Drilling costs and depletion for oil and gas royalty owners

If you receive royalty checks from Permian Basin minerals, or you hold a working interest in a well, the tax code treats that income differently from almost anything else you earn. Two rules do most of the work: the election to expense intangible drilling costs, and the depletion deduction. Both are generous, and both are routinely under-claimed on returns prepared by software or by firms that don't see oil and gas income every week. Here's how they work in plain terms.

Intangible drilling costs: the election that front-loads deductions

Drilling a well costs money in two forms. Some of it buys things with salvage value: casing, pumping units, tanks, wellhead equipment. Those are depreciated like any other equipment. The rest buys things that have no salvage value once the hole is drilled: labor, fuel, hauling, site preparation, drilling mud, cementing, and the contractor's charges for the work itself. Those are intangible drilling and development costs (IDCs), and on most wells they're the majority of the bill.

Normally a cost that creates a long-lived asset has to be capitalized and recovered slowly. Internal Revenue Code §263(c) carves out an exception: an operator or working interest owner can elect to deduct IDCs in the year they're paid or incurred rather than capitalizing them. The election is made on the return for the first year you have IDCs, and once made it's binding for later years. Miss it, and you're stuck recovering those costs through depletion over the life of the well.

Two practical points:

• Royalty owners don't have IDCs. If you own minerals and lease them to an operator, the operator pays to drill. The IDC election matters to operators, to anyone who holds a working interest directly, and to investors in drilling partnerships that pass IDCs through on a K-1.
• A working interest held directly is an exception to the passive loss rules. The loss an IDC deduction creates can generally offset wages, business income, and investment income rather than being suspended as a passive loss, provided you hold the interest in a form that doesn't limit your liability. That exception is a large part of why drilling programs attract high-income investors, and also why they carry real financial risk.

For people exposed to the alternative minimum tax, IRC §59(e) offers a middle path: amortize the IDCs over 60 months instead of expensing them.

Depletion: two methods, and you take the larger one

Minerals in the ground are a wasting asset. Every barrel sold is a barrel you no longer own, and IRC §611 allows a deduction for that. The question is how to measure it, and the code gives two answers.

Cost depletion works like depreciation. You take your tax basis in the property (what you paid, or the stepped-up value if you inherited the minerals) and recover it in proportion to production: basis multiplied by the units sold this year, divided by the estimated recoverable units remaining. When the basis is fully recovered, cost depletion stops.

Percentage depletion ignores basis entirely. For oil and gas, IRC §613A(c) lets independent producers and royalty owners deduct 15 percent of gross income from the property, on production up to an average of 1,000 barrels of oil per day (or the gas equivalent, 6,000 cubic feet per barrel). Almost every individual mineral owner in the Basin is under that ceiling. Integrated companies (those that also refine or retail) are excluded, which is why the rule is sometimes called the independent producer exemption.

You don't choose between the two. IRC §613(a) says the depletion allowance is never less than it would be under cost depletion, so each year, property by property, you compute both and take the larger. In the first years after buying or inheriting minerals with a high basis, cost depletion often wins. Once that basis is used up, percentage depletion takes over, and it keeps going.

The two limits on percentage depletion

Percentage depletion is capped twice, and the caps bite in different situations.

The 100 percent property limit. Under §613(a), percentage depletion on an oil and gas property can't exceed 100 percent of the taxable income from that property, computed before depletion. For a royalty owner with little expense against the income, this rarely matters. For a working interest owner in a year heavy with operating costs or IDCs, it can reduce the deduction on that property to zero.

The 65 percent taxable income limit. Under §613A(d)(1), your total percentage depletion for the year can't exceed 65 percent of your overall taxable income, computed before depletion and a few other items. Whatever is disallowed carries forward to the next year rather than disappearing. This limit tends to appear in a year when a large IDC deduction or a business loss has already pushed your taxable income down.

One more exclusion worth knowing: lease bonuses and advance royalties don't qualify for percentage depletion. Under §613A(d)(5), the 15 percent applies to income from actual production, not to the signing bonus an operator pays to lease your acreage. Bonus income is ordinary income, subject only to cost depletion if you have basis to allocate to it.

When the depletion deduction exceeds your basis

This is the feature that surprises people, and it's the reason percentage depletion is valuable. Cost depletion is limited by what you paid: once your basis reaches zero, the deduction ends. Percentage depletion has no such limit. It's 15 percent of gross income every year the property produces, whether your remaining basis is $500,000 or nothing at all.

Consider minerals your grandparents leased in the 1950s that have passed down through the family. The basis may be a few hundred dollars or unknown entirely. Cost depletion is effectively zero. Percentage depletion still shelters 15 cents of every royalty dollar, year after year, for as long as the wells produce. Over a few decades of Permian production, that deduction can total many times whatever the minerals were originally worth.

The accounting rule behind this is that depletion reduces your basis in the property, but not below zero. Deductions beyond that point don't create a negative basis; they're simply allowed. Years ago the excess over basis was an alternative minimum tax preference item, but Congress removed that treatment for independent producers and royalty owners, and IRC §57(a)(1) now says the preference doesn't apply to depletion computed under §613A(c).

One consequence to plan for: because depletion reduces basis, a later sale of the minerals produces more gain than you might expect. That gain is generally capital gain rather than recaptured ordinary income, which is one of the angles we look at when a client is approached by a mineral buyer.

What this looks like on a Midland return

A simplified example. A royalty owner receives $120,000 of gross royalties in a year, reported on Form 1099-MISC. Severance tax and ad valorem taxes withheld by the operator total $9,000, and those are deductible as expenses on Schedule E alongside depletion. Percentage depletion is 15 percent of $120,000, or $18,000. If the minerals were inherited recently at a value of $900,000 and the wells are expected to produce for 25 more years, cost depletion might come out higher than $18,000 for several years. The return should reflect whichever is larger, property by property, and the basis should be tracked so the switch to percentage depletion happens when it should.

Two things we see go wrong regularly:

1. Depletion is skipped entirely because the preparer didn't realize royalties qualify, or because the 1099 was entered as "other income."
2. K-1 depletion is taken at the wrong level. For oil and gas partnerships, each partner computes their own depletion using information the partnership supplies. The number printed on the K-1 is often a starting point, not the deduction.

How we handle oil and gas income

For oil and gas operators and royalty owners, the work is as much record-keeping as tax law:

1. Establish basis for every property, including date-of-death values for inherited minerals, so cost depletion is available when it's the better answer.
2. Compute both methods each year and apply the property and taxable-income limits correctly, with carryforwards tracked.
3. Make the IDC election on time for working interest owners and drilling program investors, and model the 60-month alternative when AMT is in play.
4. Separate bonus from production income, since they're taxed differently.
5. Coordinate with the rest of the plan. A large IDC year, a mineral sale, or a lease bonus changes what else should happen that year, from retirement contributions to charitable giving, and that is where year-round tax planning pays for itself.

Royalty income is some of the best-treated income in the code. The deductions are only valuable, though, if someone actually claims them.

This article is general information, not tax advice for your situation. Talk with a CPA before making the IDC election, computing depletion, or selling a mineral interest.