How does cost depletion work?

What it is

Depletion is the mineral-property counterpart of depreciation. As oil or gas is produced and sold, the property loses value, and depletion lets you deduct part of your investment. Cost depletion ties the deduction to your actual adjusted basis and the share of estimated reserves sold during the year.

Depletion is claimed by the owner of an economic interest: someone who has invested in the mineral in place and looks to income from its extraction to recover that investment.

The amount you paid for a lease or mineral interest must be allocated between the mineral property and any equipment or other depreciable assets acquired with it. Only the part allocated to the mineral property is recovered through depletion.

What the law says

IRC §611(a) allows a reasonable allowance for depletion for mines, oil and gas wells, other natural deposits, and timber. IRC §612 provides that the basis for cost depletion is the adjusted basis under §1011. Treas. Reg. §1.611-2(a)(1) sets the method: determine the adjusted basis at the end of the year, divide it by the number of units remaining as of the taxable year to get the depletion unit, and multiply that unit by the number of units sold during the year.

Under IRC §613(a), the allowance is never less than percentage depletion where percentage depletion applies, so each year you compute both and use the larger. Under §1016(a)(2), basis is reduced by the depletion allowed, but not below zero.

Requirements and tests

To compute cost depletion correctly:

If you inherit a mineral interest, your depletable basis is generally its fair market value at the date of death, which makes a date-of-death appraisal or reserve valuation important.

• Identify the property and its depletable basis: leasehold acquisition costs, and capitalized IDCs if you did not elect to deduct them, but not equipment.
• Use units remaining as of the taxable year, which equals units remaining at year-end plus units sold during the year.
• Use units sold, not units produced, and use a reserve estimate supported by engineering or other reliable data.
• Revise the rate when a new reserve estimate is made; past deductions are not changed.
• Treat each separate property separately, unless an aggregation election applies.
• Stop once adjusted basis reaches zero; cost depletion can never exceed basis.

How it works

Each year, start with the adjusted basis, meaning original depletable basis less depletion allowed in earlier years, whether cost or percentage. Divide by the units remaining as of the year, multiply by units sold, and compare the result with percentage depletion, if available. The larger amount is the deduction and reduces basis.

If reserves are revised upward, the per-unit rate falls; if revised downward, it rises. Selling the property ends depletion, and any remaining basis is used to compute gain or loss.

For a property acquired partway through the year, only units sold after the acquisition count. If you own interests in several tracts, each separate property generally has its own basis, reserve estimate, and depletion computation.

Keep a running schedule by property showing original basis, depletion allowed each year, remaining basis, reserve estimates and their sources, and units sold. This schedule is the first thing an examiner will ask for, and it also determines gain or loss when you sell.

Risks and IRS scrutiny

The IRS Oil and Gas Handbook directs examiners to test depletable basis, the allocation of purchase price between the mineral interest and equipment, the reserve estimate, and whether percentage depletion limits were applied correctly. Overstated basis or unsupported reserve figures inflate the deduction and can lead to adjustments, interest, and accuracy-related penalties.

Examiners also compare reported units sold with operator statements and severance tax reports, so volumes on the depletion schedule should match third-party records.

Who it is not for

Cost depletion does not help once basis is fully recovered, or for anyone without an economic interest, such as a person paid a fee or a share of proceeds without an investment in the mineral in place. It is also not available for amounts paid for equipment, which are depreciated.

It also does not apply to lease bonuses and advance royalties in the same way as production income; those have their own rules, including possible recapture if no production occurs.

How ebotCPA helps

We rebuild your depletable basis, set up a schedule that tracks units, reserves, and prior depletion, and compare cost and percentage depletion each year.

Book a $497 Case Analysis to have Ebot Mbi, CPA, EA review your facts before you act.

Primary sources

1. 26 U.S.C. §611(a). Allowance of deduction for depletion.

   Allows a reasonable allowance for depletion of oil and gas wells and other natural deposits.

2. 26 U.S.C. §612. Basis for cost depletion.

   Uses the adjusted basis under §1011 as the basis for cost depletion.

3. Treas. Reg. §1.611-2(a)(1). Rules applicable to mines, oil and gas wells.

   “multiplying the depletion unit, so determined, by the number of units of mineral sold within the taxable year”

   Sets the cost depletion formula using units remaining as of the taxable year and units sold.

4. 26 U.S.C. §613(a). Percentage depletion floor.

   Provides that the allowance is not less than percentage depletion where it applies.

5. 26 U.S.C. §1016(a)(2). Basis reduced by depletion.

   Reduces basis for depletion by the amount allowed, but not less than the amount allowable.

6. IRM 4.41.1. Oil and Gas Handbook.

   The examiner handbook for oil and gas issues, including intangible drilling costs, depletable basis, reserves, and depletion for independent producers and royalty owners.

Frequently asked questions