How to Buy Producing Mineral Interests in Texas

By Richard Partin, Managing Member, Texas State Royalties LLC Fort Worth, Texas | Published: September 29, 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 mistake I see from first-time buyers is treating a mineral interest acquisition like a stock purchase — moving quickly on price without doing the underlying work on production history, lease terms, and title. This guide covers the full process, including the specific verification steps that separate a clean acquisition from a costly one.

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Quick Answer: Buying a producing mineral interest in Texas involves five steps: define your acquisition criteria (basin, budget, income target), source vetted opportunities through a facilitator or direct outreach, evaluate the production history against RRC data and review the lease terms and operator quality, run the economics using realistic decline curves and current valuation multiples, and close with a title opinion and recorded deed. Producing Permian Basin interests currently trade at 40–60x monthly royalties; Fort Worth Basin Barnett interests at 30–45x.

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If you have capital ready to deploy and you are looking for a real property interest that generates royalty income without the obligations of active management, producing mineral interests in Texas deserve a serious look.

Unlike rental properties or operating businesses, a mineral interest pays you a percentage of production revenue every month the well produces — no tenants, no maintenance, no operating costs. You own a fractional share of the income stream, not the responsibility of running the operation.

But buying mineral interests is not as simple as clicking purchase. There is a process, and doing it right means understanding what you are buying before you commit a dollar.

This guide walks you through the full acquisition process — from defining your criteria, to evaluating an opportunity, to closing the deal and receiving your first royalty check.

For a foundational explanation of the different types of mineral interests and which ones buyers typically target, see Types of Mineral Interests: A Buyer's Reference.

What Is a Producing Mineral Interest and Why Does It Matter?

A mineral interest gives the owner the right to a share of the oil, gas, and other minerals extracted from a tract of land under the Texas Natural Resources Code. When a well is actively producing, the mineral interest owner receives royalty payments — a percentage of the gross revenue from production, free of operating costs.

"Producing" is the key word. A producing mineral interest is one tied to a well that is currently generating output and generating royalty income. That is different from a speculative mineral interest, where you are betting on future drilling activity that may or may not occur.

For income-focused buyers, producing interests are the target. You want cash flow from day one, not a waiting game on a development timeline you cannot control.

The most important distinction for buyers is between a fee mineral interest — perpetual ownership of the mineral estate itself, which survives lease expiration — and a royalty interest or overriding royalty interest (ORRI), which are lease-dependent and expire when the underlying lease terminates. Most buyers targeting income should focus on fee mineral interests. An ORRI may generate the same monthly check today but carries no value after the lease expires. For a full breakdown of interest types, see Types of Mineral Interests: A Buyer's Reference.

Why Does Texas Attract Mineral Interest Buyers?

Texas is the largest oil and gas producing state in the country. The Permian Basin in West Texas is one of the most prolific oil-producing regions on earth. The Eagle Ford Shale in South Texas has been a major natural gas and condensate play since the early 2010s. The Fort Worth Basin Barnett Shale was the birthplace of the modern shale revolution and remains an active, mature producing basin.

What this means for mineral interest buyers:

• Established production history. You can evaluate real data from the Texas Railroad Commission production database, not projections.
• Active operators. Major and mid-size operators are continuously drilling and completing new wells across multiple basins.
• Legal infrastructure. Texas has a well-developed body of mineral rights law and a robust county deed recording system.
• Liquidity. The Texas mineral market is active, with buyers and sellers transacting regularly across all major basins.
• Severance tax transparency. The Texas Comptroller publishes severance tax data — 4.6% on oil production and 7.5% on gas production — which allows buyers to cross-check reported production volumes against tax filings.

If you are going to own mineral interests, Texas is the most logical place to start.

How Do You Define Your Acquisition Criteria Before You Start Looking?

Before evaluating specific opportunities, get clear on what you are looking for. Buyers who skip this step waste time evaluating interests that do not fit their actual objectives.

Income target. How much monthly royalty income are you trying to generate? This determines the size of the interest you need to acquire at current production levels and commodity prices.

Basin preference. Do you have a preference for Permian Basin (oil-weighted, higher current multiples), Fort Worth Basin Barnett (gas-weighted, lower multiples, mature production), or Eagle Ford (condensate and gas, mid-range multiples)? Each basin has a different production profile, operator mix, commodity exposure, and decline curve.

Purchase budget. Mineral interests can range from a few thousand dollars for a small fractional interest to millions for a significant producing tract. Your budget determines which opportunities are realistic.

Decline tolerance. All wells decline. Are you looking for a flat, long-lived production profile, or are you comfortable with a steeper initial decline in exchange for a lower purchase price? Wolfcamp and Barnett wells typically decline 60–80% in the first year; mature Barnett wells decline 5–10% annually. Your time horizon and income requirements should drive this decision.

Interest type. Are you targeting fee mineral interests only, or are you open to NPRIs or ORRIs? Fee mineral interests are perpetual; ORRIs are lease-dependent. Most buyers focused on long-term income should target fee mineral interests.

How Do You Source Quality Opportunities?

The mineral interest market is not like the stock market. There is no centralized exchange. Opportunities come through several channels:

• Mineral interest facilitators. Companies like Texas State Royalties specialize in sourcing and presenting vetted opportunities to qualified buyers. You get access to pre-screened interests and guidance through the due diligence process.
• Direct outreach to mineral owners. Some buyers identify landowners through county deed records and approach them directly. This requires significant time and local market knowledge.
• Online marketplaces. Platforms like EnergyNet and MineralSoft list mineral interests for sale, though quality and vetting vary widely.
• Estate and probate situations. Mineral interests frequently change hands through estate proceedings. Heirs who inherit fractional interests often prefer to sell rather than manage a small royalty income stream.

For most buyers, working with a facilitator who has existing relationships and sourcing infrastructure is the most efficient path to a vetted, closeable opportunity.

How Do You Evaluate a Producing Mineral Interest Before You Buy?

This is where most buyers either do the work or get burned. A thorough evaluation covers five areas.

Production History

Request the production history for the well or wells associated with the interest. You want to see current production rate, production trend, and operator activity over time.

The Texas Railroad Commission publishes production data for all Texas wells. Always cross-check the seller's income summary against RRC production records. In my experience reviewing acquisition packages, seller summaries frequently reflect the best production months and omit low-production periods. Discrepancies between a seller's summary and RRC data consistently favor the seller. The RRC data is the authoritative record — use it.

Operator Quality

The operator is the company running the well. Their competence and financial health directly affect your royalty income. In Permian Basin acquisitions, operator compliance history is the single most predictive factor of future well management quality. Check the RRC for any violations, enforcement actions, or plugging orders before assigning value to an interest operated by a company you have not evaluated.

Look for track record in the specific basin, financial stability (major vs. mid-size independent vs. small private operator), and active development plans for the acreage.

Lease Terms

Review the existing oil and gas lease. The royalty fraction in the lease determines your gross revenue share, but the post-production cost provisions determine what you actually receive. 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 with aggressive post-production deductions may generate less net revenue than a 3/16 royalty lease with a wellhead valuation clause.

Also verify the primary term and held-by-production status. A lease that is approaching the end of its primary term without established production carries expiration risk that must be reflected in the acquisition price.

Title and Ownership

Mineral title in Texas can be complex. Interests are often fractional, and ownership can be split among multiple parties through generations of inheritance and conveyance. Decimal interest errors are common in estate proceedings — a 1/4 royalty fraction on a 1/8 mineral ownership yields a decimal interest of 0.03125, not 0.25. Verify the decimal interest independently before closing.

Before closing, you need a title opinion from a qualified Texas oil and gas attorney confirming that the seller owns what they are selling, there are no liens or competing claims, and the interest is properly described in the deed.

Royalty Income Under IRS Rules

Under IRS Publication 535, royalty income from mineral interests is subject to depletion. 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. Consult a licensed CPA with oil and gas experience before making any acquisition decision.

How Do You Run the Numbers on a Mineral Interest Acquisition?

Once you have completed due diligence, model the economics before committing to a price.

Current monthly income. Multiply current production volume by the applicable commodity price by your decimal interest. This is your baseline monthly royalty income before severance tax (4.6% on oil, 7.5% on gas per the Texas Comptroller) and any post-production deductions.

Decline curve. Model a realistic decline rate to project income over 5, 10, and 20 years. Wolfcamp and Barnett wells typically decline 60–80% in year one; mature Barnett wells 5–10% annually. A petroleum engineer or your facilitator can help model a realistic curve for the specific well and basin.

Valuation multiples. Producing Permian Basin interests currently trade at 40–60x monthly royalties. Fort Worth Basin Barnett interests trade at 30–45x monthly royalties, reflecting the lower commodity price environment for gas and the more mature production profile. Buyers applying a discounted cash flow approach typically use a 10–15% discount rate for Permian cash flows and 15–20% or higher for Barnett Shale gas, reflecting the greater commodity price uncertainty for natural gas.

Upside potential. Is there additional drilling potential on the tract? Are there undeveloped zones that could be completed in the future? Upside potential can justify a premium above the producing-only value, but it should be modeled conservatively.

Under SEC Regulation S-X, Rule 4-10, working interest owners are required to classify reserves as Proved Developed Producing (PDP), Proved Undeveloped (PUD), or Probable. Royalty interest owners are not subject to the same reserve reporting requirements, but the PDP/PUD framework is a useful lens for evaluating the upside component of any acquisition.

What Does the Closing Process Look Like?

Once you have agreed on price and terms, the closing process involves five steps:

1. Purchase and sale agreement. A contract specifying the interest being sold, the price, representations and warranties, and closing conditions.
2. Title review. Your attorney reviews the title chain and issues a title opinion confirming clean ownership.
3. Deed preparation. A mineral deed conveying the interest from seller to buyer, prepared by your attorney and reviewed before execution.
4. Recording. The deed is recorded in the county clerk's office in the county where the land is located. Recording establishes your ownership in the public record.
5. Division order. After closing, the operator will send a division order for you to sign, which establishes your decimal interest in their records and triggers royalty payments.

From signed purchase and sale agreement to first royalty check typically takes 60–90 days, depending on title complexity and operator processing time. For a detailed explanation of what happens after closing, see What to Expect After You Buy a Mineral Interest.

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Key Takeaways

• Producing mineral interests in Texas generate royalty income — a percentage of gross production revenue, free of operating costs — from day one of ownership. The buyer bears no drilling costs, no capital calls, and no operating obligations.

• The most important distinction for buyers is between fee mineral interests (perpetual, survive lease expiration) and ORRIs (lease-dependent, expire when the lease terminates). Most income-focused buyers should target fee mineral interests. Confusing the two is the most common due diligence mistake in Fort Worth Basin acquisitions.

• Always cross-check the seller's income summary against Texas Railroad Commission production data before assigning value. Seller summaries frequently omit low-production months; discrepancies vs. RRC data consistently favor the seller.

• Permian Basin operator compliance history is the most predictive factor of future well management quality. Check the RRC for violations and enforcement actions before evaluating any Permian acquisition.

• Producing Permian Basin interests currently trade at 40–60x monthly royalties; Fort Worth Basin Barnett interests at 30–45x. Buyers apply a 10–15% discount rate to Permian cash flows and 15–20% or higher to Barnett Shale gas, reflecting commodity price uncertainty.

• 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. Review the lease terms — not just the royalty fraction — to understand actual net revenue.

• Royalty income from mineral interests is subject to percentage depletion at 15% under IRS Publication 535, which is one of the primary tax advantages of owning a royalty interest rather than a working interest. Consult a licensed CPA with oil and gas experience before acquiring.

• 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

How long does it take to receive the first royalty check after buying a mineral interest? From signed purchase and sale agreement to first royalty check typically takes 60–90 days. The closing process — title review, deed preparation, recording, and division order execution — takes 30–45 days in most cases. After the deed is recorded, the operator must process the division order and update their ownership records before issuing payment. Operators typically pay royalties 60–90 days after the production month, so the first check may reflect production that occurred before you closed. For a detailed timeline of what to expect after closing, see What to Expect After You Buy a Mineral Interest.

What is the difference between a fee mineral interest and an overriding royalty interest (ORRI)? A fee mineral interest is perpetual ownership of the mineral estate — it survives lease expiration and remains valid indefinitely under Texas law. An overriding royalty interest (ORRI) is carved out of the working interest under a specific lease and expires when that lease terminates. Both generate monthly royalty income while the well is producing, but an ORRI has no value after the lease expires. Buyers who do not examine the source document may pay mineral-interest prices for a lease-dependent ORRI. For a full breakdown of interest types, see Types of Mineral Interests: A Buyer's Reference.

How are mineral interest acquisitions taxed? 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 valuation multiples do producing mineral interests trade at in Texas? Producing Permian Basin interests currently trade at 40–60x monthly royalties, reflecting the oil-weighted production profile, strong operator activity, and relatively predictable decline curves. Fort Worth Basin Barnett Shale interests trade at 30–45x monthly royalties, reflecting the gas-weighted production profile and the greater commodity price uncertainty for natural gas. Buyers applying a discounted cash flow approach typically use a 10–15% discount rate for Permian cash flows and 15–20% or higher for Barnett Shale gas. Non-producing Permian interests trade at roughly 1/10 to 1/15 of producing interest values, reflecting the development risk premium.

What is a division order and why does it matter? 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 — the fraction of production revenue you are entitled to receive. Signing the division order authorizes the operator to begin paying royalties to you at the stated decimal interest. Before signing, verify that the decimal interest matches your calculation: royalty fraction × your ownership fraction in the mineral estate. Decimal interest errors are common, particularly in estate proceedings involving fractional mineral interests. For a detailed explanation, see What Is a Division Order and Why Does It Matter?.

How does Texas State Royalties facilitate mineral interest acquisitions? Texas State Royalties sources and facilitates acquisitions of producing fee mineral interests for qualified buyers across Texas. We handle sourcing, initial production and title review, and walk buyers through every step of the process — from evaluating an opportunity through deed conveyance and first royalty payment. We work exclusively with buyers, not sellers, and focus on producing acreage interests in Texas's most active basins. 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 acquisitions vary by state and by the specific terms of each transaction. 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.