Percentage vs. Cost Depletion: Which Method Is Best for Investors?

Most investors who explore oil and gas for the first time focus heavily on the first-year tax benefits. Intangible drilling costs, tangible equipment depreciation, the idea that a significant portion of their capital investment could generate a meaningful deduction in year one. That focus makes sense. Those benefits are real and they matter.

What often gets less attention is what happens after the drilling is done and the well starts producing. That is where depletion comes in. For investors in long-producing working-interest programs, the depletion allowance is the tax benefit that keeps working long after the drilling deductions are gone.

This guide explains both methods in plain English: what they are, how they are calculated, who qualifies, and how they fit into the broader tax picture of working-interest ownership. We also address the most common questions we hear from investors.

This is educational content, not tax or investment advice. Every investor's situation is different. Always work with a qualified CPA.

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What Are Oil Depletion Allowances?

Oil depletion allowances are annual tax deductions authorized under the U.S. tax code for investors and producers who hold an economic interest in a producing oil or gas property. The concept mirrors depreciation. A piece of equipment wears out over time and is depreciated. A natural resource reserve diminishes as it is extracted and is depleted.

The logic is straightforward. A producing oil or gas reservoir is a wasting asset. Every barrel lifted from the ground represents a permanent reduction in the value of that underground resource. The tax code recognizes this reality and allows investors to deduct a portion of production income annually to account for that gradual decline.

A few key points about how depletion allowances work:

• They reduce taxable income from the producing property each year
• They are not a one-time benefit. They continue for the productive life of the well
• They are available to working interest owners, royalty owners, and mineral rights owners
• For most working-interest investors, depletion becomes the primary ongoing tax benefit after first-year drilling deductions have been fully utilized

A well that produces steadily for fifteen or twenty years continues generating depletion deductions throughout that entire period. That long-running benefit is one of the most important and underappreciated features of direct oil and gas ownership.

The Two Methods: An Overview

The IRS allows two different methods for calculating your annual depletion deduction: cost depletion and percentage depletion.

Here is the most important rule to know upfront: you are required to calculate both methods every year and claim whichever produces the larger deduction. This is not a one-time election. It is an annual analysis your CPA performs using your current production records and ownership data.

• Cost depletion ties your deduction to how much of the reserve was physically extracted during the year
• Percentage depletion ties your deduction to the gross income generated by the property during the year

Each method has specific rules, advantages, and limitations. The method that produces the better result in year three may not be the better method in year twelve. Your filing should reflect the correct answer each year.

Cost Depletion Explained

How Cost Depletion Is Calculated

Cost depletion uses a unit-of-production approach. You divide your investment in the property (your adjusted cost basis) across the total estimated recoverable reserves. That gives you a depletion rate per unit. You then multiply that rate by the units actually produced and sold during the year.

A straightforward example:

• Your share of leasehold costs: $300,000
• Estimated total recoverable reserves: 300,000 barrels
• Depletion rate: $1.00 per barrel
• Year 1 production: 30,000 barrels, deduction = $30,000
• Year 2 production: 24,000 barrels, deduction = $24,000

The deduction tracks production directly. As the well declines naturally, the cost depletion deduction declines with it.

Key Characteristics of Cost Depletion

It is property-specific. Each well requires its own separate calculation. If you hold interests in multiple properties, each carries its own cost basis, reserve estimate, and depletion schedule.

It depends on accurate reserve estimates. Petroleum engineers periodically update recoverable reserve figures based on production history and reservoir data. Changes in those estimates affect your depletion rate going forward.

It stops when your basis is fully recovered. Once cumulative cost depletion deductions have returned your entire adjusted investment in the property, cost depletion ends. If the well keeps producing after your basis reaches zero, cost depletion provides no further benefit.

When Cost Depletion Works Best

Cost depletion tends to produce the larger deduction in the earlier, higher-production years of a well's life. When output is strong and a meaningful fraction of reserves is being extracted each year, the proportional deduction can be significant. As the well matures and production naturally declines, the other method often becomes more advantageous.

Percentage Depletion Explained

How Percentage Depletion Is Calculated

Percentage depletion calculates your deduction as a fixed percentage of gross income generated by the property during the year. For oil and gas, that statutory rate is 15 percent under Section 613A of the Internal Revenue Code.

Using the same property:

• Gross production revenue in Year 5: $80,000
• Percentage depletion deduction: $12,000 (15% of $80,000)
• Gross production revenue in Year 6: $100,000 (stronger prices)
• Percentage depletion deduction: $15,000 (15% of $100,000)

The deduction scales with revenue. In stronger commodity price environments, percentage depletion produces a larger benefit.

The Key Advantage: No Basis Limit

This is what makes percentage depletion particularly powerful for long-producing wells. Unlike cost depletion, percentage depletion is not capped by your adjusted cost basis. It can continue generating deductions even after your original investment has been fully recovered.

For a well that produces steadily for twenty or twenty-five years, this distinction is significant. Cost depletion stops when your basis reaches zero. Percentage depletion keeps working, year after year, as long as the property is generating income and you remain eligible. Over the productive life of a strong well, the cumulative value of that ongoing deduction can be substantial.

Eligibility and Limitations

Percentage depletion under Section 613A is available to independent producers and royalty owners. Major integrated oil companies are generally excluded and must rely on cost depletion only. Most individual investors participating in direct working-interest programs qualify as independent producers, but confirm eligibility with your CPA.

There are two primary limitations:

1. Property income cap. Percentage depletion cannot exceed 100 percent of your taxable income from the property in any given year. In years with high operating costs or low commodity prices, this cap can reduce the benefit. In a year where the property shows a net loss, percentage depletion may be reduced to zero for that property for that year.
2. Production volume thresholds. Independent producers generally must be producing under 1,000 barrels of oil per day or 6 million cubic feet of natural gas per day to qualify for percentage depletion on those volumes. For most investors in conventional working-interest programs, this threshold is not a practical concern.

Cost Depletion vs. Percentage Depletion: Side-by-Side

The practical pattern for most working-interest investors: cost depletion may dominate in the early years, and percentage depletion becomes the primary method as the well matures and the 15 percent revenue-based calculation outpaces the unit-of-production result. Your CPA runs both calculations annually and files accordingly.

Depletion and the Full Oil and Gas Tax Stack

Depletion does not operate in isolation. It is one layer in a multi-phase tax structure unique to oil and gas working-interest ownership. Understanding how the layers work together gives you a more accurate picture of long-term investment economics.

Here is how the full tax stack typically unfolds:

Year 1: Intangible Drilling Costs (IDCs) Working interest owners who bear drilling costs can elect to expense IDCs under Section 263(c) in the year the well is drilled. IDCs cover labor, drilling mud, fuel, site prep, and field services. These costs typically represent 60 to 80 percent of total well costs and can often be deducted in full in year one, generating a substantial upfront deduction.

Years 1 through 5: Tangible Equipment Depreciation Casing, tubing, tanks, pumps, and wellhead equipment are capitalized and depreciated over time using accelerated schedules. Under current law, with 100 percent bonus depreciation in effect for qualifying assets placed in service from 2025 onward, much of this can also be recovered in year one.

Every year: Lease Operating Expenses (LOE) Ongoing costs to operate the well, including maintenance, labor, water disposal, and production taxes, are deductible as ordinary business expenses in the year incurred. These reduce taxable production income each year the well operates.

Every year for the life of the well: Depletion Once the well is producing, depletion reduces taxable production income annually for the entire productive life of the property. This is the benefit that continues running long after the drilling deductions are exhausted.

For investors who focus primarily on the first-year IDC benefit when evaluating a program, it is worth pausing to appreciate what happens in years five, ten, and fifteen. Depletion is the mechanism that sustains meaningful tax efficiency throughout the full production cycle, not just in the year you write the check.

Why Accurate Recordkeeping and Reporting Matter

Depletion deductions are only as defensible as the documentation behind them. Both methods require property-level records, and your CPA needs accurate, complete data to calculate both and file correctly.

For cost depletion, you need:

• Your adjusted cost basis in the property
• Estimated total recoverable reserves (updated periodically by a petroleum engineer)
• Actual production volumes attributed to your interest during the year

For percentage depletion, you need:

• Gross income from the property, calculated separately at the property level

At BassEXP, we provide investors with monthly owner statements that clearly report production volumes, gross revenue, and operating expenses attributed to their interest. These statements give your CPA the core data needed to run both calculations and document the elected method properly each year.

We also maintain field production logs, well performance histories, and geological documentation that support reserve estimates over time. Clean, well-organized records are not just a compliance requirement. They are a demonstration of how we operate.

If you receive a monthly owner statement from us and you are not sharing it with your CPA at year-end, you may be leaving deductions on the table.

Common Misconceptions About Oil Depletion Allowances

A few misunderstandings come up often in investor conversations. We want to address them directly.

"Depletion is a loophole." It is not. Depletion is a provision that has existed in the U.S. tax code for over a century, established specifically to recognize that producing a natural resource is a capital consumption event. The reserve is being removed from the ground and converted into income. Depletion reflects that economic reality.

"Depletion is a tax credit." It is a deduction against taxable income from the property, not a credit. A $15,000 depletion deduction reduces your taxable income by $15,000. The actual tax savings depend on your marginal rate.

"Percentage depletion is available to everyone." It is not. Major integrated oil companies cannot use it. Production volume thresholds apply. Eligibility should be confirmed with your CPA based on your specific ownership structure.

"I can elect one method permanently." You cannot. Both methods must be calculated each year, and you are required to claim the larger allowable deduction. This is a legal requirement, not a preference. The better method often changes as the well matures.

"Depletion will eliminate my tax liability entirely." Income-based limitations apply. In years where property taxable income is low or negative, percentage depletion may be reduced or eliminated on that property for that year. Planning around these scenarios is part of good tax strategy.

Depletion FAQs for Quick Clarity

Can percentage depletion exceed my basis? Yes. Percentage depletion can continue after your basis is fully recovered, subject to the production volume thresholds, the property income cap, and the overall taxable income limitation. Once cost depletion stops because your basis reaches zero, percentage depletion can keep generating deductions as long as the well is producing income and you remain eligible.

Who can use percentage depletion? Independent producers and royalty owners generally qualify under Section 613A. Major integrated oil companies cannot use percentage depletion for oil and gas properties and are limited to cost depletion only. Confirm eligibility with a qualified CPA.

What happens if the property shows a net loss? The property net-income limit can reduce percentage depletion to zero for that property in that year. Cost depletion may still apply if adjusted basis remains. A year with high operating costs or low commodity prices may limit the depletion benefit, but it does not permanently affect future years.

How does depletion interact with IDCs and tangible depreciation? IDCs and equipment depreciation reduce your taxable income on their own timelines. IDCs typically accelerate deductions into year one. Tangible depreciation spreads across several years. Depletion then applies annually to production income for the life of the well, continuing well beyond the point where drilling deductions have been fully utilized. All three should be claimed where eligible, and property-level records are essential to support each deduction correctly.

Does depletion apply to royalty owners as well? Yes. Because royalty owners generally do not bear drilling and development costs, they typically do not have a leasehold cost basis to deplete. As a result, percentage depletion at 15 percent of gross royalty income is generally the primary method available to them. Working interest owners may use either method and must calculate both annually.

How long does the depletion deduction continue? Cost depletion continues until your adjusted cost basis is fully recovered. Percentage depletion continues as long as the property is generating income and you remain eligible under Section 613A, regardless of whether your basis has been fully recovered. For a well producing for twenty or twenty-five years, percentage depletion can generate annual deductions throughout that entire productive period.

Do I need to choose one method permanently? No. Each tax year, both methods must be calculated for each producing property, and you are required to claim whichever produces the larger allowable deduction for that year. The better method can and does change as a well matures. Your CPA handles this annually using your current production records and remaining basis figures.

What This Means for BassEXP Investors

The wells we develop at BassEXP are conventional, multi-zone programs in proven Oklahoma fields. We target legacy formations with established production histories and overlooked stacked-pay potential. Our goal is to drill wells that produce steadily and responsibly over time.

That approach matters when it comes to depletion. A well that produces consistently for fifteen or twenty years is not just an income-generating asset. It is an asset where the depletion benefit compounds in value over that entire period. Year after year, a portion of the revenue that well generates is sheltered from taxation. For investors building long-term passive income alongside a disciplined tax strategy, that ongoing benefit is a meaningful part of the overall return picture.

Our commitment to operational transparency extends directly to the documentation investors need to capture these deductions properly. Every BassEXP investor receives:

• Monthly owner statements with production volumes, gross revenue, and itemized operating costs
• Annual documentation summaries organized for CPA review
• Clear cost breakdowns showing IDC and tangible classifications at the project level
• Direct access to Preston and the team for questions at any stage

We are not tax advisors. We are operators who believe in giving investors complete, accurate information so their tax professionals can do their jobs well. That is part of what it means to treat investors the way we would want to be treated ourselves.

If you are exploring oil and gas as part of a broader tax strategy, take the time to understand the full picture: first-year benefits, ongoing production deductions, and the role depletion plays over the life of the well. And if you want to talk through how our programs work, we are always willing to have that conversation directly.

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