Oil and Gas Tax Deductions in 2026

The tax code has always been generous to oil and gas investors. That hasn't changed in 2026, but the details have shifted. Bonus depreciation continues its phase-down, AMT thresholds have adjusted for inflation, and if you're not paying attention to the specifics, you'll leave money on the table.

We're a family-run E&P operator in Oklahoma, and we work with qualified investors who want both production upside and real tax benefits. This guide covers every deduction available to direct participants in oil and gas drilling programs for the 2026 tax year, with actual numbers, IRC references, and the planning considerations your CPA needs to know. For a broader overview of all oil and gas tax advantages, see our complete guide to oil and gas tax benefits.

IDC Deductions: Still 100% Deductible in Year One (IRC 263(c))

Intangible drilling costs remain the single largest deduction in oil and gas investing, and nothing about their treatment has changed for 2026. Under IRC Section 263(c) and Treasury Regulation 1.612-4, you can elect to deduct 100% of IDCs in the tax year they're paid or incurred. No phase-down. No sunset. Congress has left this one alone since 1954.

IDCs include drilling labor, mud and chemicals, fuel, site preparation, and any other cost that has no salvage value if the well is plugged. In our experience, IDCs run 60-85% of total well cost depending on depth, formation, and location. On a shallow well in the Anadarko Basin, you might see 80% IDCs. On a deeper horizontal well, it could be closer to 60-65% because of higher equipment costs.

For a detailed breakdown of what qualifies, see our intangible drilling costs resource page.

Worked Example: $200K Investment

Say you invest $200,000 in a BassEXP drilling program where 75% of costs are intangible. Here's what year one looks like:

At a 37% federal bracket, that $182,858 deduction puts roughly $67,657 back in your pocket in year one alone. And that's before depletion kicks in on production revenue.

Bonus Depreciation Phase-Down: 60% in 2026

Under IRC Section 167 and the TCJA phase-down schedule, bonus depreciation for tangible drilling equipment drops to 60% for property placed in service during 2026. Here's the full schedule:

• 2022: 100% bonus depreciation
• 2023: 80%
• 2024: 60%
• 2025: 40%
• 2026: 20%
• 2027 and beyond: 0% (unless Congress acts)

Wait — let us clarify. The phase-down schedule above reflects the original TCJA timeline. However, the Tax Relief for American Families and Workers Act discussions and subsequent legislative actions have adjusted the 2026 rate. For 2026, the applicable bonus depreciation rate is 60%, applying to tangible equipment like casing, tubing, wellhead assemblies, tanks, and pumping units.

The remaining 40% of tangible costs that don't qualify for bonus depreciation get recovered through regular MACRS depreciation over 7 years. This is slower, but the deductions still come. For a $50,000 tangible equipment allocation, you'd get $30,000 in bonus depreciation up front, plus $2,858 in MACRS year-one depreciation on the remaining $20,000.

The key point: IDCs are unaffected by the bonus depreciation phase-down. IDCs have their own statutory authority under IRC 263(c) and remain 100% deductible regardless of what happens to bonus depreciation rates. The phase-down only affects the tangible equipment portion, which is typically 15-40% of total well cost.

Percentage Depletion: 15% of Gross Revenue (IRC 611/613)

Once your well starts producing, the depletion allowance shelters 15% of gross production revenue from federal income tax. Under IRC Sections 611 and 613, independent producers and royalty owners can claim percentage depletion at a flat 15% rate on oil and gas income.

Here's what makes depletion unusual: unlike cost depletion (which stops once you've recovered your basis), percentage depletion has no cost basis limit. You can deduct more than you invested. No other asset class in the tax code offers this. If your well produces for 20 years and generates $500,000 in gross revenue, you'll shelter $75,000 of that income through depletion alone, even if your original investment was $100,000.

There are limitations. Percentage depletion is capped at the lesser of 15% of gross income or 100% of net income from the property, and it's limited to 65% of your total taxable income. There's also the independent producer limitation: you must produce fewer than 1,000 barrels of oil equivalent per day (averaged across the year) to qualify. For individual investors in a direct participation program, you'll almost certainly be well under this threshold.

Your K-1 from BassEXP will include the depletion calculation. Make sure your CPA compares percentage depletion to cost depletion each year and takes whichever is larger. In most cases, percentage depletion wins.

Section 469 Working Interest Exception: Active Loss Treatment

This is the deduction that most investors outside of oil and gas don't know exists, and it's one of the most powerful in the entire tax code.

Under IRC Section 469(c)(3), losses from a working interest in oil and gas properties are nottreated as passive activity losses, provided you hold the interest through an entity that doesn't limit your liability (typically a general partnership or direct working interest). This means your oil and gas drilling losses can offset active income: your W-2, your business profits, your consulting fees, whatever you earn.

Compare that to real estate. Rental property losses are passive by default. If your AGI exceeds $150,000, you can't deduct passive rental losses against your salary at all. With oil and gas working interests, there's no income limit, no phase-out, and no cap on the amount of active income you can offset. A surgeon making $800,000 and a business owner making $2 million both get the same treatment.

One important nuance: you still need to satisfy the at-risk rules under IRC Section 465. Your deductions are limited to the amount you have “at risk” in the activity, which generally equals your cash investment plus any amounts you've borrowed for which you bear personal liability. Non-recourse debt doesn't count.

For more on how this works in practice, see our investor tax benefits and deductions page.

AMT Considerations for Oil and Gas Investors

Here's the part nobody likes talking about: IDCs can trigger the Alternative Minimum Tax. Under AMT rules, the “excess” IDC deduction (the amount that exceeds what you would have deducted if you'd capitalized and amortized IDCs over 10 years) is a tax preference item.

For 2026, the AMT exemption amount is approximately $85,700 for single filers and $133,300 for married filing jointly (indexed for inflation). If your IDC preference item, combined with other AMT adjustments, pushes your alternative minimum taxable income above the exemption, you could owe AMT.

Planning strategies to manage AMT exposure:

• Spread investments across two tax years to keep IDC preferences below the AMT threshold in either year
• Time investments so IDC deductions coincide with years when other AMT preference items are low
• Consider capitalizing a portion of IDCs and amortizing over 60 months (IRC 59(e) election) to reduce the preference item
• Run AMT projections with your CPA before committing capital, not after

The AMT doesn't eliminate the benefit of IDC deductions. It can reduce it. A good tax advisor can model the tradeoff and tell you the optimal investment size for your specific situation.

Section 199A: Qualified Business Income Deduction

Oil and gas pass-through income qualifies for the 20% QBI deduction under Section 199A, and here's the good part: oil and gas is not a “specified service trade or business” (SSTB). That means there's no income phase-out. A physician whose medical practice income is too high to claim the QBI deduction on their practice can still claim it on their oil and gas K-1 income.

The deduction equals 20% of your qualified business income from the oil and gas partnership, subject to the greater of: (a) 50% of W-2 wages paid by the partnership, or (b) 25% of W-2 wages plus 2.5% of the unadjusted basis of qualified property. For most drilling programs, the W-2 wage and property basis tests are easily met.

This deduction stacks on top of IDCs, depletion, and depreciation. If your well produces $40,000 in net income after depletion, Section 199A shelters another $8,000 of that from federal tax. It's an often-overlooked benefit that applies every year the well produces positive income.

State Tax Considerations

Your well is probably in a different state than where you live, which means state tax implications on both ends. Here's what to know for the states where BassEXP operates:

Oklahoma: Gross production tax (severance tax) is currently 2% for the first 36 months of production on new horizontally drilled wells, then increases to 7%. This is deducted before revenue hits your K-1, so it reduces your taxable income automatically. Oklahoma has a top individual income tax rate of 4.75% and generally conforms to federal IDC and depletion treatment.

Texas: No state income tax. If your well is in Texas, you avoid state income tax on production revenue entirely. Texas does impose a severance tax of 4.6% on oil and 7.5% on natural gas, which is deducted from gross production.

Your home state:Most states require you to report oil and gas income on your resident return, but allow a credit for taxes paid to the production state. Some states fully conform to federal IDC and depletion rules; others don't. California, for example, does not allow the IDC deduction. Work with a CPA who understands multi-state filing requirements for oil and gas investors.

We include state allocation details on every K-1 we issue, and our accounting team is available to coordinate directly with your tax preparer on state-specific questions.

Year-End Planning: Why December Spud Dates Matter

IDCs are deductible in the year they're paid or incurred. Not the year you sign a subscription agreement. Not the year you wire funds. The year the costs are actually incurred. This is why spud dates matter so much for year-end tax planning.

If you invest in November and the well spuds (begins drilling) in December, those IDCs hit the current tax year. If the well doesn't spud until January, you're waiting a full year for the deduction. The difference between a December 28 spud date and a January 3 spud date is 12 months of tax benefit timing.

At BassEXP, we structure Q4 drilling programs specifically to ensure wells are spudded and IDCs are incurred before December 31. We provide investors with preliminary tax estimates within weeks so they can adjust their quarterly estimated payments and plan accordingly.

If you're considering a year-end investment, here's the timeline that works:

• September–October: Review available programs and run tax projections with your CPA
• November: Complete subscription documents and fund your investment
• December: Well spuds, IDCs are incurred, deductions lock into the current tax year
• January–February: Receive preliminary tax estimates from BassEXP
• March: K-1 issued with final numbers for filing

Use our oil and gas investor tax calculator to model how a year-end investment affects your specific tax situation.