Oil and gas investment tax benefits: who gets what, and what could change

What an individual investor gets, and what a major does not

Policy pieces ask whether "the industry" is subsidized. Sponsor pages list three benefits of a drilling program and stop. Neither answers the question a CFO or business owner is asking: if I own this kind of interest, which provisions reach my return, and on what conditions? The code answers by owner type, not by industry. There are four seats at the table:

• An integrated oil company is defined in IRC §291(b)(4) by reference to the retailer and refiner tests in §613A(d): more than $5 million of retail sales or more than 75,000 barrels a day of refinery runs. The familiar names are all in this category.
• An independent producer is any producer that is not integrated, from a mid-sized public company to a two-person operator.
• An individual working-interest owner bears a share of drilling, completion and operating cost, directly or through a partnership. For tax purposes this owner is an independent producer in miniature.
• A royalty owner, including a mineral owner who leases to an operator, receives a share of production revenue and bears none of the cost.

Read the next table across any row and the pattern repeats: the provision applies in full to the individual and the independent, and is trimmed or switched off for the integrated company. The mechanics of the §263(c) election live in our guide to intangible drilling costs; the worked year-by-year numbers for a direct investor are in the oil and gas investment tax deductions map. This page is the who-gets-what layer above both.

Who gets what: the map by owner

"Full" means the provision applies as written. Anything else is a reduction or exclusion in the statute.

Two things follow. The largest companies are the ones the statute trims most, which is the opposite of the usual headline. And the individual working-interest owner and the independent producer share a column in almost every row, which is why the conditions attached to that column deserve more attention than the benefits.

Oil and gas industry tax breaks: the full list

Oil and gas industry tax breaks, in the budget sense, are tax expenditures: rules that let a producer recover costs faster than ordinary capitalization would allow, or recover more than cost. They are not cash payments, and they are worth nothing to a taxpayer without income to offset. The federal list is short:

• IDC expensing under §263(c) and Treas. Reg. §1.612-4, reduced to 70% for integrated companies by §291(b).
• Percentage depletion under §613A(c), available only to independent producers and royalty owners.
• 24-month amortization of geological and geophysical costs under §167(h); seven years for a major integrated oil company as defined in §167(h)(5).
• Two price-triggered credits: the enhanced oil recovery credit in §43 and the marginal well credit in §45I. Both phase out as prices rise. For 2025 the §43 credit was fully phased out (2024 reference price $74.48 against a $59.12 threshold) and the natural gas marginal well credit was $0.79 per Mcf (Notices 2025-32 and 2025-34, IRB 2025-27). The IRS publishes new figures each year.
• Partnership treatment for publicly traded partnerships whose income is at least 90% "qualifying income" under §7704(c)–(d), which is why most energy MLPs are pipelines. It is a structural benefit, not a deduction, and §469(k) applies the passive-loss rules to each publicly traded partnership separately, so an MLP's losses generally offset only its own later income.
• The working-interest exception to the passive-activity rules in §469(c)(3), covered below. It is the only item on this list that matters more to an individual than to a company.

Everything else a producer deducts, from lease operating expense to severance taxes to interest, is ordinary business expense available to any industry.

IDC expensing, and why integrated companies get 70%

Intangible drilling and development costs are the parts of a well with no salvage value: labor, fuel, drilling mud, site preparation, cementing and completion services. Ordinary capitalization rules would recover them over the life of the reserve. §263(c) instead preserves a long-standing regulatory option to deduct them when incurred; the election is made on the first return that includes the costs and binds future years.

For integrated oil companies, §291(b)(1) disallows 30% of the deduction, and §291(b)(2) lets that 30% be deducted ratably over 60 months instead. Independents and individuals deduct 100%. Any taxpayer can also choose a slower path: §59(e) permits an election to amortize any portion of IDCs over 60 months, and amounts so elected are not an AMT preference. Which costs qualify, how the election is made and a worked first-year example are in the IDC guide.

Percentage depletion for royalty owners and independents

Depletion is the deduction for using up a wasting asset. Every owner of an economic interest, including a royalty owner, gets cost depletion under §611 and §612, which recovers basis in proportion to units sold and stops when basis reaches zero. Percentage depletion is a fixed share of gross income that is not tied to basis, so it keeps running after basis is gone. The taxpayer takes the larger of the two each year, property by property.

The Tax Reduction Act of 1975 repealed percentage depletion for oil and gas generally in §613A(a) and restored it only for independent producers and royalty owners in §613A(c). The current rules:

For a royalty owner this is usually the whole story: no drilling costs, no IDC election, no equipment, just depletion on the royalty checks, with the 1,000-barrel and 65% limits applied at the owner's level. The ceiling is shared under §613A(c)(8) across a controlled group and among a spouse and minor children, so a family cannot multiply it by dividing ownership. For partnerships and S corporations, each partner or shareholder computes depletion. The marginal-well step-up is dormant: the 2024 reference price of $74.48 is far above the $20 trigger.

Offsetting W-2 income: the working-interest exception

This is the provision behind the question most individual investors ask. The 1986 passive-activity rules in IRC §469 stop a taxpayer from using losses from an activity in which they do not materially participate against wages, business income or portfolio income. Congress wrote one industry exception. Under §469(c)(3)(A), "passive activity" does not include "any working interest in any oil or gas property which the taxpayer holds directly or through an entity which does not limit the liability of the taxpayer with respect to such interest," and §469(c)(4) says this applies whether or not the taxpayer materially participates.

Three consequences follow, and the first is the one sponsor pages tend to leave out:

• The test is liability exposure, not effort. A direct owner or a general partner qualifies. A limited partner or an LLC member generally does not, because the entity limits liability. Some programs have investors hold general-partner interests during the drilling year and convert to limited interests afterward; the exposure carried during that period should be understood before signing.
• The exception runs both ways. Under §469(c)(3)(B), once a working interest has produced a non-passive loss, later net income from that property is non-passive too. It cannot be used to absorb passive losses from elsewhere.
• It does not cover royalties. Royalties not earned in a trade or business are portfolio income under §469(e)(1). A royalty owner rarely has a loss to shelter in any case.

A non-passive working-interest loss is ordinary, so it offsets ordinary income of any kind, including Roth conversion income. That pairing is the subject of our Roth conversion IDC offset analysis. IRS Publication 925 describes the same exception. The price of it is the exposure that earns it: an owner whose liability is not limited can be called on for cost overruns, environmental claims and plugging obligations.

Equipment: bonus depreciation and seven-year MACRS

The tangible share of a well, such as casing, tubing, wellheads, pumps, separators and tanks, is not expensed under §263(c). It is depreciated under §168. Rev. Proc. 87-56 places assets used in drilling wells and producing oil and gas in asset class 13.2, which carries a seven-year recovery period under MACRS. Separately, the 2025 tax act (Pub. L. 119-21, §70301) made 100% bonus depreciation under §168(k) permanent for qualified property acquired after January 19, 2025; the IRS issued interim guidance in Notice 2026-11. That is a general business rule, not an oil and gas provision, and it applies to the major and the individual alike. In drilling it often decides whether the first-year write-off covers most of a well's cost or only the intangible share. Whether particular equipment qualifies is a question for the operator's tax package. Equipment is recaptured on sale under §1245; §1254 (below) covers IDCs and depletion.

Minimum taxes: individual AMT and corporate CAMT

For individuals, §57(a)(2) treats excess IDCs, the amount expensed above 120-month straight-line recovery, as an AMT preference to the extent it exceeds 65% of net income from oil, gas and geothermal properties. Section 57(a)(2)(E) switches the preference off for taxpayers that are not integrated oil companies, but caps the benefit: the reduction in alternative minimum taxable income cannot exceed 40% of AMTI computed without it. Percentage depletion computed under §613A(c) is excluded from the depletion preference in §57(a)(1). In a year with a large IDC deduction and little production income, the AMT is often the binding constraint on an individual's first-year benefit.

For the largest corporations, the 15% corporate alternative minimum tax is measured on financial-statement income, where IDCs are capitalized rather than expensed. Pub. L. 119-21, §70523 amended §56A(c)(13) so that adjusted financial statement income is reduced by IDC deductions allowed under §263(c), including amounts under §59(e) or §291(b)(2), for tax years beginning after December 31, 2025. That is the one recent change that runs in the majors' favor, and it only reaches corporations large enough to be in the CAMT at all.

The limits that shrink all of it

For an individual, the value of these provisions depends less on the oil and gas rules than on the rest of the return:

• At-risk. §465 limits deductible losses to the amount actually at risk; nonrecourse financing generally does not count. A deduction cannot exceed the cash and recourse debt you have put in.
• Excess business loss. §461(l), made permanent by the 2025 act, caps the net business loss a noncorporate taxpayer can deduct against non-business income. For tax years beginning in 2026 the threshold is $256,000, or $512,000 on a joint return (Rev. Proc. 2025-32). The excess becomes a net operating loss carryforward. Note that Roth conversion income is not business income, so a large IDC loss against a large conversion runs into this cap.
• Recapture. On a sale of the property, §1254 recaptures as ordinary income the IDCs deducted under §263(c) and the depletion that reduced basis, up to the gain. The deduction is better understood as deferral plus a possible rate difference than as a permanent exclusion.
• Marginal rate. A deduction is worth your marginal rate, and less as it pushes income down through the brackets. The Roth conversion calculator shows what plain bracket management is worth across a retirement before any energy deduction is priced in; the wider set of tools is under strategies.
• State conformity. States do not all follow federal IDC expensing or bonus depreciation. Confirm the treatment in your state of residence and in the producing state.

The risks the deductions do not remove

History and repeal risk: 1926 to 2025

The shape of these provisions is a product of a century of trimming. The Revenue Act of 1926 set percentage depletion for oil and gas at 27.5% of gross income. The Tax Reform Act of 1969 cut it to 22% (the statutory notes to §613 record the change). The Tax Reduction Act of 1975 repealed it for all but independents and royalty owners and added the 1,000-barrel ceiling and 65% limit that still apply. The Tax Reform Act of 1986 created the passive-loss rules and, in the same bill, the working-interest exception, along with §291(b)'s 30% haircut for integrated companies and the AMT preference for excess IDCs. Each round left the individual and the independent with more than the major.

Repeal has been a recurring budget proposal. Treasury's General Explanations of the Fiscal Year 2025 Revenue Proposals included a section titled "Eliminate fossil fuel tax preferences" that, as in prior years, targeted IDC expensing, percentage depletion for oil and gas wells and the passive-loss exception for working interests, among others. None of those repeals was enacted. The 2025 act (Pub. L. 119-21) went the other way: it left the core provisions intact, made 100% bonus depreciation and the §461(l) cap permanent, added the CAMT adjustment for IDCs and expanded §7704(d) qualifying income to additional energy activities for tax years beginning after December 31, 2025. The administration did not publish a Green Book with its FY2027 budget, so as of this writing there is no current formal repeal proposal on the table.

The takeaway: the provisions are durable but politically exposed. A multi-year plan that relies on percentage depletion or the §469(c)(3) exception should be revisited whenever a major tax bill moves, and a plan that depends on one large first-year deduction should be stress-tested against the AMT and the excess business loss cap first, because those are current law, not proposals.

Primary sources: IRC §263(c) and Treas. Reg. §1.612-4; §291(b); §59(e); §611–613A; §167(h); §168 and Rev. Proc. 87-56; §43; §45I; §56A(c)(13); §57(a); §461(l); §465; §469(c)(3)–(4), (e)(1) and (k); §1254; §7704; Pub. L. 119-21 §§70301, 70523; Rev. Proc. 2025-32; IRS Notices 2025-32, 2025-34 and 2026-11; Treasury FY2025 Green Book. This page is educational and is not tax, legal or investment advice, and it is not an offer or solicitation of any investment. Oil and gas interests involve risk of loss of the entire amount invested. Consult your own CPA and counsel before acting.