How to Read an Oil and Gas Lease Before Buying Mineral Rights

By Richard Partin, Managing Member, Texas State Royalties LLC Fort Worth, Texas | Published: October 17, 2026 | Last Updated: October 16, 2026

When you buy a producing mineral interest in Texas, you are not just buying the mineral estate — you are buying into an existing oil and gas lease. That lease governs how much royalty income you will receive, what deductions the operator can take, how long the lease remains in force, and what rights you retain as the mineral owner. Reading and understanding the lease before closing is one of the most important steps in mineral interest due diligence.

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Quick Answer: An oil and gas lease is the contract between the mineral owner and the operator that governs royalty rate, post-production deductions, lease term, and depth rights. Under Texas Natural Resources Code, the mineral estate is the dominant estate; the operator is obligated to pay royalties as specified in the lease. Fort Worth Basin Barnett Shale leases from the early 2000s at 1/8 to 3/16 royalty with post-production deductions of $0.35–$0.60/Mcf reduce effective royalty by 15–25% — buyers cannot renegotiate until the lease expires.

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Why Does the Lease Matter to a Buyer?

The mineral estate is the underlying asset — the perpetual right to the oil, gas, and other minerals beneath the land. But the lease is the operating agreement that determines how that asset performs financially.

Two mineral interests in the same basin, with the same production rate and the same operator, can generate very different royalty income depending on the lease terms. A 1/4 royalty with no post-production deductions is worth substantially more than a 1/8 royalty with transportation and processing deductions. A lease with favorable depth clauses protects the mineral owner's rights in formations not currently being developed. A lease with a strong continuous drilling clause prevents the operator from holding the acreage indefinitely without activity.

Buyers acquire the interest subject to the existing lease. The lease terms cannot be renegotiated until the lease expires. Understanding what you are buying before closing — not after — is the only way to price the acquisition correctly.

What Are the Key Provisions to Review?

Royalty fraction. The royalty fraction is the single most important economic term in the lease. It determines what percentage of gross production revenue flows to the mineral owner. Common fractions are 1/8 (12.5%), 3/16 (18.75%), 1/5 (20%), and 1/4 (25%). Fort Worth Basin Barnett Shale leases from the early 2000s are frequently at 1/8 to 3/16. Modern Permian Basin leases are more commonly at 1/4 or higher. The royalty fraction is fixed for the life of the lease.

Post-production cost provisions. Post-production costs — gathering, compression, processing, and transportation — are the costs incurred after the gas leaves the wellhead. Whether these costs can be deducted from the royalty depends on the lease language. Leases containing "free of cost," "at the wellhead," or equivalent language prohibit post-production deductions. Leases without this language generally allow deductions under Texas law. In the Fort Worth Basin, Barnett Shale post-production deductions of $0.35–$0.60 per Mcf reduce effective royalty by 15–25%. Confirm the post-production cost language before pricing any gas royalty acquisition.

Held-by-production (HBP) status. A lease that is held by production remains in force as long as the well continues to produce in paying quantities. There is no expiration date on an HBP lease — it continues indefinitely as long as production continues. If production ceases, the lease expires and the mineral interest reverts to non-producing status. Verify that the well is currently producing in paying quantities and that the HBP status is confirmed by Texas Railroad Commission (RRC) production records.

Primary term and savings clauses. A lease in its primary term has a fixed expiration date — typically three to five years from the effective date — unless production is established before that date. A savings clause (continuous drilling clause, shut-in royalty clause, force majeure clause) can extend the primary term under specific circumstances. Review the savings clauses carefully — a lease that appears to be in its primary term may be extended by a savings clause the seller has not disclosed.

Depth clauses. Depth clauses define which formations are covered by the lease. A lease covering "all depths" covers every formation beneath the surface. A lease with a depth limitation — "to the base of the Barnett Shale" — covers only the specified formation. Depth clauses matter when a tract has multiple productive formations at different depths. Confirm that the lease covers the formations currently being developed and any formations likely to be developed in the future.

Pugh clause. A Pugh clause (also called a "freestone rider" in Texas) releases acreage not held by production at the end of the primary term. Without a Pugh clause, a single producing well can hold the entire leased acreage indefinitely. A Pugh clause protects the mineral owner's ability to re-lease undeveloped acreage.

Shut-in royalty clause. A shut-in royalty clause allows the operator to maintain the lease by paying a nominal shut-in royalty when the well is capable of production but is not producing — typically because there is no market for the gas. Confirm the shut-in royalty amount and the conditions under which it can be invoked.

The Texas Comptroller imposes severance tax at 4.6% on oil and 7.5% on gas before the royalty reaches the mineral owner. Qualifying owners may deduct percentage depletion at 15% of gross income under IRS Publication 535. 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, they pass through probate at death unless held in a trust.

Texas State Royalties reviews lease terms as part of the acquisition facilitation process for every buyer we work with. Start Your Buyer Search or review our acquisition services.

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Key Takeaways

• The royalty fraction is the single most important economic term in the lease; Fort Worth Basin Barnett Shale leases from the early 2000s at 1/8 to 3/16 royalty are significantly less valuable than modern Permian Basin leases at 1/4 or higher — buyers cannot renegotiate until the lease expires
• Post-production deductions of $0.35–$0.60/Mcf in the Fort Worth Basin reduce effective royalty by 15–25%; leases containing "free of cost" or "at the wellhead" language prohibit these deductions — confirm the post-production cost language before pricing any gas royalty acquisition
• Verify HBP status against Texas Railroad Commission (RRC) production records; if production ceases, the lease expires and the interest reverts to non-producing status
• Review savings clauses (continuous drilling, shut-in royalty, force majeure) and depth clauses before closing — a lease that appears to be in its primary term may be extended by a savings clause, and depth limitations may exclude formations likely to be developed in the future
• The Texas Comptroller imposes severance tax at 4.6% on oil and 7.5% on gas; qualifying owners may deduct percentage depletion at 15% of gross income under IRS Publication 535; reserve classifications follow SEC Regulation S-X Rule 4-10
• Under Texas Natural Resources Code, the mineral estate is the dominant estate; the operator is obligated to pay royalties as specified in the lease once the division order is processed; under Texas Property Code § 1.002, mineral interests are real property
• 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 — a title opinion from a licensed Texas oil and gas attorney is required before closing

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Frequently Asked Questions

What is the difference between a gross royalty and a net royalty?

A gross royalty is calculated as a percentage of gross production revenue before any deductions. A net royalty is calculated after post-production deductions are taken. Whether your royalty is gross or net depends on the lease language. Leases with "free of cost" or "at the wellhead" language provide a gross royalty — the operator cannot deduct post-production costs. Leases without this language typically provide a net royalty in Texas, allowing the operator to deduct gathering, compression, processing, and transportation costs.

How do I know if a lease is held by production?

Cross-reference the lease effective date and primary term against Texas Railroad Commission (RRC) production records for the well. If the well has been producing continuously since before the primary term expired, the lease is HBP. If there are gaps in production — particularly gaps that exceed the shut-in royalty period — the HBP status may be questionable. A licensed Texas oil and gas attorney can confirm HBP status as part of the title opinion.

Can I renegotiate the lease terms after buying the mineral interest?

No. Buyers acquire the interest subject to the existing lease. The lease terms — royalty fraction, post-production cost provisions, depth clauses, and all other provisions — are fixed for the life of the lease. The only opportunity to negotiate new terms is when the lease expires and the mineral owner re-leases the acreage to a new operator.

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About the Author

Richard Partin is the Managing Member of Texas State Royalties, a Fort Worth-based, buyer-first firm that sources producing oil and gas mineral interests through established industry relationships. He holds a degree from the University of Texas at Arlington and has years of hands-on experience in oil and gas acreage interests, working interests, and capital formation across active Texas producing regions.

Texas State Royalties facilitates mineral-interest acquisitions and works exclusively with buyers. Information is for educational purposes only and is not legal, tax, or investment advice. Buyers should consult qualified legal, tax, and financial advisors before making any acquisition decision.