How to Evaluate a Mineral Interest Before You Buy: A Due Diligence Checklist

By Richard Partin, Managing Member, Texas State Royalties LLC Fort Worth, Texas | Published: September 25, 2026 | Last Updated: October 16, 2026

My family has operated in the oil and gas business in Comanche and Eastland Counties for multiple generations. I studied biology and chemistry at UT Arlington — a background that shapes how I read formation data and production geology — and I now facilitate acquisitions of producing mineral and royalty interests for qualified buyers across Texas through Texas State Royalties LLC. The due diligence framework in this guide is the one I apply to every acquisition I evaluate, whether the interest is in the Fort Worth Basin, the Permian Basin, or the plays in between.

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Quick Answer: Before buying a mineral interest, verify eight things: (1) the seller has clear, marketable title; (2) the underlying lease terms — royalty rate, deduction provisions, and held-by-production status — are acceptable; (3) production history from the Texas Railroad Commission confirms the well is producing consistently; (4) the operator is financially sound and in good standing with the RRC; (5) the price is based on verified production data, not seller projections; (6) post-production deductions are disclosed and authorized by the lease; (7) the tax treatment — including the 15% depletion deduction and Texas severance taxes — is understood before closing; and (8) you have a realistic exit thesis. Each of these eight areas has the potential to materially affect the value of what you are buying.

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In the mineral interest market, buyers who focus on price without completing proper due diligence routinely overpay for declining assets, acquire interests with title defects, or inherit lease terms that significantly reduce their effective royalty. The purchase price is the last thing to negotiate — not the first.

This guide covers the eight areas every buyer must evaluate before acquiring a mineral interest. It is written for buyers who are new to the market and for experienced buyers who want a systematic framework they can apply to every opportunity.

For a foundational understanding of what mineral interests are and how they are structured, start here: Understanding Mineral Interests: The Complete Guide for Buyers.

What Does Title Review Involve for a Mineral Interest?

Title is the foundation of every mineral interest acquisition. A mineral interest is only as valuable as the seller's ability to convey clear, marketable title — and in Texas, where mineral interests have been subdivided and conveyed through generations of family estates, title defects are common.

Chain of title. The chain of title is the sequence of deeds, probate records, and other instruments that establish how ownership passed from one party to the next. A complete chain traces ownership from the original patent or grant to the current seller. Gaps in the chain — missing deeds, unrecorded conveyances, or ambiguous language — create title risk that can be expensive to cure after closing.

Heirship and probate. Many mineral interests in Texas have passed through estates without formal probate. When a mineral owner dies and heirs do not probate the estate, the interest may be held by multiple heirs who are unaware of their ownership. Acquiring from one heir without identifying and obtaining releases from the others creates a title defect. In my work facilitating acquisitions in Comanche and Eastland Counties — where mineral interests have passed through four and five generations of family estates — unestablished heirship is the single most common title defect I encounter. An affidavit of heirship recorded in the county deed records, or a probated will, is the minimum required to establish clear title on an inherited interest.

Fractional ownership. Mineral interests are frequently divided into small fractions — 1/8, 1/16, 1/32, or smaller — through generations of inheritance and conveyance. Verify that the fraction being sold matches the fraction the seller actually owns. A seller who believes they own 1/4 of the minerals may actually own 1/8 after a prior conveyance they are unaware of.

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. I have reviewed chains of title in Palo Pinto and Comanche Counties where a seller's stated ownership was reduced by 25% or more because of a reservation made by a prior owner decades earlier.

Existing liens and encumbrances. Search the county deed records for any deeds of trust, liens, or other encumbrances on the mineral interest. A mineral interest subject to a lien cannot be conveyed with clear title until the lien is released.

For most buyers, engaging a licensed Texas landman or oil and gas attorney to run title is money well spent. The cost of a title opinion is modest relative to the risk of acquiring a defective interest. For a detailed explanation of how mineral interests are conveyed and what deed language controls, see What Is a Deed Conveyance? A Guide for Mineral Interest Buyers.

What Lease Terms Should a Buyer Evaluate Before Closing?

If the mineral interest is currently under lease — meaning an operator has the right to drill and produce — the lease terms define your economic rights as the new mineral owner. You inherit the lease when you acquire the interest. You cannot renegotiate it until it expires.

Royalty fraction. This is the most important economic term in the lease. Verify the royalty fraction stated in the lease document and confirm it matches what the seller represented. 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 income at that rate for the duration of the lease, not at current market rates.

Post-production deduction language. Review the royalty clause for language governing whether the operator can deduct gathering, processing, transportation, and marketing costs from your royalty. "Free of cost," "at the wellhead," and "without deduction" are the phrases that protect the full royalty. Absent that language, Texas courts generally permit deductions. This is one of the most overlooked variables in mineral interest due diligence — and one I flag for every buyer I work with. For a detailed explanation of how deductions affect your monthly check, see How Royalty Payments Are Calculated.

Lease term and held-by-production status. An oil and gas lease has a primary term — typically three to five years in Texas — during which the operator must drill or the lease expires. After the primary term, the lease is held by production (HBP) as long as a well on the leased acreage continues to produce in paying quantities. Verify whether the lease is in its primary term or HBP, and whether current production is sufficient to hold the lease.

Shut-in royalty provisions. If a well is capable of production but the operator shuts it in, a shut-in royalty clause allows the operator to maintain the lease by paying a nominal shut-in royalty. Review whether the lease has this provision and what the shut-in royalty amount is.

Depth and formation limitations. Some leases cover all depths and formations; others are limited to specific formations or depth ranges. If the lease is formation-limited, the mineral owner retains the right to lease other formations separately — which may represent additional value not reflected in the asking price.

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 indefinitely, preventing you from leasing the remainder to a different operator at a higher royalty rate when the market improves.

How Do You Verify Production History Before Buying?

Production history is the most reliable indicator of what a mineral interest will generate going forward. Seller representations about production are not a substitute for verified data.

The Texas Railroad Commission (RRC) publishes production data for every permitted well in Texas. You can search by operator, lease name, or API number and download monthly production records. This data is public, free, and updated monthly. It is the authoritative source — always pull it directly rather than relying solely on what the seller provides.

Current production rate. What is the well producing today? This is your baseline for projecting future royalty income. Cross-reference the RRC data against the seller's reported income. 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.

Decline curve. How has production changed over time? Most oil and gas wells follow a predictable decline curve — high initial production that decreases at a declining rate over time. My science background from UT Arlington gives me a working understanding of reservoir mechanics that I apply directly when reviewing decline curves for buyers. 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. 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.

Shut-in periods. Has the well been shut in? If so, why and for how long? Extended shut-in periods may indicate mechanical problems, regulatory holds, or disputes. Every gap in the production record deserves an explanation before closing.

Multiple wells and undeveloped upside. Does the acreage have more than one producing well? Multiple wells multiply royalty income and reduce the risk that a single well failure eliminates revenue entirely. Potential future wells are speculative — a reasonable buyer pays a modest premium for credible undeveloped upside, not a full producing-well multiple.

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 pricing an acquisition.

How Do You Evaluate 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. A strong operator can extend the productive life of a well; a weak or financially distressed operator may defer maintenance, fail to recomplete declining wells, or abandon production entirely.

Financial condition. For publicly traded operators, review SEC filings — annual reports (Form 10-K) and quarterly reports (Form 10-Q) — to assess financial health, debt levels, and capital expenditure plans. Reserve disclosures in SEC filings are governed by Regulation S-X, Rule 4-10, which sets the standards for how operators must report proved reserves. A public operator with strong proved reserve disclosures and a funded capital program is a materially different risk than a small private operator with no disclosed financials.

RRC compliance record. The Texas Railroad Commission maintains a public compliance database showing violations, penalties, and enforcement actions by operator and by well. Check the compliance record for the subject well and for the operator's broader Texas operations before closing. In my experience evaluating Permian Basin acquisitions, operator compliance history is one of the most predictive indicators of how a well will be managed going forward.

Royalty payment history. Ask the seller for the last 12 months of royalty check stubs. Consistent, on-time payments indicate an operator who is managing the well and its revenue distribution correctly. Irregular payments, unexplained deductions, or gaps in payment history warrant investigation before closing.

How Is a Mineral Interest Priced?

Mineral interests do not have a published price list. Pricing is negotiated between buyer and seller based on verified production data, lease terms, and market conditions.

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.

The most important pricing discipline is this: base your valuation on verified production data, not on seller projections or representations about future drilling. Speculative acreage carries materially different risk than a producing interest with a documented income history, and the two should never be priced the same way.

What Post-Production Deductions Should a Buyer Verify?

Post-production deductions can significantly reduce the royalty you actually receive relative to the gross royalty fraction in the lease. Before acquiring an interest that is already producing, verify what deductions the operator is currently taking.

Request the most recent 12 months of royalty check stubs from the seller. Review the check stubs for deduction line items — gathering, processing, transportation, and marketing fees. Calculate the effective royalty rate: net payment divided by gross production value. Compare it to the lease royalty fraction. If the effective rate is materially lower than the lease fraction, the operator is taking deductions.

If the lease language does not clearly authorize those deductions, you may have a claim against the operator for underpayment. Consult a Texas oil and gas attorney before acquiring an interest with a deduction dispute — inheriting a disputed deduction situation is a liability, not a discount.

What Are the Tax Implications of Owning a Mineral Interest?

Mineral interest ownership has specific tax implications that affect your after-tax return. Understand them before you acquire.

Royalty income is ordinary income. Royalty payments are taxed as ordinary income at your marginal federal rate. There is no capital gains treatment for royalty income received during ownership.

Percentage depletion deduction. Individual mineral owners are entitled to deduct 15% of gross royalty income as a depletion allowance, subject to limitations. This deduction partially offsets the ordinary income tax on royalty payments. See IRS Publication 535 for the full rules governing percentage depletion for oil and gas.

Texas severance taxes. The Texas Comptroller administers a severance tax on oil production (4.6% of market value) and gas production (7.5% of market value). Operators deduct severance taxes from royalty payments before remitting them. Verify that the check stubs reflect severance tax deductions and that the rates are correct.

Ad valorem taxes. Mineral interests in Texas are subject to ad valorem (property) taxes assessed by the county appraisal district. The assessed value is based on the productive value of the interest. Verify the current assessed value and annual tax liability before acquiring — this is a recurring cost that affects net return.

1031 exchange eligibility. If you are selling a mineral interest and want to defer capital gains taxes, a 1031 like-kind exchange may allow you to reinvest the proceeds into a replacement mineral interest without recognizing gain at the time of sale. For a detailed explanation, see Understanding 1031 Exchanges for Mineral Interests.

Consult a CPA with oil and gas experience before making acquisition decisions based on after-tax return projections.

What Is a Realistic Exit Strategy for a Mineral Interest?

Every acquisition should include a thesis for how you will eventually sell. Mineral interests are illiquid relative to publicly traded securities — there is no exchange, no daily price, and no guaranteed buyer. But there is an active private market.

Private sale. The most common exit for mineral interests is a private sale to another buyer, a mineral aggregator, or an operator. Texas State Royalties and similar firms actively acquire producing mineral interests. The sale process typically takes 30 to 90 days from listing to closing.

1031 exchange. If you sell a mineral interest at a gain, a 1031 exchange allows you to defer the capital gains tax by reinvesting in a like-kind replacement property within the required timeframes. This is a common strategy for buyers who want to upgrade to a larger or higher-quality interest without triggering a tax event.

Estate planning. Mineral interests can be held indefinitely and passed to heirs. For long-term holders, the step-up in basis at death eliminates the capital gains tax on appreciation during the owner's lifetime — a significant estate planning benefit that is worth modeling before acquisition.

The Complete Due Diligence Checklist

Before committing to any mineral interest acquisition, verify each of the following:

Title

• Chain of title reviewed by a licensed landman or oil and gas attorney
• No gaps, missing deeds, or unresolved heirship issues
• Fractional ownership confirmed against deed language
• Prior reservations identified and quantified
• No liens or encumbrances on the interest

Lease

• Royalty fraction verified in the lease document
• Post-production deduction language reviewed
• Lease status confirmed (primary term vs. held by production)
• Shut-in royalty provisions noted
• Depth and formation limitations identified
• Pugh clause presence or absence noted

Production

• Production history pulled directly from the Texas RRC database
• Decline curve analyzed and projected forward
• No unexplained shut-in periods
• Multiple wells or undeveloped locations identified and valued separately

Operator

• Financial condition researched (SEC filings for public operators)
• RRC compliance record checked for subject well and operator
• Royalty payment history confirmed with 12 months of check stubs

Pricing

• Valuation based on verified RRC production data, not seller projections
• Conservative commodity price assumption used and stress-tested against EIA forecasts
• Undeveloped upside valued separately and conservatively

Deductions

• Last 12 months of check stubs reviewed
• Effective royalty rate calculated and compared to lease fraction
• No undisclosed deduction disputes

Taxes

• Severance tax deductions verified on check stubs (4.6% oil / 7.5% gas)
• Ad valorem tax liability confirmed with county appraisal district
• After-tax return modeled with CPA input, including 15% depletion deduction

Exit

• Exit thesis defined before acquisition
• Liquidity timeline realistic for the asset type
• 1031 exchange eligibility considered if selling an existing interest to fund the acquisition

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Key Takeaways

• Title review is not optional. Unestablished heirship, prior reservations, and fractional ownership errors are the most common title defects in Texas mineral interest acquisitions — and they are expensive to cure after closing.

• You inherit the lease when you acquire the interest. Review the royalty rate, post-production deduction provisions, held-by-production status, and Pugh clause before closing. You cannot renegotiate these terms until the lease expires.

• Always pull production data directly from the Texas Railroad Commission. Discrepancies between seller-provided summaries and RRC records are a red flag — and in my experience, they almost always favor the seller.

• Operator quality is a leading indicator of future production. For public operators, SEC filings under Regulation S-X, Rule 4-10 disclose proved reserves and capital plans. For private operators, the RRC compliance database is the best available proxy.

• Post-production deductions can materially reduce net royalty income below the lease royalty fraction. Calculate the effective royalty rate from actual check stubs before pricing the interest.

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

• Define your exit thesis before you acquire. Mineral interests are illiquid — the buyers who do best are those who understand the private sale market, 1031 exchange options, and estate planning implications before they close.

• Reserve classifications follow SEC Regulation S-X Rule 4-10; under Texas Property Code § 1.002, mineral interests are real property conveyed by deed; 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 mineral interest due diligence take? For a straightforward acquisition with a clean title and a single producing well, a thorough due diligence process typically takes two to four weeks. Transactions involving complex title — multiple heirs, estate issues, or a long chain of conveyances — can take significantly longer. Do not let a seller pressure you into closing before due diligence is complete. A title defect discovered after closing is far more expensive than a delayed closing.

Do I need a lawyer to buy a mineral interest in Texas? You are not legally required to use an attorney, but engaging a Texas oil and gas attorney to review title and the purchase agreement is strongly advisable for any significant acquisition. Title defects, lease interpretation disputes, and deed drafting errors are the most common sources of post-closing problems — all of which a qualified attorney can identify before closing. The cost of a title opinion is modest relative to the risk of acquiring a defective interest.

What is the most important thing to verify before buying a mineral interest? Title. A mineral interest is only as valuable as the seller's ability to convey clear, marketable title. Production history, lease terms, and operator quality all matter — but none of them matter if the seller does not actually own what they are selling. Title review comes first.

How do I know if a royalty rate is fair? Compare the royalty rate in the underlying lease to current market rates in the same basin. In Texas, current market rates for new leases in active plays range from 1/5 (20%) to 1/4 (25%) or higher in competitive areas. A legacy lease at 1/8 (12.5%) is below market — which means the mineral owner receives less income per unit of production than they would under a current-market lease. That below-market rate is a permanent feature of the interest until the lease expires, and it should be reflected in the purchase price.

What happens if the operator stops paying royalties? Under the Texas Natural Resources Code, operators are required to pay royalties within 120 days of first production and on a monthly basis thereafter. If an operator fails to pay, the mineral owner has a legal claim for unpaid royalties, interest, and attorney's fees under Texas law. Before acquiring an interest, review the payment history to confirm the operator has been paying consistently. An operator with a history of late or disputed payments is a risk factor that should affect your pricing.

Can I use a 1031 exchange to buy a mineral interest? Yes, if you are selling another real property interest and want to defer capital gains taxes, a 1031 like-kind exchange allows you to reinvest the proceeds into a replacement mineral interest without recognizing gain at the time of sale, provided you meet the identification and closing deadlines. Mineral interests qualify as like-kind real property under IRS rules. See Understanding 1031 Exchanges for Mineral Interests for a complete explanation of the process and requirements.

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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. Every interest we bring to buyers has been sourced, reviewed for production history, and structured for a clean deed conveyance. Learn more about how we work with buyers or review our acquisition services.

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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.