Understanding Oil and Gas Royalties: A Complete Guide for Mineral Interest Owners

By Richard Partin, Managing Member, Texas State Royalties LLC Fort Worth, Texas | Published: September 23, 2026 | Last Updated: October 16, 2026

My family has been acquiring and operating mineral interests in Comanche and Eastland Counties for multiple generations. I studied biology and chemistry at UT Arlington and now facilitate acquisitions of producing mineral and royalty interests for qualified buyers across Texas through Texas State Royalties LLC. The most common royalty-related mistake I see from buyers is focusing on the stated royalty fraction in the lease without reviewing the post-production cost provisions — a 1/4 royalty lease with aggressive deductions can generate less net revenue than a 3/16 royalty lease with a wellhead valuation clause. Understanding how royalties actually flow from the wellhead to your bank account is the foundation of any responsible acquisition.

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Quick Answer: Oil and gas royalties are a contractual share of production revenue paid by the operator to the mineral interest owner — typically monthly — when a well is producing. The payment equals the mineral owner's decimal interest multiplied by the net production revenue after any permitted post-production cost deductions. The royalty fraction is set in the lease; the decimal interest is the royalty fraction multiplied by the owner's fractional share of the mineral estate. Texas also deducts severance tax — 4.6% on oil, 7.5% on gas — before the royalty reaches the mineral owner.

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Oil and gas royalties are payments made to mineral interest owners when an operator produces and sells oil or gas from their acreage. When a mineral interest is leased to an oil and gas operator, the lease specifies a royalty fraction — typically expressed as a decimal or fraction of gross production — that the operator must pay to the mineral owner for every unit of oil or gas produced and sold.

Royalties are not wages, dividends, or investment returns in the conventional sense. They are a contractual share of production revenue, paid by the operator to the mineral owner as compensation for the right to extract the minerals. The mineral owner does not operate the well, bear the cost of drilling, or manage the production process. What the mineral owner holds is the right to receive a fraction of the revenue when production generates income — and that right is what makes a mineral interest a productive asset.

For a foundational overview of mineral interests and how they are structured, see Understanding Mineral Interests: The Complete Guide for Buyers. For a breakdown of the different types of interests that generate royalty income, see Types of Mineral Interests: A Buyer's Reference.

How Are Oil and Gas Royalties Generated?

Royalties begin with a lease. When a mineral interest owner — the lessor — grants an oil and gas company — the lessee, or operator — the right to explore for and produce minerals from their acreage, that grant is made through an oil and gas lease governed by the Texas Natural Resources Code. The lease is a contract that specifies the terms under which the operator may drill and produce, including the royalty fraction the operator must pay to the mineral owner.

The sequence works like this:

1. The mineral interest owner leases their acreage. The owner executes an oil and gas lease with an operator. The lease specifies the royalty fraction, the primary term (typically 3–5 years), and the conditions under which the lease is held beyond the primary term.
2. The operator drills and completes a well. If the operator finds producible oil or gas, they complete the well and begin production. The operator bears all costs of drilling, completion, and production — the mineral owner contributes no capital.
3. The operator sells the production. The operator sells the oil or gas to a purchaser — a pipeline company, a refinery, or a midstream processor. The sale generates revenue.
4. The operator calculates and pays the royalty. The operator calculates the mineral owner's share of the revenue based on the royalty fraction in the lease and pays it — typically monthly — along with a royalty statement that details the calculation.
5. The mineral owner receives the royalty payment. The payment is deposited directly to the mineral owner. No action is required on the mineral owner's part to receive it — the obligation runs entirely with the operator.

Royalties are paid only when production generates revenue. If a well is shut in, if production ceases, or if commodity prices fall below the operator's cost threshold, royalty payments may be reduced or suspended. The mineral owner does not receive a payment simply for owning the interest — the payment is tied to actual production and sales.

How Is the Royalty Fraction Set and What Does It Mean for Buyers?

The royalty fraction is the single most important economic term in an oil and gas lease. It determines what percentage of gross production revenue flows to the mineral owner before the operator deducts its costs.

The historical standard in Texas was 1/8 (12.5%) — a fraction so common it became the default expectation in many markets. Over the past two decades, as competition for mineral acreage intensified in the Permian Basin, Eagle Ford, and other active plays, royalty fractions have risen substantially. Today, royalty fractions in active Texas plays commonly range from 3/16 (18.75%) to 1/4 (25%), with some leases in highly competitive areas reaching higher. The fraction negotiated depends on the productivity of the acreage, the competitive environment, and the mineral owner's negotiating position.

The royalty fraction determines the mineral owner's net revenue interest (NRI) — the fraction of production revenue the mineral owner actually receives. A mineral owner with a 1/4 royalty has a 25% NRI: for every dollar of gross production revenue, the mineral owner receives $0.25 before any post-production cost deductions.

For buyers evaluating an acquisition, the royalty fraction in the outstanding lease is a fixed term — you are acquiring the interest subject to the existing lease, not negotiating a new one. What matters is understanding what that fraction actually yields after deductions, which requires reviewing the lease terms and the historical royalty statements together.

How Are Royalty Payments Calculated?

The royalty payment for a given production period is calculated by multiplying the mineral owner's decimal interest by the net production revenue after any permitted post-production cost deductions.

Royalty Payment = (Production Volume × Commodity Price × Decimal Interest) − Post-Production Cost Deductions

Production volume is measured at the wellhead or at a designated measurement point and reported in barrels (BBL) for oil, thousand cubic feet (MCF) for natural gas, and barrels of oil equivalent (BOE) for combined production. The volume reported on the royalty statement is the volume attributed to the mineral owner's interest — not the total well production.

The decimal interest is the product of the mineral owner's royalty fraction and their fractional ownership of the mineral estate. A mineral owner with a 1/4 royalty on a 40-net-mineral-acre interest in a 640-acre unit has a decimal interest of:

0.25 × (40 ÷ 640) = 0.015625

Decimal interest errors are among the most common sources of royalty underpayment. In estate proceedings involving fractional mineral interests — particularly in Comanche and Eastland Counties where a single tract may have a dozen or more fractional owners — errors are common. A 1/4 royalty fraction on a 1/8 mineral ownership yields a decimal interest of 0.03125, not 0.25. Always verify the decimal interest on the royalty statement against your own calculation before signing a division order.

Commodity price is the price per unit applied to the calculation — typically the index price for the relevant basin (WTI for Permian oil, Henry Hub for gas) adjusted for any basis differential. Buyers should request actual price realizations from the seller's royalty statements rather than relying on index prices alone, as basis differentials and contract terms can produce significant variation.

Wolfcamp and other Permian Basin wells also produce natural gas liquids (NGLs) — ethane, propane, butane, and natural gasoline — which typically represent 15–25% of total well revenue. NGL volumes appear as a separate line item on the royalty statement and are priced independently of oil and dry gas. Buyers evaluating Permian Basin interests should account for NGL revenue in their income projections.

What Are Post-Production Deductions and How Much Do They Reduce Your Royalty?

After oil or gas is produced at the wellhead, it typically must be gathered, transported, processed, and treated before it can be sold. These activities — collectively called post-production operations — generate costs. Whether those costs can be deducted from the mineral owner's royalty is determined by the language of the lease.

Common post-production costs include gathering fees, transportation fees, processing fees (separating NGLs from the gas stream), compression fees, and treatment fees for removing impurities.

The critical lease language is whether the royalty is calculated at the wellhead (before post-production costs — most favorable to the mineral owner) or at the point of sale (after post-production costs — less favorable). Many leases use language that falls between these poles, and the interpretation has generated substantial litigation in Texas courts.

On Fort Worth Basin Barnett Shale leases from the early 2000s — many of which lack "free of cost" language — gathering and processing deductions of $0.35–$0.60/Mcf are common, reducing the effective royalty by 15–25% of gross value. A 1/4 royalty lease on Barnett gas with aggressive post-production deductions may generate less net revenue than a 3/16 royalty lease with a wellhead valuation clause on the same acreage. Buyers must review the actual lease terms and the historical royalty statements — not just the royalty fraction — to understand what the interest actually yields.

Texas also imposes severance tax on oil and gas production: 4.6% on oil and 7.5% on gas, per the Texas Comptroller of Public Accounts. Severance tax is deducted from gross production revenue before the royalty is calculated in most lease structures, reducing the effective royalty below the stated fraction.

How Do You Read a Royalty Statement?

The royalty statement (also called a revenue statement or check detail) is the document the operator sends with each royalty payment. It details the calculation of the payment and is the primary tool for verifying that the operator is paying correctly.

A typical royalty statement includes:

Field	What It Means
Property / Well name	The well or unit from which production is attributed
Production month	The month in which the production occurred (typically 30–60 days before payment)
Product	Oil, gas, or NGLs
Volume	The mineral owner's attributed production volume for the period
Price	The price per unit applied to the calculation
Gross value	Volume × Price
Deductions	Post-production cost deductions, if any
Net value	Gross value minus deductions
Decimal interest	The mineral owner's decimal interest in the well
Net payment	Net value × decimal interest

The decimal interest is the most important figure to verify. If the royalty statement shows a decimal interest different from your calculation, request a division order review from the operator before signing anything.

Before an operator begins paying royalties to a new mineral owner, the operator requires the owner to execute a division order — a document that confirms the owner's decimal interest and authorizes the operator to pay royalties at that decimal. The division order is not a lease amendment; it does not change the lease terms. After a mineral interest is acquired through deed conveyance, the buyer must execute a division order with the operator before royalty payments will be redirected. Operators will not redirect payments based on a recorded deed alone.

In my experience reviewing acquisition packages, seller summaries frequently reflect the best production months and omit low-production periods. Always request 12–24 months of actual royalty statements and cross-check the volumes against Texas Railroad Commission production records. Discrepancies between a seller's summary and RRC data consistently favor the seller.

What Factors Affect Royalty Income Over Time?

Royalty income from a mineral interest is not fixed. It varies with commodity prices, production decline, lease terms, operator activity, and pooling arrangements.

Commodity prices are the most volatile driver. A mineral interest generating $2,000/month at $75/BBL oil generates $1,333/month at $50/BBL — a 33% reduction with no change in production volume. Model royalty income at multiple price scenarios before committing to an acquisition price.

Production decline is inevitable. All oil and gas wells decline over time. Wolfcamp and Barnett wells typically decline 60–80% in the first year; mature Barnett wells decline 5–10% annually. Review the production history of every well attributable to the interest and understand the decline curve before projecting future royalty income. The Texas Railroad Commission maintains publicly available production records for every well in Texas.

Operator activity determines whether new wells are drilled on the acreage and how aggressively the existing wells are maintained. A mineral owner whose acreage is held by a single producing well may see significantly increased royalty income if the operator drills additional wells — or may see income decline if the operator reduces activity or enters financial distress.

Pooling and unitization affect the decimal interest. When operators pool multiple mineral interest owners' acreage into a single production unit to drill a horizontal well, the mineral owner's royalty is calculated on their proportionate share of the unit — not on the full production of the well. Pooling provisions in the lease govern whether and how the operator may pool the acreage.

How Are Oil and Gas Royalties Taxed?

Under IRS Publication 535, royalty income from mineral interests is ordinary income for federal tax purposes. However, royalty interest owners who qualify as independent producers or royalty owners may deduct percentage depletion at 15% of gross income from the property, subject to the limitation that the deduction cannot exceed 100% of net income from the property. This depletion deduction is one of the primary tax advantages of owning a royalty interest rather than a working interest.

Working interest owners are subject to cost depletion rather than percentage depletion in most circumstances, and they may deduct intangible drilling costs (IDCs) in the year incurred — but they also bear all operating costs and capital calls that royalty interest owners never face. Under SEC Regulation S-X, Rule 4-10, working interest owners must classify reserves as Proved Developed Producing (PDP), Proved Undeveloped (PUD), or Probable — a reserve reporting obligation that does not apply to royalty interest owners in the same way.

When a mineral interest that generates royalty income is sold, the gain from the sale may qualify for a 1031 like-kind exchange, allowing the seller to defer capital gains tax by reinvesting the proceeds into a replacement mineral interest. For a complete guide, see Understanding 1031 Exchanges for Mineral Interests.

The tax treatment of mineral interests is complex. Consult a licensed CPA with oil and gas experience before making any acquisition or disposition decision.

What Should Buyers Verify Before Acquiring a Royalty-Generating Interest?

Before closing on any mineral interest acquisition, buyers should verify six things:

Review the outstanding lease in full. Obtain and read the complete lease — not just the royalty fraction. Understand the post-production cost provisions, the depth clauses, the pooling provisions, and the held-by-production status. The lease terms govern what you will receive and for how long.

Request 12–24 months of royalty statements. These documents show the actual decimal interest being paid, the deductions being taken, the production volumes, and the price realizations. They are the most reliable indicator of what the interest has been generating — and they reveal whether the seller's summary matches the actual payment history.

Cross-check against RRC production records. Pull the RRC production records for every well attributable to the interest. Verify that the volumes on the royalty statements match the RRC data. Discrepancies that favor the seller are a red flag.

Verify the decimal interest. Confirm that the decimal interest shown on the royalty statements matches the interest you are acquiring. If there is a discrepancy, resolve it before closing.

Understand the operator. Research the operator's financial condition, drilling activity, and track record in the play. An operator in financial distress may reduce activity, delay royalty payments, or be acquired by a successor who changes the development plan.

Obtain a title opinion. Commission a title opinion from a licensed Texas oil and gas attorney confirming that the seller's ownership is clear, that the outstanding lease is valid, and that there are no competing claims or encumbrances.

For a complete acquisition checklist, see How to Evaluate a Mineral Interest Before You Buy.

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Key Takeaways

• Oil and gas royalties are a contractual share of production revenue paid by the operator to the mineral interest owner — typically monthly — when a well is producing. The mineral owner bears no drilling costs, no capital calls, and no operating obligations. Royalties are paid only when production generates revenue.

• The royalty payment equals the mineral owner's decimal interest multiplied by net production revenue after permitted post-production cost deductions. The decimal interest is the royalty fraction multiplied by the owner's fractional share of the mineral estate. A 1/4 royalty on a 40-net-mineral-acre interest in a 640-acre unit yields a decimal interest of 0.015625.

• On Fort Worth Basin Barnett Shale leases from the early 2000s lacking "free of cost" language, post-production deductions of $0.35–$0.60/Mcf are common, reducing the effective royalty by 15–25% of gross value. A 1/4 royalty lease with aggressive deductions can generate less net revenue than a 3/16 royalty lease with a wellhead valuation clause. Review the lease terms — not just the royalty fraction.

• Texas imposes severance tax on production — 4.6% on oil and 7.5% on gas per the Texas Comptroller — which is deducted from gross production revenue before the royalty is calculated in most lease structures. Wolfcamp and other Permian Basin wells also produce NGLs that typically represent 15–25% of total well revenue and appear as a separate line item on the royalty statement.

• Seller royalty summaries frequently omit low-production months. Always request 12–24 months of actual royalty statements and cross-check volumes against Texas Railroad Commission production records. Discrepancies between a seller's summary and RRC data consistently favor the seller.

• Royalty income from mineral interests is eligible for percentage depletion at 15% under IRS Publication 535, subject to the 100%-of-net-income limitation. This depletion deduction is one of the primary tax advantages of owning a royalty interest rather than a working interest, which is subject to cost depletion and bears all operating costs.

• Decimal interest errors are among the most common sources of royalty underpayment, particularly in estate proceedings involving fractional mineral interests. Always verify the decimal interest on the royalty statement against your own calculation — royalty fraction × ownership fraction — before signing a division order.

• Reserve classifications follow SEC Regulation S-X Rule 4-10; under Texas Property Code § 1.002, mineral interests are real property; under Texas Estates Code, interests held individually pass through probate at death — unestablished heirship is the most common title defect in Comanche and Eastland County acquisitions

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Frequently Asked Questions

What is the difference between a royalty fraction and a decimal interest? The royalty fraction is the percentage of gross production revenue specified in the oil and gas lease — for example, 1/4 (25%). The decimal interest is the actual fraction of production revenue the mineral owner receives, calculated by multiplying the royalty fraction by the owner's fractional share of the mineral estate. A mineral owner with a 1/4 royalty who owns 40 net mineral acres in a 640-acre unit has a decimal interest of 0.25 × (40 ÷ 640) = 0.015625. The royalty fraction is set in the lease; the decimal interest depends on both the lease and the ownership fraction.

How do post-production deductions reduce my royalty payment? Post-production deductions are costs incurred after the oil or gas leaves the wellhead — gathering, transportation, processing, compression, and treatment fees. Whether these costs can be deducted from your royalty depends on the language of your lease. Leases that calculate the royalty "at the wellhead" generally prohibit post-production deductions; leases that calculate the royalty "at the point of sale" or "on proceeds received" generally permit them. On Fort Worth Basin Barnett Shale leases from the early 2000s lacking "free of cost" language, deductions of $0.35–$0.60/Mcf are common, reducing the effective royalty by 15–25% of gross value. Always review the lease terms and the historical royalty statements to understand what deductions are currently being taken.

How is royalty income taxed under federal law? Royalty income from mineral interests is ordinary income for federal tax purposes. However, royalty interest owners who qualify as independent producers or royalty owners may deduct percentage depletion at 15% of gross income from the property under IRS Publication 535, subject to the limitation that the deduction cannot exceed 100% of net income from the property. Texas also imposes severance tax on production — 4.6% on oil and 7.5% on gas — which is deducted before the royalty payment reaches the mineral owner. The tax treatment of mineral interests is complex; consult a licensed CPA with oil and gas experience before acquiring.

What is a division order and do I have to sign it? A division order is a document the operator sends to each royalty owner after a change in ownership. It specifies your decimal interest in the well and authorizes the operator to pay royalties to you at that decimal. Operators will not redirect royalty payments based on a recorded deed alone — the division order is required before payments begin. Before signing, verify that the decimal interest matches your calculation: royalty fraction × your ownership fraction in the mineral estate. If the decimal interest is incorrect, request a correction before signing. For a detailed explanation, see What Is a Division Order and Why Does It Matter?.

Why do royalty payments vary from month to month? Royalty payments vary because they are tied to actual production volume and commodity price — both of which change every month. Production declines over time as reservoir pressure decreases. Commodity prices fluctuate with market conditions. Post-production deductions may vary with throughput volumes and contract terms. Operators also typically pay royalties 30–60 days after the production month, so a payment received in October reflects September production at September prices. Buyers should review 12–24 months of royalty statements to understand the range of variation before projecting future income.

How does Texas State Royalties help buyers evaluate royalty-generating interests? Texas State Royalties facilitates acquisitions of producing mineral and royalty interests for qualified buyers across Texas. We review the outstanding lease terms, request and analyze historical royalty statements, cross-check production volumes against RRC data, and walk buyers through the decimal interest verification and division order process. We work exclusively with buyers, not sellers. Learn more about how we work with buyers or review our acquisition and facilitation services.

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Start Your Buyer Search

Texas State Royalties sources and facilitates acquisitions of producing mineral and royalty interests across Texas for qualified buyers. Learn more about how we work with buyers or review our acquisition and facilitation services.

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This article is for educational purposes only and is not legal, tax, or investment advice. The legal and tax characteristics of mineral interest royalties vary by state and by the specific terms of each lease. Consult a qualified Texas oil and gas attorney and a licensed CPA before making any acquisition decision.

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About the Author

Richard Partin is the founder of Texas State Royalties, a Fort Worth-based, buyer-first firm that sources producing oil and gas mineral interests through established industry relationships. His website biography describes years of hands-on experience in oil and gas, including acreage interests, working interests, and capital formation across active producing regions nationwide.

TSR works with buyers to understand their criteria, source and screen opportunities, and review available information about location, production and revenue history, operator, and ownership documentation. Buyers review the details and decide whether to proceed. When a transaction moves forward, the mineral interest is conveyed by deed.

Texas State Royalties works with buyers and facilitates direct mineral-interest deed conveyances. TSR is not a neutral advisor, and its materials reflect its role in helping buyers source and review opportunities. Information is for educational purposes only and is not legal, tax, or investment advice. TSR does not determine whether a particular mineral interest qualifies as replacement property for a 1031 exchange. Buyers should consult their Qualified Intermediary and qualified tax, legal, and financial advisors before making a decision.