Tax Breaks for Oil and Gas: Deductions, Credits, and Depletion

Tax breaks for oil and gas producers cluster around a few powerful provisions in the Internal Revenue Code: immediate deduction of intangible drilling costs, a percentage depletion allowance tied to gross revenue, a carve-out that lets working-interest losses offset ordinary income, and a set of credits and deductions aimed at tertiary recovery, marginal wells, and carbon sequestration. Most of the largest benefits are reserved for independent producers and royalty owners rather than integrated majors, and some are available to individual investors who hold working interests directly.

Intangible Drilling Costs Deduction

The most valuable break for most operators is the ability to immediately deduct intangible drilling costs, or IDCs, under Section 263(c). IDCs cover the expenses that leave nothing salvageable behind if a well comes up dry: labor, fuel, chemicals, drilling mud, survey work, and hauling equipment to the site. They typically account for 60 to 80 percent of total well cost. Tangible items like casing, wellhead equipment, and storage tanks are treated differently and must be depreciated over years.

The deduction lets an operator write off the full IDC amount in the year it’s spent, rather than spreading the cost over the well’s productive life.¹ Spend $1 million drilling a well with $700,000 of intangibles, and that $700,000 reduces taxable income in year one.

Integrated oil companies (firms that also refine and market) face a limit here. They can deduct only 70 percent of IDCs immediately and must amortize the remaining 30 percent over 60 months. Independent producers and individual investors have no such restriction and deduct 100 percent right away. That distinction changes the drilling economics for smaller operators in a material way.

Percentage Depletion Allowance

As a well produces, the resource underground shrinks. Percentage depletion lets qualifying taxpayers deduct 15 percent of the gross revenue from a producing property each year, regardless of what they originally paid for the mineral rights.² The unusual feature: the deduction can eventually exceed original cost basis. Once you’ve recovered your entire investment through depletion, you keep claiming 15 percent of gross revenue for as long as the well produces.

Large integrated oil companies cannot use percentage depletion at all. They must use cost depletion, which stops once the original investment is fully recovered. Only independent producers and royalty owners qualify, and even then production is capped: percentage depletion applies to the first 1,000 barrels of oil (or 6,000 thousand cubic feet of gas) per day of average daily production.³

Two further caps apply. The deduction from any single property cannot exceed 100 percent of that property’s net income for the year, so a property with no net income yields no percentage depletion.² And total percentage depletion across all properties cannot exceed 65 percent of the taxpayer’s overall taxable income for the year, with any disallowed amount carrying forward.³

Working Interest Exception to the Passive Loss Rules

Ordinarily, losses from activities in which you don’t materially participate can only offset passive income. Oil and gas working interests are carved out: a working interest is not treated as a passive activity, even if the taxpayer does no day-to-day work on the well.⁴ An investor holding a qualifying working interest can use drilling losses against salary, consulting income, or other active earnings.

Form matters. The taxpayer must bear personal liability for the project’s costs and obligations. Holding the interest through a limited partnership or another entity that shields the holder from liability disqualifies it; a general partnership or direct ownership works.⁴

There’s also a look-back rule. If you claim non-passive losses from a working interest in one year, later net income from that same property is treated as non-passive too. You can’t take losses against active income during the drilling phase and then reclassify production income as passive when the well starts paying.

Tertiary Injectants Deduction

When operators pump carbon dioxide, nitrogen, or certain polymers underground to push oil toward a production well, those materials are usually consumed. Section 193 allows a full, immediate deduction for the cost of tertiary injectants in the year they’re injected.⁵ Spend $50,000 on nitrogen for injection, and the full amount comes off taxable income right away rather than being capitalized.

Recoverable hydrocarbon injectants (natural gas or crude oil pumped in and later extracted) don’t qualify. Hydrocarbon-based or hydrocarbon-derivative substances can qualify if they contain no more than an insignificant amount of natural gas or crude oil, and the substance must be used as part of a recognized tertiary recovery method.⁵ If the same expenditure was already deducted as an IDC under Section 263(c) or under any other provision, Section 193 is not available.

Marginal Well Production Credit

Section 45I provides a per-unit credit for oil and gas from marginal wells: the low-volume wells that are often first to be shut in when prices fall. A well qualifies if its production is treated as “marginal production” under the stripper well rules (generally averaging 15 barrels of oil equivalent or less per day), or if it averages no more than 25 barrels of oil equivalent per day and produces at least 95 percent water.⁶

The base credit is $3 per barrel of qualified crude oil and $0.50 per thousand cubic feet of qualified natural gas, both adjusted annually for inflation.⁷ The credit phases out as reference prices rise. Because crude prices have stayed well above the inflation-adjusted threshold, the credit has been phased out for crude oil in recent years. For the 2025 tax year, the IRS confirmed it remains available for qualified natural gas production only.⁶

Enhanced Oil Recovery Credit

Section 43 provides a credit equal to 15 percent of qualified enhanced oil recovery costs for tertiary projects such as steam injection, gas flooding, or chemical injection.⁸ Qualified costs include injection equipment, construction, and certain IDCs tied to the tertiary project. The project must be located in the United States and follow a certified tertiary recovery plan.

In practice, this credit has been fully phased out for years. It reduces to zero when the reference price of oil exceeds a statutory inflation-adjusted threshold, and oil has traded well above that mark throughout recent years. The credit remains on the books and would reactivate if prices dropped significantly.

Carbon Oxide Sequestration Credit (45Q)

Section 45Q creates a per-ton credit for capturing and sequestering carbon oxide, and oil and gas operators can benefit when captured CO2 is used for enhanced oil recovery. For carbon capture equipment placed in service and used in qualified enhanced oil or gas recovery projects, the base credit for taxable years beginning in 2026 is $17 per metric ton of carbon oxide captured and injected.⁹ For direct air capture facilities, the base amount is $36 per metric ton.

These base amounts can increase substantially when the project meets prevailing wage and apprenticeship requirements established by the Inflation Reduction Act. Operators must have an EPA-approved monitoring, reporting, and verification plan and must track both injected and escaped CO2, with the IRS cross-referencing EPA data to verify claims. For operators running tertiary CO2 floods, 45Q can offset the cost of buying or capturing the carbon dioxide, stacking on top of the Section 193 deduction for the injectant itself.

How the Provisions Stack

The real leverage in oil and gas tax treatment comes from combining these provisions on a single project. An independent producer drilling a new well can immediately deduct 100 percent of IDCs, then claim percentage depletion at 15 percent of gross revenue once production begins, potentially for decades after the original investment is recovered. An investor holding a working interest directly can use first-year drilling losses to offset active income such as salary or business profits.

Later in a well’s life, if the operator moves to tertiary recovery, injectant costs are deductible under Section 193, the Section 43 credit may return if oil prices fall low enough, and captured CO2 used in the process can generate 45Q credits. A well that qualifies as marginal can also pick up the Section 45I credit on natural gas production. No single provision is extraordinary in isolation, but the stack is unlike anything available in other industries.

1
Office of the Law Revision Counsel. 26 U.S. Code 263 – Capital Expenditures – Section: Intangible Drilling and Development Costs
2
Office of the Law Revision Counsel. 26 U.S. Code 613 – Percentage Depletion
3
Office of the Law Revision Counsel. 26 USC 613A – Limitations on Percentage Depletion in Case of Oil and Gas Wells
4
Office of the Law Revision Counsel. 26 U.S. Code 469 – Passive Activity Losses and Credits Limited – Section: Working Interests in Oil and Gas Property
5
Office of the Law Revision Counsel. 26 U.S. Code 193 – Tertiary Injectants
6
Internal Revenue Service. Instructions for Form 8904 – Credit for Oil and Gas Production From Marginal Wells
7
Office of the Law Revision Counsel. 26 USC 45I – Credit for Producing Oil and Gas From Marginal Wells
8
Office of the Law Revision Counsel. 26 U.S. Code 43 – Enhanced Oil Recovery Credit
9
Office of the Law Revision Counsel. 26 USC 45Q – Credit for Carbon Oxide Sequestration