Percentage vs. Cost Depletion in Oil & Gas

Why depletion matters now

Oil and gas wells lose value as reserves are produced. The tax code recognizes this loss through depletion—a deduction for the “using up” of the resource. For investors, choosing the right method can change after‑tax returns in a material way. Two options exist: cost depletion and percentage depletion. Which one should you use this year?

Let's explains both methods in plain English, shows who qualifies, and offers a simple example and checklist you can use with your CPA. The aim is practical clarity, not theory.

Where Depletion Fits in Oil & Gas Taxes (Today’s context)

Depletion sits beside two other major oil and gas tax tools:

• Intangible drilling costs (IDCs): often deductible in the first year.
• Tangible costs: deducted over time through depreciation.

Depletion is different. It follows the production. You deduct value as oil or gas is sold. Most owners compute both cost and percentage depletion each year and claim the larger amount allowed by law. That choice can shift from year to year as prices, volumes, and basis change.

A key factor is eligibility. Independent producers and royalty owners may use percentage depletion at a statutory rate of 15% of gross income from the property, subject to limits. Large integrated companies generally cannot use percentage depletion and rely on cost depletion instead.

Cost Depletion: Accurate, basis‑driven, and record‑heavy

What it is. Cost depletion recovers your basis—the amount you invested in the mineral property—over the life of the reserves. It works like a unit‑of‑production method.

How it’s calculated.
Cost depletion for the year =
(Units sold this year ÷ Total recoverable units) × Adjusted basis.

What it requires.

• A defendable reserve estimate (engineering support is best).
• A current basis schedule that reflects prior depletion taken.
• Production and sales data by property.

What it does well.

• Mirrors the actual decline of the resource.
• Keeps deductions tied to investment recovered.

Key constraint. You can never deduct more than total basis. Once basis reaches zero, cost depletion stops—even if the well keeps producing.

Percentage Depletion: Simple, powerful—and limited by law

What it is. Percentage depletion allows a fixed percentage of a property’s gross income as a deduction each year. For oil and natural gas, the statutory rate is 15% for eligible taxpayers.

Who qualifies.

• Independent producers and royalty owners generally qualify.
• Integrated oil companies (large refiners/retailers) generally do not.

Core limits to know.

1. Daily production cap: The allowance applies only up to the equivalent of 1,000 barrels of oil per day (or 6,000 mcf of gas) across a taxpayer’s average daily domestic production.
2. Property net‑income limit: The deduction cannot exceed 100% of the property’s taxable income (you cannot create or deepen a loss on that property with percentage depletion).
3. Overall income cap: Total percentage depletion for the year cannot exceed 65% of the taxpayer’s taxable income. Any excess may be carried forward.

Why investors like it. Percentage depletion continues even after basis is fully recovered. For long‑lived wells with steady output, this can create a durable, annual deduction.

Challenges and Trade‑offs you should expect

• Recordkeeping vs. simplicity. Cost depletion can be more precise but requires strong reserve and basis records. Percentage depletion is simpler to compute but bound by statutory limits.
• Price swings. Both methods depend on production revenues. Volatile prices can change which method wins in any year.
• Eligibility cliffs. Falling outside §613A eligibility (for example, due to integration thresholds) removes the percentage option.
• Net‑income constraint. A high‑cost year can limit percentage depletion to zero on that property, even if gross revenue is decent.
• Policy debate. Percentage depletion is often debated. Supporters say it sustains marginal wells and local jobs. Critics view it as a subsidy. Investors should plan, not assume, yet note the 15% rate has been stable for years.
• Pass‑through complexity. In partnerships, depletion is determined at the owner level. Two partners in the same well can have different allowable deductions.

Two Methods at a Glance (quick reference)

Cost depletion

• Basis‑driven; stops at zero basis.
• Tracks extraction in units; reflects the reservoir’s drawdown.
• Requires reserve engineering and meticulous schedules.

Percentage depletion

• 15% of gross income for eligible taxpayers, subject to limits.
• Can exceed basis over the life of the well.
• Disallowed for many integrated companies.

A Worked Example (side‑by‑side)

Assumptions

• Basis in the property: $100,000.
• Recoverable reserves: 100,000 barrels.
• Production this year: 5,000 barrels.
• Average realized price: $50 per barrel.
• Gross income from the property: $250,000.
• Property net income (after lease operating costs, etc.): $200,000.

Cost depletion

• Cost per barrel = $100,000 ÷ 100,000 = $1.00.
• Deduction = 5,000 × $1.00 = $5,000.
• Remaining basis going forward: $95,000.

Percentage depletion

• 15% × $250,000 = $37,500.
• Check property net‑income limit: $37,500 is below $200,000 → allowed.
• Check overall 65% cap at the taxpayer level: assume not a constraint.

Result
Percentage depletion ($37,500) beats cost depletion ($5,000) this year. An eligible independent producer or royalty owner would typically claim percentage depletion for this property. Next year may differ if volumes, prices, or basis change.

Eligibility Under §613A: Who can use percentage depletion

• Independent producers: May use 15% percentage depletion, subject to production, property, and income limits.
• Royalty owners: Generally eligible under the same limits.
• Integrated oil companies: Typically cannot use percentage depletion for oil and gas and must rely on cost depletion.

Production limit reminder. The 1,000‑barrel‑per‑day (or 6,000 mcf) cap is measured on average daily domestic production. If production exceeds the cap, only the qualifying portion receives the 15% allowance.

Carryover concept. Amounts disallowed by the 65% overall income cap may be carried forward, preserving some benefit for future profitable years.

Investor Profiles: Which method tends to help whom?

• High‑basis, lower‑output properties: Cost depletion may compare well, especially early on.
• Low‑basis, productive wells with steady revenue: Percentage depletion often wins.
• Long‑lived “stripper” wells: Percentage depletion can compound value over many years.
• Royalty portfolios: Percentage depletion can be a durable, annual deduction.
• Integrated operators: Expect to rely on cost depletion due to §613A restrictions.

No single rule fits every well. The best approach is to compute both each year and document the choice.

Practical Constraints and Common Pitfalls

• Property‑by‑property limits: Percentage depletion cannot exceed property net income. Grouping does not fix a loss on one lease.
• Basis errors: Missing AFE adjustments, acquisition costs, or prior year depletion can distort cost depletion.
• Reserve updates: Outdated engineering can misstate cost depletion; update when new data arrives.
• Partnership surprises: K‑1s often include “simulated depletion.” Each owner must compute their own allowable deduction based on individual limits.
• Production cap monitoring: Watch the 1,000‑barrel/6,000‑mcf thresholds if you add wells mid‑year.

Opportunities: Actions that improve after‑tax outcomes

1) Model both methods every year.
Refresh reserves, basis, and property economics. Document why one method is larger.

2) Track property‑level income monthly.
You will need net income by property to confirm the property limit for percentage depletion.

3) Coordinate with other oil & gas deductions.
Layer depletion with IDC expensing and equipment depreciation to shape timing of deductions.

4) Watch the 65% cap and carryovers.
Forecast taxable income early. If the cap bites, keep a record of disallowed amounts to carry forward.

5) Build evidence for cost depletion.
Maintain engineering reports, production histories, and AFE/basis files to defend calculations.

6) Plan for ownership changes.
Partial sales or reassignments affect basis and who gets the deduction. Update schedules promptly.

7) Align structure with goals.
Royalty owners and eligible independents often prefer percentage depletion. Integrated operations will plan around cost depletion.

Documentation and CPA Checklist (use at year‑end)

• Property list and interest type (working, royalty, overrides).
• Current basis roll‑forward with all additions and prior depletion.
• Engineering support for reserves and any revisions during the year.
• Monthly production and pricing by property; revenue tie‑out to statements.
• Lease operating statements to compute property net income.
• K‑1 support for pass‑through interests, including any simulated depletion.
• Eligibility memo (independent vs. integrated status; production cap test).
• Carryover tracker for any 65% cap disallowances.

Bring this packet to your CPA. It saves time and reduces the risk of missed deductions.

Bass EXP’s Approach: How we support depletion reporting

• Property‑level reporting. We present monthly volumes, pricing, and costs by property to simplify the property net‑income test.
• Clear ownership math. We show working interest, burdens, and net revenue interest (NRI) so investors see how gross becomes net.
• Basis transparency. Our AFE and capital accounting support basis tracking for cost depletion.
• Year‑end packages. Investors receive organized support for percentage depletion and cost depletion calculations plus any carryover notes.
• Education built‑in. We help investors and their advisors walk through “compute‑both” scenarios so the larger allowable deduction is captured.

Outlook: What to watch next

Policy discussions around depletion surface from time to time. Some argue percentage depletion supports small producers and marginal wells. Others question whether the benefit should be narrowed. While the 15% rate and §613A limits have been consistent for years, investors should stay alert to legislative updates. The practical takeaway is simple: plan annually, document well, and remain flexible.

A simple rule—compute both and choose well

Cost depletion mirrors investment recovery. Percentage depletion rewards productive, long‑lived properties and eligible owners. Each method has constraints. The right choice is the one that delivers the larger allowable deduction this year, supported by clean records.

If you’re evaluating direct projects in Oklahoma or building a royalty portfolio, Bass EXP can help you organize the data, apply the rules, and coordinate with your CPA. Want a one‑page summary to take to your next tax meeting? Ask us for the Depletion Explainer and we’ll share the checklist and example used in this article.

Disclosure: This material is educational. It is not tax, legal, or investment advice. Speak with a qualified advisor about your specific situation.

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