the benefit accrues to owners of industrial facilities or DAC facilities rather than to fossil fuel companies.

Enhanced oil recovery (EOR) credit—de minimis costs
A tax credit equal to 15% of qualified domestic enhanced oil recovery (EOR) costs is available when oil prices are below a certain threshold ($28 per barrel in 1991 dollars) that rises with inflation each year. Injecting carbon dioxide into the ground, where it is to be geologically sequestered, counts as a qualifying domestic EOR cost.

Expensing of tertiary injectants—de minimis costs
Certain tertiary injectant costs, including the operating and recycling costs associated with below-ground carbon dioxide sequestration, may be deducted immediately (i.e., expensed) rather than over the useful life of the asset. Costs for recoverable hydrocarbon injectants are not included.

Amortization of air pollution control facilities—de minimis costs
Certain air pollution control facilities used in connection with coal-fired power plants are given five- or seven-year amortization periods, allowing quicker upfront deductions for the facilities than would be allowed under normal tax law. The amortizable basis of a qualifying facility may be reduced by 20% in certain circumstances.

Fossil Fuel Tax Benefits Not Based on Pollution or GHG Emissions

Percentage depletion for oil and gas companies—$3.4 billion over FY2025-FY2029
Certain independent oil and gas producers may claim percentage depletion rather than cost depletion. The former allowance is 15% of gross income from the property, not to exceed 100% of taxable income from the property and 65% of all taxable income. Oil and gas producers may claim percentage depletion on up to 1,000 barrels of average daily production, or an equivalent amount of natural gas.

Exceptions for publicly traded partnerships with qualified income derived from energy-related activities—$3.2 billion over FY2025-FY2029
Publicly traded partnerships are treated as corporations for tax purposes. An exception occurs if 90% or more of a partnership's gross income comes from certain sources, including the exploration, development, mining, refining, production, transportation, and marketing of fossil fuels or other energy sources. The total cost of this provision is $4.4 billion; CRS calculations remove $1.2 billion for other energy sources, leaving $3.2 billion for fossil fuels.

Expensing of exploration and development costs for oil and gas companies—$2.3 billion over FY2025-FY2029
The costs associated with identifying and preparing natural resources for extraction may be expensed.

Tax credit for metallurgical coal—$709 million over FY2025-FY2029
The Advanced Manufacturing Production Credit, as enacted by P.L. 117-169, subsidizes the domestic production of certain inverters, battery components, solar and wind energy components, and critical minerals. The FY2025 reconciliation law added "metallurgical coal which is suitable for use in the production of steel" to the list of qualifying critical minerals. Qualifying metallurgical coal can be imported or produced domestically and is eligible for a credit equal to 2.5% of production costs through 2029.

Amortization of geological and geophysical expenditures associated with oil and gas exploration—$300 million over FY2025-FY2029
Geological and geophysical (G&G) costs are associated with determining the location and potential size of a natural resource or mineral deposit. These costs would generally be viewed as intangible assets, which are typically amortized over 15 years. Most producers may amortize G&G expenditures over two years, and major integrated oil companies may amortize over seven years.

The total cost of the five provisions above is $9.9 billion, an average of $2.0 billion per year. Provisions with de minimis costs or no estimates by the JCT are described below.

Credit for producing oil and gas from marginal wells—de minimis costs
A tax credit is available for producing oil or gas from marginal wells when oil and gas prices are below certain thresholds. The credit for natural gas is unavailable most years, and the credit for crude oil has never been available, as oil prices have never fallen below the relevant threshold.

Seven-year MACRS for Alaska natural gas pipelines—de minimis costs
Since 2014, a Modified Accelerated Cost Recovery System (MACRS) period of seven years has been provided for certain large natural gas pipelines in Alaska. MACRS and other forms of accelerated depreciation allow businesses to deduct costs more quickly than they would under normal tax rules. (Natural gas pipelines, like other types of business property, became eligible for expensing starting in 2025.)

Fossil fuel capital gains tax treatment—estimate not provided by the JCT
Certain sales of coal under royalty contracts qualify for taxation as capital gains rather than as ordinary income.

Safe harbor from arbitrage rules for prepaid natural gas—estimate not provided by the JCT
This provision allows tax-exempt bonds to be used to finance prepaid natural gas contracts without applying otherwise applicable arbitrage rules.

Seven-year MACRS for natural gas gathering lines—estimate not provided by the JCT
Natural gas gathering lines have a seven-year MACRS period, which is shorter than their projected useful life.

Passive loss rules for working interests in oil and gas property—estimate not provided by the JCT
Deductions from passive trade or business activities, to the extent they exceed income from all such passive activities, generally may not be deducted against other income. Working interests in oil or gas property are exempt from these rules and may be deducted against other income.

Scale and Impact on Global Warming

Based on projections from the Congressional Budget Office (CBO) and the JCT, fossil fuel tax benefits (including those meant to lower emissions) will equal 0.07% of federal spending and 0.05% of revenues over FY2025-FY2029.

The Urban-Brookings Tax Policy Center (TPC) concludes that the effects of fossil fuel tax benefits on global warming are "likely minor," noting that "any increase in domestic production they induce mostly displaces imports rather than raising domestic fuel consumption." The TPC also cites a study from the National Academy of Sciences, which finds that such tax benefits likely reduce GHG emissions because they encourage displacement of coal by natural gas. (Coal has roughly twice the GHG emissions of natural gas.)

JCT Estimates vs. Other Estimates

The International Monetary Fund (IMF) has found that annual fossil fuel subsidies amount to $7.4 trillion worldwide and more than $1.1 trillion in the United States. The latter figure is three orders of magnitude greater than the total reported by the JCT. The discrepancy largely reflects the IMF's decision to include both explicit and implicit subsidies in its reported totals. Explicit subsidies are tax breaks or spending programs benefiting fossil fuel companies or users. Implicit subsidies represent forgone revenues from lawmakers' decision to not levy a carbon tax or other fee that would account for the social costs of pollution. For the United States, virtually all the subsidies are implicit: The IMF reports that in 2024, fossil fuels were given $1.1 trillion of implicit subsidies and $18.2 billion ($0.0182 trillion) of explicit subsidies across all levels of government (federal, state, and local). This lower amount of explicit subsidies is closer to the JCT's estimates.

During the Biden Administration, the Treasury Department produced higher estimates than the JCT for specific fossil fuel tax benefits. For example, the JCT estimates that percentage depletion for oil and gas companies reduces five-year revenues by $3.4 billion, whereas the Biden Treasury reported that it reduces revenues by $6.9 billion.

Two methodological differences explain much of the discrepancies between the two sets of estimates. First, the JCT estimates the costs of fossil fuel tax benefits under current law, whereas the Biden Treasury estimated the savings from repealing such benefits alongside other reforms. For example, the Biden Administration proposed raising the corporate tax rate from 21% to 28%, which would have made deductions from taxable income more costly. Second, the JCT assumes that if a given tax benefit is eliminated, taxpayers will claim the next-largest benefit available, whereas the Treasury assumes that taxpayers are prevented from claiming other benefits. The JCT and Treasury estimates also differ in more minor ways, such as their treatment of passive loss rules, inclusion of negative tax expenditures, baseline projections for economic growth, and methods of rounding low-cost provisions.