Yes, oil companies do get federal subsidies, and they come in several forms: tax deductions that shrink taxable income, tax credits that reduce or refund taxes owed, below-market royalty rates on oil and gas pulled from public lands and waters, direct grants, government-backed loans, and taxpayer-funded cleanup of wells the industry walked away from. Some of these provisions are more than a century old. Others were created or expanded in the last three years. The dollar value to any given company depends heavily on its size and structure, because several of the most generous tax breaks are reserved for smaller independent producers rather than the integrated majors.
Tax Deductions That Shrink Taxable Income
The oldest and most valuable federal support for oil and gas comes through the tax code, in the form of deductions that let producers write off costs faster or in greater amounts than ordinary tax rules would allow.
Intangible Drilling Costs
Producers can deduct intangible drilling costs in the year those expenses occur rather than spreading them across the life of the well. Intangible drilling costs cover everything that goes into getting a well operational but has no salvage value: wages for drilling crews, fuel, ground clearing, and similar expenses. These costs often make up the majority of a well’s price tag. Under normal tax rules, a business spending millions on a long-lived asset recovers the investment gradually through depreciation. Oil and gas producers get to write off most of it immediately.1Office of the Law Revision Counsel. 26 U.S. Code 263 – Capital Expenditures
Independent producers can deduct 100 percent of intangible drilling costs in year one. Integrated companies, meaning those that both produce and refine crude above certain thresholds, must reduce the deduction by 30 percent and amortize that portion over five years.2Office of the Law Revision Counsel. 26 U.S. Code 291 – Special Rules Relating to Corporate Preference Items Even so, the majors still get to expense 70 percent immediately, which beats standard depreciation schedules in most other industries.
Percentage Depletion
Percentage depletion lets qualifying producers deduct 15 percent of gross income from a producing well every year, regardless of what they originally invested. Standard cost depletion works like depreciation: you write down the value of a resource as you extract it. Percentage depletion severs that link. A highly productive well can generate deductions that far exceed the money the operator ever put into the ground.3Office of the Law Revision Counsel. 26 U.S. Code 613A – Limitations on Percentage Depletion in Case of Oil and Gas Wells
This one is not available to the largest majors. A taxpayer or related entity that operates refineries running more than 75,000 barrels per day on average is disqualified. So is a company selling oil, gas, or derived products through retail outlets if total retail receipts exceed $5 million for the year. Even qualifying independents face a cap: the 15 percent rate applies only to the first 1,000 barrels per day of domestic crude (or the gas equivalent), and the deduction on any single property cannot exceed 65 percent of taxable income from that property.3Office of the Law Revision Counsel. 26 U.S. Code 613A – Limitations on Percentage Depletion in Case of Oil and Gas Wells For mid-size independents, though, this remains one of the most valuable provisions in the federal tax code.
Tertiary Injectants
When a well’s natural pressure drops, operators inject substances like carbon dioxide or steam to push out more oil. The cost of those injectants, as long as they are not recoverable hydrocarbons, can be deducted immediately rather than capitalized.4Office of the Law Revision Counsel. 26 U.S. Code 193 – Tertiary Injectants It stacks on top of the other drilling deductions and helps aging fields stay profitable longer than they otherwise would.
Tax Credits That Reduce or Refund Taxes Owed
Credits are worth more per dollar than deductions because they cut tax liability directly. Two credits target the oil and gas sector specifically.
Section 45Q Carbon Capture Credit
The Inflation Reduction Act sharply expanded the credit for capturing carbon dioxide. For equipment placed in service after 2022, the credit reaches $85 per metric ton of CO2 permanently stored in geological formations and $60 per metric ton used in enhanced oil recovery or other industrial processes, provided the project meets prevailing wage and apprenticeship requirements. Projects that don’t meet those labor standards receive one-fifth of those rates.5Office of the Law Revision Counsel. 26 USC 45Q – Credit for Carbon Oxide Sequestration
The unusual feature of 45Q is direct pay. For the first five years after carbon capture equipment goes into service, any taxpayer, including for-profit oil companies, can elect to receive the credit as a cash payment from the IRS rather than using it to offset tax liability. Most other clean energy credits reserve direct pay for tax-exempt and government entities. After that initial five-year window, the credit continues for seven more years but only as an offset against taxes owed. Construction has to begin before January 1, 2033, to qualify. For a company adding carbon capture at a refinery or gas processing plant, the credit can cover a meaningful share of project costs.
Section 43 Enhanced Oil Recovery Credit
A separate credit covers 15 percent of qualified enhanced oil recovery costs, including expenses for steam injection, polymer flooding, and CO2 injection. It phases out when crude oil prices exceed an inflation-adjusted threshold. The base threshold was $28 per barrel in 1990 dollars, and the credit disappears entirely once the reference price exceeds that by $6.6Office of the Law Revision Counsel. 26 USC 43 – Enhanced Oil Recovery Credit Even after decades of inflation adjustments, oil prices have generally sat above that range, so the credit has effectively been zeroed out in recent years. It stays on the books as a backstop that would reactivate if prices dropped sharply.
Below-Market Royalties on Public Lands and Waters
Companies that pull oil and gas out of federal land or offshore areas owe royalties to the government as payment for accessing publicly owned minerals. When those royalty rates sit below what private landowners or state governments charge, the difference is a subsidy in everything but name.
For onshore federal leases, the historical minimum was 12.5 percent of production value, a figure set by the Mineral Leasing Act of 1920.7U.S. Department of the Interior. Report on the Federal Oil and Gas Leasing Program The Inflation Reduction Act of 2022 raised the minimum for new competitive onshore leases to 16.67 percent, closer to what many states and private landowners already collected.8Bureau of Land Management. Impacts of the Inflation Reduction Act of 2022 The IRA also raised the national minimum bid from $2 to $10 per acre.9Office of the Law Revision Counsel. 30 USC 226 – Leasing of Oil and Gas Parcels
Offshore rates moved twice in three years. The Outer Continental Shelf Lands Act sets a statutory floor of 12.5 percent, but actual rates had been higher for years, reaching 18.75 percent on many deepwater leases. The IRA codified a 16.67 percent minimum for new offshore leases. Then the One Big Beautiful Bill Act, signed in mid-2025, repealed the IRA’s offshore increase and returned the rate to the 12.5 percent statutory minimum. New offshore leases in 2026 are meaningfully cheaper for producers than they were in 2023 and 2024.
Royalty relief goes further. The government sometimes suspends royalty payments entirely until a well produces a specified volume, a practice most common in deepwater areas where extraction costs run high. Every dollar of royalty relief is a dollar that stays with the company instead of going to the Treasury.
Direct Grants and Government-Backed Loans
Outside the tax code, federal agencies write checks and back private lending for energy projects.
The Department of Energy’s Loan Programs Office administers Title XVII loan guarantees, which back private lending for energy projects that might not attract financing on their own. The program’s authority runs into the tens of billions of dollars and was recently expanded to include “Energy Dominance Financing Projects,” a category covering production, processing, refining, and transportation of energy resources.10eCFR. 10 CFR Part 609 – Loan Guarantees for Clean Energy Projects A guarantee is not a check, but it shifts default risk from private lenders to taxpayers. That lets the borrower secure lower interest rates and better terms than the market would otherwise offer. If the project fails, the government covers the lender’s losses.
Direct grants flow through the Department of Energy and other agencies for pipeline security, refinery modernization, and infrastructure hardening. These typically work as cost-sharing arrangements: the government covers part of the project budget, the company covers the rest.
Taxpayer-Funded Cleanup of Abandoned Wells
When operators walk away from wells without properly plugging them, cleanup falls to taxpayers. The Bipartisan Infrastructure Law set aside $4.7 billion to plug orphan wells across the country, with an initial $560 million distributed to 24 states in the first funding round.11U.S. Department of the Interior. Through President Biden’s Bipartisan Infrastructure Law, 24 States Set to Begin Plugging Over 10,000 Orphaned Wells The average taxpayer cost to plug a single well and reclaim the surface runs around $71,000.12Bureau of Land Management. Oil and Gas Bonding
This spending exists because bonding requirements were historically too low to cover actual cleanup costs, which effectively subsidized operators who left depleted wells behind. The Bureau of Land Management raised minimum bond amounts in 2024, but the $4.7 billion in cleanup funding is a retroactive subsidy that covers costs the industry should have borne itself.
Publicly Funded Research the Industry Commercializes
The Department of Energy funds research on enhanced oil recovery techniques, seismic imaging for locating new deposits, and carbon capture technology. Many of these programs carry environmental labels, but they hand concrete financial value to private companies by absorbing the cost and risk of technological development. When DOE-funded research improves exploration success rates or makes enhanced recovery cheaper, the companies that adopt those techniques capture the benefit without having paid for the underlying science.
Carbon capture is where the layering is most visible. The government funds the research, backstops the financing through loan guarantees, and then pays a per-ton credit on every ton of CO2 captured. Each layer of support has its own policy justification. Stacked together, they represent a level of financial assistance few other industries receive.
Who Actually Gets What
The size of the subsidy depends on the company. Percentage depletion is closed off to any producer with refineries running more than 75,000 barrels per day or more than $5 million in retail sales, which excludes the largest integrated majors. The 100 percent first-year deduction for intangible drilling costs is likewise reserved for independents; integrated companies get 70 percent immediately and amortize the rest. The 45Q credit, by contrast, is available to any qualifying operator, and its direct-pay window turns it into cash even for companies with little tax liability to offset. Royalty rates apply to whoever holds the lease, so the 2025 rollback of offshore rates benefits every offshore operator, large or small. When the industry’s biggest names appear in headlines about subsidies, the deductions and credits they actually claim are often a narrower list than the full menu, but the loan guarantees, royalty rates, and cleanup spending reach them alongside everyone else.