Key Terms in Oil and Gas Leases: A Buyer's Glossary

By Richard Partin, Managing Member, Texas State Royalties LLC Fort Worth, Texas | Published: October 2, 2026 | Last Updated: October 16, 2026

When you acquire a mineral interest in Texas, you are almost always acquiring an interest that is already subject to an oil and gas lease — or one that will be leased before production begins. The lease terms determine how much royalty you receive, how long the operator controls the mineral estate, and what deductions can be taken from your royalty before you receive it. In the Fort Worth Basin, Barnett Shale leases from the early 2000s — many held by production (HBP) at 1/8 to 3/16 royalty and lacking "free of cost" language — carry post-production deductions of $0.35–$0.60 per Mcf, reducing the effective royalty by 15–25%. Buyers who do not understand the lease terms before closing are acquiring an interest without knowing what it is actually worth.

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Quick Answer: An oil and gas lease is a contract between the mineral interest owner (lessor) and the operator (lessee) that grants the right to drill and produce in exchange for a royalty fraction and bonus payment. Key terms include the royalty clause, primary term, held-by-production clause, post-production cost provisions, and depth clause. Under Texas Natural Resources Code, the mineral estate is the dominant estate; the lease governs how production revenue is shared between the mineral owner and the operator.

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Why Do Lease Terms Matter to Mineral Interest Buyers?

When you acquire a mineral interest that is already under lease, you acquire it subject to that lease. You cannot renegotiate the royalty fraction, the post-production cost provisions, or any other lease term until the lease expires. The lease terms are fixed for the life of the lease — which, for a held-by-production lease, may be indefinite as long as production continues in paying quantities.

Understanding the lease terms before closing is not optional. The royalty fraction, the post-production cost provisions, and the depth clause directly determine the economic value of the interest you are acquiring. A 1/4 royalty lease on a Permian Basin well is worth significantly more than a 1/8 royalty lease on the same well. A lease with "free of cost" language protects the mineral owner from post-production deductions; a lease without it allows the operator to deduct gathering, compression, processing, and transportation costs before calculating the royalty.

Key Oil and Gas Lease Terms Defined

Lessor. The mineral interest owner who grants the lease — the party receiving the royalty and bonus payment.

Lessee. The operator or oil company who receives the right to drill and produce — the party paying the royalty and bonus.

Bonus payment. The upfront cash payment made by the lessee to the lessor at lease signing, typically expressed as a dollar amount per net mineral acre. The bonus is consideration for granting the lease and is taxable as ordinary income in the year received.

Primary term. The fixed period during which the lessee has the right to drill — typically one to five years in modern Texas leases. If the lessee does not drill and establish production during the primary term, the lease expires and the mineral estate reverts to the lessor.

Held by production (HBP). A lease that has survived its primary term because production in paying quantities was established before the primary term expired. An HBP lease continues indefinitely as long as production continues. Fort Worth Basin Barnett Shale leases from the early 2000s are predominantly HBP — buyers acquire these interests subject to lease terms that were negotiated 20+ years ago and cannot be renegotiated until production ceases.

Royalty clause. The provision specifying the fraction of gross production revenue payable to the lessor. Modern Texas leases typically specify 1/5 (20%), 3/16 (18.75%), or 1/4 (25%). Older Barnett Shale leases were often executed at 1/8 (12.5%) to 3/16 (18.75%). The royalty fraction is the single most important economic term in the lease for the mineral interest buyer.

Post-production costs. Costs incurred after the gas or oil leaves the wellhead — gathering, compression, processing, dehydration, and transportation to the point of sale. Whether these costs can be deducted from the royalty depends on the lease language. Leases with "at the wellhead" or "free of cost" language protect the mineral owner from post-production deductions. Leases without this language allow the operator to deduct these costs. In the Fort Worth Basin, Barnett Shale post-production deductions of $0.35–$0.60 per Mcf reduce the effective royalty by 15–25%.

Net revenue interest (NRI). The fraction of gross production revenue that flows to the working interest owner after all royalties and other burdens are paid. The NRI is calculated as: 1 minus the sum of all royalty fractions and overriding royalty interests burdening the lease. A lease with a 1/5 royalty and no ORRIs has an NRI of 4/5 (80%) for the working interest owner.

Overriding royalty interest (ORRI). A royalty interest carved out of the working interest — not the mineral estate. An ORRI is paid from the lessee's share of production and reduces the NRI. ORRIs expire when the lease terminates. ORRI vs. mineral interest confusion is the most common Fort Worth Basin due diligence mistake I encounter.

Depth clause. A provision limiting the lease to specific geological formations or depth intervals. A lease with a depth clause may cover only the Wolfcamp formation, leaving the Barnett or other formations available for separate leasing. Buyers should confirm whether the existing lease covers all productive formations beneath the tract.

Pugh clause. A provision that releases acreage not held by production at the end of the primary term. Without a Pugh clause, production on any part of the leased acreage holds the entire lease. With a Pugh clause, only the acreage actually producing is held; the rest reverts to the lessor.

Shut-in royalty. A payment made by the lessee to the lessor when a well capable of production is shut in (not producing) due to lack of a market or pipeline connection. Shut-in royalty provisions allow the lessee to maintain the lease during temporary shut-in periods without losing the HBP status.

Division order. A document executed by the mineral interest owner after closing that instructs the operator to pay royalties to the new owner at the specified decimal interest. The division order does not create or modify the lease — it is an administrative document that directs payment. Under Texas Natural Resources Code, the operator is obligated to pay royalties as specified in the lease once the division order is processed.

Severance tax. The Texas Comptroller imposes severance tax on production before the royalty reaches the mineral owner: 4.6% on oil and 7.5% on natural gas. Severance tax appears as a deduction on the royalty check statement. The Texas Railroad Commission (RRC) maintains production and well records for all Texas oil and gas wells; buyers should cross-reference production volumes on royalty statements against RRC records periodically.

Percentage depletion. A federal income tax deduction available to qualifying royalty interest owners under IRS Publication 535, equal to 15% of gross income from the property, subject to the limitation that the deduction cannot exceed 100% of net income from the property. Reserve classifications for producing properties follow SEC Regulation S-X Rule 4-10.

What Buyers Should Review in Every Lease Before Closing

Before closing on any mineral interest acquisition, buyers should review the full lease and confirm:

• The royalty fraction and whether it is calculated on gross production or net production after deductions
• Whether the lease contains "free of cost," "at the wellhead," or equivalent language protecting against post-production deductions
• The primary term and whether the lease is currently HBP
• The depth clause and whether it covers all productive formations
• Whether a Pugh clause exists and what acreage it releases
• The shut-in royalty provisions and whether any wells are currently shut in
• Any ORRIs burdening the lease and their effect on the NRI

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 to learn how we structure the process.

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Key Takeaways

• The royalty fraction in the lease is the single most important economic term for the mineral interest buyer; 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
• Post-production deductions — allowed by leases lacking "free of cost" or "at the wellhead" language — reduce the effective royalty by 15–25% in the Fort Worth Basin Barnett Shale ($0.35–$0.60/Mcf); buyers acquire the interest subject to the existing lease and cannot renegotiate until it expires
• HBP leases continue indefinitely as long as production continues; buyers of HBP interests in the Barnett Shale are acquiring interests subject to lease terms negotiated 20+ years ago
• ORRI vs. mineral interest confusion is the most common Fort Worth Basin due diligence mistake; an ORRI expires when the lease terminates and is not a mineral interest
• 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; the PV10 income approach is the standard framework for valuing producing mineral interests
• 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 Estates Code, mineral interests pass through probate at death unless held in a trust — unestablished heirship is the most common title defect in Comanche and Eastland County acquisitions; under Texas Property Code § 1.002, mineral interests are real property conveyed by deed

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Frequently Asked Questions

What is the difference between a royalty interest and a working interest?

A royalty interest is the mineral owner's share of gross production revenue — paid without deduction for operating costs. A working interest is the operator's share — subject to all operating costs, capital expenditures, and lease operating expenses. Royalty interest owners bear no operating costs; working interest owners bear all of them. Most mineral interest buyers acquire royalty interests, not working interests.

What does "held by production" mean and why does it matter to buyers?

A lease is held by production (HBP) when production in paying quantities was established during the primary term and continues. An HBP lease continues indefinitely as long as production continues — there is no expiration date. Buyers of HBP interests acquire the interest subject to the existing lease terms, which cannot be renegotiated until production ceases. In the Fort Worth Basin, most Barnett Shale leases are HBP at 1/8 to 3/16 royalty with unfavorable post-production cost provisions.

Can post-production deductions be challenged after closing?

Challenging post-production deductions after closing is difficult and expensive. The lease language controls. If the lease does not contain "free of cost" or "at the wellhead" language, the operator is generally entitled to deduct post-production costs under Texas law. Buyers should review the lease language before closing — not after — and price the acquisition accordingly.

What is the decimal interest and how is it calculated?

The decimal interest is the fraction of gross production revenue payable to the mineral owner, expressed as a decimal. It is calculated as: royalty fraction × (net mineral acres ÷ gross acres in the spacing unit). For example, a 1/5 royalty on 40 NMA in a 640-acre spacing unit yields a decimal interest of 0.20 × (40/640) = 0.0125. Decimal interest errors are common in estate proceedings — always verify the decimal interest independently from the deed chain and the division order before closing.

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For a complete guide to evaluating a mineral interest before you close, see: How to Evaluate a Mineral Interest Before You Buy.

For a guide to reading your royalty check statement after closing, see: How to Read a Royalty Check Statement.

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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.