How to Buy Mineral Rights in Texas: A Step-by-Step Guide for Buyers

By Richard Partin, Managing Member, Texas State Royalties LLC Fort Worth, Texas | Published: October 12, 2026 | Last Updated: October 16, 2026

My family has been in the oil and gas business in Comanche and Eastland Counties for multiple generations — first as operators, now as a facilitator helping qualified buyers acquire producing mineral and royalty interests across Texas. I studied biology and chemistry at UT Arlington, which gave me a foundation for reading formation data and production geology the way most mineral buyers cannot. I run Texas State Royalties LLC out of Fort Worth, and the acquisitions I facilitate span the Fort Worth Basin, the Permian Basin, and the plays in between. Everything in this guide comes from that direct experience.

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Quick Answer: To buy mineral rights in Texas, you need to: (1) understand what type of interest you are acquiring and how it generates royalty income; (2) locate available interests through direct sellers, facilitators, or county deed records; (3) evaluate production history, title, and lease terms through independent due diligence; (4) execute a mineral deed and record it in the county clerk's office where the land sits; and (5) notify the operator and confirm your division order. Each step has legal and financial consequences — working with a qualified oil and gas attorney and an experienced facilitator reduces risk at every stage.

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Texas sits atop some of the most productive oil and gas formations in the world — the Permian Basin, the Eagle Ford Shale, the Haynesville, and the Barnett Shale among them. That geology, combined with Texas's unique legal framework for mineral ownership, makes the state one of the most active markets for mineral interest acquisitions in the country.

Buying mineral rights in Texas is not like buying a stock or a piece of surface real estate. The process involves title research, production analysis, deed drafting, and county recording — each step with its own requirements and potential pitfalls. The buyers I work with who do best are those who understand the full process before they start. This guide walks through it from start to finish.

What Is a Mineral Interest and How Does It Generate Income?

A mineral interest gives the owner the right to the oil, gas, and other minerals beneath a specific tract of land. Under Texas law, the mineral estate is classified as real property and is severable from the surface estate — the two can be, and in Texas very often are, held by different parties. This separation is called a split estate.

The split estate is not an edge case in Texas — it is the default condition across most of the state's producing basins. In the counties I work in most frequently, including Midland, Ector, Reeves, and Tarrant, it is common to find surface ownership and mineral ownership in completely different hands, sometimes separated by decades of independent conveyances.

When an operator leases your mineral interest and produces oil or gas, you receive a royalty — a percentage of gross production revenue paid without bearing any of the drilling, completion, or operating costs. The royalty rate, the lease terms, and the productivity of the underlying formation determine what that income looks like month to month.

Under the Texas Property Code and long-established Texas common law, a mineral interest is real property — not a security, not a financial instrument. It is conveyed by a deed recorded in the county clerk's office of the county where the land is located, the same way surface real estate is transferred. The Texas Railroad Commission (RRC) regulates all oil and gas production in Texas and maintains public records of well permits, production volumes, and operator compliance that buyers can access before closing on any interest.

For a thorough grounding in how mineral interests are structured, see Understanding Mineral Interests: The Complete Guide for Buyers.

What Type of Mineral Interest Should You Buy?

Not all mineral interests are the same. The two most common types buyers encounter are:

Mineral interests (fee minerals): Full ownership of the minerals beneath a tract. You can lease them, sell them, or pass them to heirs. When unleased, you own the minerals outright. When leased, you receive a royalty. Fee minerals carry the right to negotiate future lease terms, including the royalty rate — which means buyers benefit from any upward revision in rates when a lease expires and is renegotiated.

Royalty interests: A right to receive a fraction of production revenue, typically carved out of a mineral interest at the time of leasing. Royalty interests do not carry the right to lease — they simply receive income when a well produces. They are perpetual when tied to the mineral estate, but they do not give the holder any say in future lease negotiations.

Most buyers seeking long-term income and asset appreciation target fee mineral interests rather than standalone royalty interests, because fee minerals give you the right to negotiate future leases and benefit from any upward revision in royalty rates when existing leases expire.

One pattern I see repeatedly in the Fort Worth Basin: buyers acquire what they believe is a fee mineral interest, only to discover after closing that they purchased an overriding royalty interest (ORRI) — a leasehold carve-out that expires when the underlying lease terminates. The deed language controls. Before closing, your title attorney must confirm whether you are acquiring a perpetual mineral estate interest or a lease-tied ORRI. The long-term value difference between the two is substantial.

For a full breakdown of interest types, see Types of Mineral Interests in Oil and Gas.

How Do You Find Mineral Rights for Sale in Texas?

Mineral interests are not listed on an exchange. Finding available acreage requires knowing where to look and understanding the trade-offs of each source.

Mineral facilitators source, evaluate, and structure interests for qualified buyers. This is the most efficient path for buyers who want vetted, producing acreage without doing the sourcing work themselves. Texas State Royalties operates this way — we source interests, coordinate due diligence, and manage the deed conveyance and county recording process for buyers. Learn more about how we work with buyers.

Direct sellers — landowners who have inherited mineral interests and want liquidity — are a primary source of off-market acreage. In my experience working across Comanche, Eastland, Palo Pinto, and surrounding counties, a significant share of mineral owners inherited their interests through family estates and have never actively managed them. Many do not know what they own or what it is worth. Reaching these sellers requires direct outreach through county deed records and, often, patient relationship-building over time.

County deed records are the ground truth for mineral ownership in Texas. Every county clerk's office maintains deed records that identify mineral interest ownership by tract. Searching these records — either directly or through a landman — can reveal owners who have not marketed their interests and may be receptive to a fair offer.

Online marketplaces exist where mineral owners list interests for sale. Quality and due diligence standards vary widely. Buyers should conduct independent production verification through the Texas Railroad Commission and independent title review regardless of how an interest is presented on any platform.

For a deeper look at sourcing strategies, see How to Find Producing Mineral Interests for Sale.

How Do You Evaluate a Mineral Interest Before Buying?

Evaluation is where buyers either protect themselves or expose themselves to risk. A thorough evaluation covers three areas: production, title, and lease terms. All three must be completed independently before you commit to a price.

How Do You Analyze Production History?

Pull the well's production history directly from the Texas Railroad Commission's production query system before relying on anything the seller provides. The RRC database is free, publicly accessible, and updated monthly. It is the authoritative source for Texas well production data.

When reviewing production history, look for:

Decline curve shape. Oil and gas wells decline in production over time. The shape of that decline tells you a great deal about the formation and the well's remaining productive life. Horizontal wells in tight formations — the Wolfcamp in the Permian Basin's Midland sub-basin, the Barnett Shale in the Fort Worth Basin — typically show steep initial declines of 60–80% in the first year, followed by a long, shallow tail that can produce for decades at reduced rates. My science background at UT Arlington gave me a working understanding of reservoir mechanics that I apply directly when reviewing decline curves for buyers. A well that has already passed through its steep initial decline and is producing on a shallow tail is a different risk profile than a well still in its first year of production.

Production consistency. Gaps in monthly production — months with zero or near-zero output — can indicate mechanical problems, regulatory holds, or title disputes. Every gap deserves an explanation before closing. I have seen gaps that turned out to be routine workovers and gaps that revealed unresolved title disputes that had suspended the operator's payments entirely.

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 RRC's compliance database shows whether an operator has outstanding violations on the subject well. For Permian Basin acquisitions, I pay particular attention to whether the operator has a track record of successful recompletions and infill drilling in the same formation — that activity can meaningfully extend the productive life of an interest.

Reported income vs. RRC production. If the seller provides royalty check stubs or a production summary, cross-reference the reported volumes against the RRC data. Discrepancies between what a seller reports and what the RRC shows are a red flag. In my experience, when the two do not match, the discrepancy is almost always in the seller's favor. Independent RRC verification is not optional.

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.

How Do You Review Title on a Mineral Interest?

Title is the most technically demanding part of mineral interest due diligence. You need to confirm that the seller actually owns what they are selling — and that no prior conveyances, reservations, or encumbrances cloud the title.

A proper title review involves:

Chain of title going back to the original patent or a recognized root of title. In Texas, mineral interests have been subdivided and conveyed through generations of family estates, often without professional guidance. It is not unusual to find a chain of title in Comanche or Eastland County that runs through four or five generations of heirs, with interests fractured into small decimal shares at each step. Every link in that chain must be verified.

Prior reservations. When Texas landowners sold surface acreage in the early and mid-twentieth century, it was common practice to reserve a fraction of the minerals. Those reservations are still in the deed records and still affect the net interest available for sale today. A seller who believes they own 100% of the minerals beneath a tract may actually own 50% or 75% because of a reservation made by a prior owner decades ago.

Outstanding leases, ORRIs, and production payments. These encumbrances reduce the net interest the buyer receives. They must be identified and quantified before closing.

Heirship. If the interest passed through an estate — which is common with inherited mineral interests — confirm that heirship has been properly established in the county deed records through a probated will or a recorded affidavit of heirship. An interest that passed outside of probate without a recorded affidavit may have a clouded title that is difficult and expensive to cure after closing.

For most buyers, engaging a landman or oil and gas attorney to run title is money well spent. Under Texas recording law, an unrecorded deed is valid between the parties but may be defeated by a subsequent purchaser who records first without notice of the prior conveyance. Title defects discovered after closing are expensive to cure and can cloud ownership for years.

What Lease Terms Should a Buyer Review?

The underlying lease controls how much royalty income you actually receive. Key provisions to review before closing:

Royalty rate. In Texas, royalty rates on legacy leases range from 1/8 (12.5%) to 1/4 (25%). In the Fort Worth Basin, I regularly encounter Barnett Shale leases signed in the early 2000s — before horizontal drilling transformed the play's economics — with royalty rates of 1/8 or 3/16. Those leases are often held by production and will not expire until the well stops producing. A buyer acquiring an interest burdened by a below-market royalty rate on a long-term held-by-production lease should model the income at that rate, not at current market rates, for the duration of the lease.

Post-production deductions. Texas law permits operators to deduct certain post-production costs — transportation, processing, and compression — from royalty payments unless the lease prohibits it. 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. This is one of the most overlooked variables in royalty interest due diligence, and it is one I flag for every buyer I work with.

Depth and formation limitations. Some leases cover only specific formations. If the lease does not cover all productive formations beneath the tract, you may receive royalties from some wells but not others on the same acreage.

Pugh clause. A Pugh clause limits the operator's ability to hold all of your acreage by production from a single well. Without one, a single producing well can hold an entire lease — and all of your acreage — indefinitely, preventing you from leasing the remainder to a different operator at a higher royalty rate.

For a structured due diligence framework, see How to Evaluate a Mineral Interest Before You Buy.

How Is a Mineral Interest Priced?

Mineral interests do not have a published price list. Pricing is negotiated between buyer and seller based on several inputs.

Producing interests are typically priced as a multiple of annual royalty income — the trailing twelve months of royalty payments, annualized. The appropriate multiple depends on the formation, the operator, the decline curve, and current commodity prices. The EIA's Short-Term Energy Outlook publishes near-term oil and gas price forecasts that buyers can use to stress-test income assumptions across price scenarios.

Unleased or undeveloped acreage is typically priced on a per-net-mineral-acre (NMA) basis. Pricing depends heavily on proximity to active drilling, the quality of the formation, and comparable transactions in the area. 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 — a useful benchmark for understanding what operators believe is recoverable from a given formation.

Buyers should be cautious of any pricing that relies on projected future drilling activity rather than current production. Speculative acreage carries materially different risk than a producing interest with a documented income history.

How Do You Close a Mineral Interest Transaction in Texas?

Closing a mineral interest transaction involves two key steps: executing the deed and recording it in the county where the land is located.

What Must a Mineral Deed Contain?

The deed is the legal instrument that transfers ownership. Under Texas law, a mineral deed must:

• Identify the grantor (seller) and grantee (buyer) with specificity
• Contain a legal description of the land sufficient to locate it on the ground — typically a metes-and-bounds description or a survey reference tied to the Texas General Land Office survey system
• Specify what is being conveyed — the mineral interest, the royalty interest, or a defined fraction thereof
• Be signed by the grantor and notarized
• Include a statement of consideration

The deed should also specify the warranty of title. A general warranty deed is the strongest protection for the buyer — the seller warrants title against all prior claims, not just those arising during their ownership. A special warranty deed limits the seller's warranty to claims arising during their period of ownership. A quitclaim deed provides no title protection at all. For most acquisitions, buyers should require at minimum a special warranty deed.

Texas State Royalties coordinates deed preparation and county recording as part of every facilitated acquisition. For a detailed explanation of how mineral deeds work, see What Is Deed Conveyance? A Complete Guide for Mineral Interest Buyers.

Why Does Recording the Deed Matter?

Once executed, the deed must be filed with the county clerk in the county where the land is located. Recording gives public notice of the transfer and protects the buyer against subsequent claims. Recording fees vary by county but are typically modest — a few dollars per page.

Do not delay recording. Under Texas recording law, an unrecorded deed is valid between the parties but may be defeated by a subsequent purchaser who records first without notice of the prior conveyance. Record immediately after closing.

What Happens After You Close?

After closing, notify the operator of the ownership change and provide a copy of the recorded deed. The operator will update their records and issue a new division order — a document that specifies your decimal net revenue interest (NRI) in the well and authorizes them to pay you directly.

Review the division order carefully before signing. Confirm that the decimal interest matches your calculation based on your net mineral acres, the drilling unit size, and the lease royalty rate. Division order errors are not uncommon, particularly on wells with complex ownership histories. Under the Texas Natural Resources Code, operators are required to pay royalties within 120 days of first production, but payment is typically contingent on a signed division order — which is why reviewing it promptly matters.

Once the division order is executed and processed, royalty payments should begin flowing within one to two payment cycles — typically 60 to 90 days after the operator processes the transfer.

What Are the Most Common Mistakes Buyers Make?

These are the errors I see most frequently in the acquisitions I facilitate and review:

Skipping independent title review. Title defects are the most common source of post-closing disputes in mineral interest acquisitions. A landman or oil and gas attorney review is not optional for any serious acquisition. The cost of a title review is a fraction of the cost of curing a defect after closing.

Relying on seller-provided production data without RRC verification. Always pull production data directly from the Texas Railroad Commission. I have reviewed seller-provided summaries that omitted months of low production, smoothed out decline curves, or excluded wells on the same acreage that were producing at reduced rates. The RRC data does not lie.

Confusing ORRIs with perpetual mineral interests. This is the most consequential mistake I see buyers make in the Fort Worth Basin. An overriding royalty interest tied to a specific lease has value only as long as that lease remains in force. A perpetual mineral interest runs with the land indefinitely. The deed language controls — confirm which one you are buying before you close.

Overpaying for speculative undeveloped acreage. Acreage that looks cheap on a per-acre basis may be cheap for a reason. Proximity to active drilling matters, and future drilling is never guaranteed. I have seen buyers pay significant premiums for acreage based on an operator's stated drilling plans, only to have those plans delayed or cancelled when commodity prices fell.

Ignoring lease deduction provisions. Post-production cost deductions can meaningfully reduce net royalty income. Review the lease language before pricing the interest — not after closing when the income is lower than expected.

Delaying deed recording. Record the deed immediately after closing. An unrecorded deed is vulnerable to subsequent claims under Texas recording law.

How Does Texas State Royalties Help Buyers?

Texas State Royalties facilitates acquisitions of producing mineral and royalty interests for qualified buyers across Texas. Our role is to source interests, coordinate due diligence, and manage the deed conveyance and county recording process — we are a facilitator, not a broker, and we do not provide investment, tax, or legal advice.

My family background in Comanche and Eastland County oil and gas operations gives me a ground-level understanding of how these assets perform across commodity cycles — not just how they look on paper. My science background from UT Arlington informs how I read formation data and production geology when evaluating interests for buyers. And my focus on the Fort Worth Basin and Permian Basin means I have direct, current knowledge of the operators, formations, and market conditions that affect the interests I bring to buyers.

Learn more about how we work with buyers or review our acquisition services.

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Key Takeaways

• Mineral interests are real property under Texas law, conveyed by deed and recorded in the county clerk's office. They are not securities and do not require a license to purchase.

• Fee mineral interests give the owner the right to lease, receive royalties, and negotiate future lease terms — making them the preferred acquisition target for long-term income buyers over standalone royalty interests or ORRIs.

• The most consequential due diligence mistake in Texas mineral acquisitions is failing to confirm whether the interest is a perpetual mineral estate interest or a lease-tied overriding royalty interest (ORRI). The deed language controls.

• Always pull production data directly from the Texas Railroad Commission — never rely solely on seller-provided summaries. Discrepancies between seller data and RRC records are a red flag.

• Post-production deduction provisions in the underlying lease directly affect net royalty income. Review the lease language before pricing the interest.

• Record the deed immediately after closing. An unrecorded deed is valid between the parties but vulnerable to a subsequent purchaser who records first under Texas recording law.

• Review the division order carefully after closing. Errors in decimal NRI calculations can result in underpayments that are difficult to recover retroactively.

• Reserve classifications follow SEC Regulation S-X Rule 4-10; the PV10 income approach — discounting future net cash flows at 10% — is the standard framework for valuing producing mineral interests

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Frequently Asked Questions

Do I need a license to buy mineral rights in Texas? No. Buying a mineral interest in Texas does not require a real estate license or any other professional license. A mineral interest is real property conveyed by deed — any individual or entity can purchase one. However, buyers should engage a qualified oil and gas attorney to review title and a CPA with oil and gas experience to understand the tax treatment before closing.

How long does it take to close a mineral interest transaction in Texas? A straightforward transaction with clean title and a willing seller can close in two to four weeks. Transactions involving complex title, multiple heirs, or estate issues can take significantly longer. After closing, expect 60 to 90 days before the operator processes the ownership transfer and begins issuing royalty payments under the Texas Natural Resources Code's payment timeline requirements.

What is the difference between a mineral interest and a royalty interest in Texas? A mineral interest (fee mineral) is full ownership of the minerals beneath a tract — including the right to lease, develop, and convey. A royalty interest is the right to receive a fraction of production revenue, typically carved out of the mineral estate at the time of leasing. Fee minerals carry the right to negotiate future leases; royalty interests do not. Both are real property interests conveyed by deed. An overriding royalty interest (ORRI) is a third type — a leasehold carve-out that expires when the underlying lease terminates, unlike a perpetual mineral or royalty interest.

Can mineral rights be inherited in Texas? Yes. Mineral interests pass through estates like any other real property under the Texas Estates Code. They can be devised by will or pass by intestate succession. When an interest passes through an estate, the heir should confirm that heirship has been properly established in the county deed records — through a probated will or a recorded affidavit of heirship — before attempting to sell or lease the interest. Unestablished heirship is one of the most common title defects I encounter in acquisitions involving inherited interests.

Are royalty payments from Texas mineral interests taxable? Yes. Royalty income is subject to federal income tax as ordinary income. However, mineral interest owners are entitled to a percentage depletion deduction — the IRS allows most individual owners to deduct 15% of gross royalty income, subject to limitations. See IRS Publication 535 for details. Texas does not impose a state income tax on individuals, but the Texas Comptroller administers a severance tax on oil (4.6% of market value) and gas (7.5% of market value) that is deducted at the production level before royalty payments are made.

What is a division order and do I have to sign it? A division order is a document issued by the well operator that sets out your decimal net revenue interest (NRI) in a specific well and authorizes the operator to pay you directly. In Texas, operators are required to pay royalties within 120 days of first production under the Texas Natural Resources Code, but payment is typically contingent on a signed division order. Review the decimal interest carefully before signing — it should match your calculation based on your net mineral acres, the drilling unit size, and the lease royalty rate. Errors in division orders are not uncommon, and I review them carefully for every buyer I work with before recommending they sign.

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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 ready to explore available interests, 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.