What Is a Royalty Interest in Oil and Gas?

By Richard Partin, Managing Member, Texas State Royalties LLC Fort Worth, Texas | Published: October 15, 2026 | Last Updated: October 16, 2026

Richard Partin comes from a multi-generational oil and gas operating family in Comanche and Eastland Counties, Texas. He holds a biology and chemistry background from UT Arlington and facilitates acquisitions of producing mineral and royalty interests for qualified buyers across Texas through Texas State Royalties LLC.

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Quick Answer: A royalty interest is the right to receive a fractional share of gross oil and gas production revenue — free of drilling, completion, and operating costs. It is created by an oil and gas lease, runs with the mineral estate as real property under Texas law, and pays the owner monthly as long as the well produces. It is not a security; it is a real property interest conveyed by deed and recorded in the county where the land sits.

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When people talk about owning mineral rights in Texas, they are often describing something more specific: a royalty interest. Understanding what a royalty interest is — how it is created, what it entitles the owner to, and how it differs from other forms of mineral ownership — is foundational knowledge for any buyer entering the Texas mineral rights market.

I have worked with buyers evaluating interests across the Fort Worth Basin, the Permian Basin, and the Barnett Shale play. The questions I hear most often come back to the same core issue: buyers are not always sure what they are actually buying. This post answers that question precisely.

What Is a Royalty Interest in Oil and Gas?

A royalty interest is the right to receive a fractional share of gross production revenue from an oil or gas well, free of the costs of drilling, completing, and operating that well.

The royalty interest owner does not invest capital in the well. Drilling costs, completion crews, gathering pipelines, and saltwater disposal are borne entirely by the working interest owner — the operator. In exchange for taking on all capital risk and operational responsibility, the operator retains the majority of production revenue. The royalty interest owner receives their contractually defined percentage of gross revenue each month the well produces.

Under Texas law, a mineral interest — including the royalty right it carries — is classified as real property. The Texas Property Code, Section 1.002, defines real property to include land and anything permanently attached to it, and Texas courts have long held that mineral interests are interests in real property, not personal property or securities. A royalty interest is conveyed by a deed recorded in the county clerk's office where the land is located, the same way surface real estate is transferred. The Texas Railroad Commission (RRC) regulates oil and gas production in the state and maintains public records of well permits, production volumes, and operator information that buyers can use to verify the production history of any interest before closing.

How Is a Royalty Interest Created?

A royalty interest is created through an oil and gas lease. When a mineral owner signs a lease with an operator, the lease grants the operator the right to drill and produce from the mineral estate for a defined primary term — typically three to five years in Texas, though this varies. In exchange, the operator agrees to pay the mineral owner a royalty — a percentage of gross production revenue — for as long as the well produces in paying quantities.

The royalty rate is negotiated and stated in the lease. In Texas, royalty rates have historically ranged from 1/8 (12.5%) to 1/4 (25%). In highly competitive plays such as the Permian Basin's Midland and Delaware sub-basins, rates can exceed 25% where mineral owners hold significant bargaining leverage. The rate reflects the productivity of the acreage, the operator's appetite for the play, and market conditions at the time of leasing.

Once the lease is executed and a producing well is drilled, the royalty interest becomes active. The mineral owner begins receiving monthly royalty payments from the operator or the operator's revenue distribution system, typically 60 to 90 days after first production.

From my work in the Fort Worth Basin, where the Barnett Shale underlies much of Tarrant, Johnson, and Hood Counties, I have seen royalty rates on legacy leases as low as 1/8 — leases signed before horizontal drilling transformed the play's economics. Buyers acquiring interests burdened by older low-royalty leases should model the income accordingly and not assume current market rates apply to the underlying lease.

What Is the Difference Between a Royalty Interest and a Working Interest?

The distinction between a royalty interest and a working interest is fundamental for any buyer to understand before making an acquisition decision.

A working interest owner participates in both the costs and revenues of the well. They pay their proportionate share of drilling, completion, and operating expenses, and they receive their proportionate share of production revenue after those costs. Working interest ownership carries direct financial risk — if the well underperforms, commodity prices fall, or operating costs rise, the working interest owner absorbs those losses.

A royalty interest owner bears none of those costs. Their income is a percentage of gross revenue, not net revenue after expenses. They have no obligation to fund drilling or operations. Their downside risk is limited to production decline and commodity price movement — they cannot be assessed for operating losses.

This cost-free structure is what distinguishes royalty interests from working interests in both economics and risk profile, and it is the primary reason buyers seek them as passive income assets rather than operational investments.

What Is the Difference Between a Royalty Interest and an Overriding Royalty Interest?

This distinction is one of the most consequential — and most commonly misunderstood — in mineral rights acquisitions.

A royalty interest is carved out of the mineral estate itself and runs with the land. It survives the expiration of any particular lease. If one lease expires and a new lease is executed on the same acreage, the mineral owner's royalty right continues under the new lease terms. The interest is perpetual as long as the mineral estate exists.

An overriding royalty interest (ORRI) is carved out of the working interest, not the mineral estate. It entitles the holder to a percentage of production revenue above and beyond the landowner's royalty, but it is tied to a specific lease. When that lease expires — whether by its primary term ending without production, by the operator releasing the acreage, or by any other termination — the ORRI expires with it. The ORRI holder has no rights under any subsequent lease on the same acreage.

In my experience facilitating acquisitions in the Fort Worth Basin and Permian Basin, buyers who confuse ORRIs with perpetual mineral interests are the most common due diligence gap I encounter. A seller may market an "oil and gas interest" without clearly distinguishing whether it is a mineral interest or an ORRI. The deed language controls. Buyers should require their title attorney to confirm the nature of the interest — mineral estate or leasehold carve-out — before closing. The difference in long-term value between a perpetual mineral interest and an ORRI on a lease with five years remaining can be substantial.

How Is Royalty Income Calculated?

The royalty interest owner's monthly payment is calculated from their net revenue interest (NRI) — the decimal fraction of gross production revenue they are entitled to receive from a specific well or pooled drilling unit.

The NRI is derived from three inputs: the mineral owner's net mineral acres, the size of the pooled drilling unit, and the lease royalty rate. The formula is:

NRI = (Net Mineral Acres ÷ Drilling Unit Acres) × Royalty Rate

For example: a mineral owner with 10 net mineral acres in a 640-acre drilling unit under a 1/5 (20%) royalty lease has an NRI of 0.003125 (10 ÷ 640 × 0.20). If the well generates $100,000 in gross revenue in a given month, that owner receives $312.50 before any permitted deductions.

Deductions for post-production costs — transportation, processing, and compression — can reduce the net payment below the gross royalty calculation. Whether deductions are permitted depends entirely on the language of the underlying lease. Leases with "at the wellhead" or "no deduction" language protect the full royalty. Leases that are silent on deductions, or that permit "reasonable" post-production costs, can result in meaningful reductions to the monthly payment.

The U.S. Energy Information Administration (EIA) publishes monthly production and price data by basin and state. Buyers can use EIA data to benchmark the production volumes and commodity prices underlying a royalty income stream against regional averages before making an acquisition decision.

What Factors Affect the Value of a Royalty Interest?

Several variables determine how much a royalty interest is worth. Buyers should evaluate each one before pricing an acquisition.

• Production rate. Current production is the most immediate driver of royalty income. The Texas Railroad Commission's online production query system provides monthly production volumes for every permitted well in Texas, going back years. This is the first data source any serious buyer should consult.
• Decline curve. Oil and gas wells decline in production over time. The decline curve — the rate at which production falls month over month — determines how long the income stream will remain meaningful. Horizontal wells in tight formations like the Permian Basin's Wolfcamp or the Barnett Shale typically show steep initial declines followed by a long, shallow tail. Buyers should model the decline before pricing.
• Commodity prices. Royalty income is production volume multiplied by commodity price. The EIA publishes short-term and long-term price forecasts that buyers can use to stress-test income assumptions across price scenarios.
• Royalty rate. A 25% royalty generates twice the income of a 12.5% royalty on the same production from the same well. The lease royalty rate is fixed at signing and does not change during the lease term.
• Lease deduction provisions. Post-production cost deductions can meaningfully reduce net royalty income. Review the lease language carefully — this is one of the most overlooked variables in royalty interest due diligence.
• Operator quality. The operator controls the well. Their decisions about workovers, recompletions, and infill drilling directly affect production levels and the longevity of the income stream. The Texas Railroad Commission's compliance records show whether an operator has outstanding violations on the subject well.
• Remaining proved reserves. The volume of recoverable hydrocarbons remaining in the formation determines the long-term income potential of the interest. Reserve estimates for public operators are disclosed in SEC filings under Regulation S-X, Rule 4-10, which governs oil and gas reserve disclosures for reporting companies.

How Are Royalty Interests Taxed?

Royalty income from oil and gas production is subject to federal income tax as ordinary income in the year received. However, mineral interest owners are entitled to a depletion deduction — a tax allowance that recognizes the gradual exhaustion of the mineral resource.

For most individual owners, the IRS allows a percentage depletion deduction of 15% of gross royalty income, subject to the limitation that the deduction cannot exceed 100% of the net income from the property. This deduction can meaningfully reduce the effective federal tax rate on royalty income. IRS Publication 535, Chapter 9 covers depletion in detail.

Texas does not impose a state income tax on individuals. However, the Texas Comptroller administers the state's oil and gas severance tax, which is assessed at the production level and deducted before royalty payments are made. The current severance tax rate on oil production in Texas is 4.6% of market value; the rate on natural gas is 7.5% of market value. These rates are deducted by the operator before the royalty check is issued — the royalty owner does not pay them separately.

Buyers should consult a qualified CPA with oil and gas experience before acquiring a royalty interest to understand the full federal and state tax treatment for their specific situation.

What Should a Buyer Review Before Acquiring a Royalty Interest?

Due diligence on a royalty interest acquisition should cover at minimum the following:

1. Title chain. Confirm the seller has clear, marketable title to the interest being conveyed. A title attorney or experienced landman should review the deed records in the county clerk's office going back at least 40 years, or to the root of title. Under the Texas Mineral Interest Pooling Act and related statutes, title defects can affect the validity of the interest being conveyed.
2. Lease terms. Review the royalty rate, deduction provisions, depth and formation limitations, and any Pugh clause language in the underlying lease. These terms directly affect the income the buyer will receive.
3. Production history. Pull the well's production history from the Texas Railroad Commission's public database. Verify that reported production volumes match the royalty income history provided by the seller. Discrepancies may indicate division order errors, suspended payments, or title disputes.
4. Division order. The division order — a document issued by the operator that sets out each owner's decimal NRI in a specific well — is the instrument that authorizes royalty payments. Review it carefully. Division order errors are not uncommon, particularly on older wells or wells with complex ownership histories, and they can result in underpayments that are difficult to recover retroactively.
5. Operator standing. Confirm the operator is in good standing with the Texas Railroad Commission and has no outstanding compliance violations on the subject well. The RRC's compliance database is publicly searchable.
6. Deed form and conveyance language. The deed conveying the interest should clearly identify the type of interest (mineral interest vs. ORRI), the legal description of the land, the county of recording, and any reservations or exceptions. Texas State Royalties coordinates deed preparation and county recording as part of every facilitated acquisition.

Texas State Royalties facilitates acquisitions of producing mineral and royalty interests for qualified buyers. Our role is to source interests, assist with due diligence coordination, and manage the deed conveyance process — we are a facilitator, not a broker, and we do not provide investment, tax, or legal advice. Learn more about how we work with buyers or review our acquisition services.

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Key Takeaways

• A royalty interest is the right to receive a share of gross oil and gas production revenue with no obligation to pay drilling or operating costs. It is real property under Texas law, conveyed by deed.

• It is created by an oil and gas lease and, when tied to the mineral estate, runs with the land in perpetuity — unlike an overriding royalty interest (ORRI), which is tied to a specific lease and expires when that lease terminates.

• Monthly royalty income is calculated from the net revenue interest (NRI) — a decimal fraction applied to gross well revenue, derived from net mineral acres, drilling unit size, and lease royalty rate.

• Key value drivers are production rate, decline curve, royalty rate, lease deduction provisions, commodity prices, and operator quality. All are verifiable through public sources before closing.

• Royalty income is taxed as ordinary income but qualifies for a 15% percentage depletion deduction under IRS rules. Texas severance taxes (4.6% on oil, 7.5% on gas) are deducted at the production level before payment.

• The most common due diligence gap in royalty interest acquisitions is failing to confirm whether the interest being purchased is a perpetual mineral interest or a lease-tied ORRI. The deed language controls.

• Reserve classifications follow SEC Regulation S-X Rule 4-10; under Texas Natural Resources Code, the mineral estate is the dominant estate and the operator is obligated to pay royalties as specified in the lease; under Texas Estates Code, mineral 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 interest and mineral rights? Mineral rights refer to ownership of the subsurface mineral estate — the right to explore, develop, and produce oil, gas, and other minerals from a tract of land. A royalty interest is the specific right, created by an oil and gas lease, to receive a percentage of production revenue from that estate. All royalty interests derive from mineral rights, but not all mineral rights are currently under lease and generating royalty income. An unleased mineral interest has potential value; a leased, producing royalty interest has current income.

Can a royalty interest be sold separately from the surface land? Yes. In Texas, the mineral estate is severable from the surface estate and can be bought, sold, and conveyed independently by deed. This severability is established under Texas common law and codified in the Texas Property Code. A royalty interest — as a component of the mineral estate — can likewise be conveyed separately. The deed is recorded in the county clerk's office of the county where the land is located.

How long does a royalty interest last? A royalty interest tied to the mineral estate runs with the land and has no expiration date as long as the mineral estate exists. It continues through successive leases and successive operators. An overriding royalty interest (ORRI), by contrast, is tied to a specific lease and expires when that lease terminates — whether by its primary term ending without production, by the operator releasing the acreage, or by any other termination event.

What is a division order and why does it matter? A division order is a document issued by the well operator that sets out each owner's decimal NRI in a specific well. It is the instrument that authorizes the operator to begin making royalty payments. Buyers should review the division order after closing to confirm the decimal interest matches what was represented in the purchase agreement. Division order errors — particularly on wells with complex ownership histories — can result in underpayments that are difficult to recover retroactively.

Are royalty interests considered securities under federal law? No. A royalty interest in oil and gas is a real property interest, not a security. It is conveyed by deed, recorded in county property records, and regulated under Texas property law. The SEC's definition of a security under the Securities Act of 1933 does not encompass a fee mineral interest or a standard landowner's royalty interest. This distinction matters for how the interest is acquired, held, and transferred — and it is why Texas State Royalties describes every transaction as a deed conveyance of real property, not a securities offering.

How do I verify the production history of a royalty interest before buying? Production data for every permitted well in Texas is publicly available through the Texas Railroad Commission's online production query system. Buyers can search by API number, operator name, lease name, or county and review monthly oil and gas production volumes going back years. This data is the starting point for any royalty interest valuation and should always be cross-referenced against the income history provided by the seller.

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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. If you are evaluating a royalty interest acquisition, start your buyer search here.

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This article is for educational purposes only and is not investment, tax, or legal advice. Consult a qualified CPA, attorney, or financial advisor before purchasing mineral or royalty interests.

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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.