What Is a Producing Mineral Interest?

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

A producing mineral interest is a mineral interest with at least one active well generating royalty income. It is the most sought-after category of mineral interest because it generates immediate cash flow from the date of closing — no waiting for a lease, no waiting for a well to be drilled. Understanding what makes a producing interest valuable, and what risks to evaluate before closing, is essential for every buyer.

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Quick Answer: A producing mineral interest is a mineral interest with at least one active well generating royalty income. Under Texas Property Code § 1.002, it is real property conveyed by deed. Royalty income flows from the date of closing once the division order is processed. Producing Permian Basin interests trade at 40–60x monthly royalties; Fort Worth Basin Barnett Shale interests trade at 30–45x.

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What Makes a Mineral Interest "Producing"?

A mineral interest is producing when at least one well on the tract is actively generating oil or gas production and the mineral owner is receiving (or entitled to receive) royalty payments. The well must be producing in paying quantities — generating revenue sufficient to cover operating costs and provide a profit to the working interest owner.

A mineral interest subject to a held-by-production (HBP) lease is producing as long as the well continues to produce in paying quantities. If production ceases, the lease expires and the mineral interest reverts to non-producing status — available for re-leasing but generating no current income.

How Does Royalty Income Flow from a Producing Interest?

Royalty income flows through the following chain: gross production revenue × royalty fraction × (net mineral acres ÷ spacing unit acres) = decimal interest payment. The Texas Comptroller imposes severance tax at 4.6% on oil and 7.5% on gas before the royalty reaches the mineral owner. Post-production deductions — allowed by leases lacking "free of cost" language — further reduce the net royalty. In the Fort Worth Basin, Barnett Shale post-production deductions of $0.35–$0.60 per Mcf reduce effective royalty by 15–25%.

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.

What Should Buyers Evaluate Before Acquiring a Producing Interest?

Production history. Cross-reference the seller's production summary against Texas Railroad Commission (RRC) production records. Seller summaries often omit low-production months; discrepancies typically favor the seller. Wolfcamp/Barnett wells show 60–80% first-year decline; mature Barnett wells decline 5–10% annually.

Lease terms. Review the full lease. Confirm the royalty fraction, post-production cost provisions, and HBP status. Fort Worth Basin Barnett Shale leases from the early 2000s at 1/8 to 3/16 royalty with unfavorable post-production cost provisions are significantly less valuable than modern Permian Basin leases.

Title. Commission a title opinion from a licensed Texas oil and gas attorney. In Comanche, Eastland, and Palo Pinto Counties, prior reservations in deed chains routinely reduce stated ownership. Unestablished heirship under the Texas Estates Code is the most common title defect in those counties.

Pricing. Producing Permian Basin interests trade at 40–60x monthly royalties; Fort Worth Basin Barnett Shale interests trade at 30–45x. Producing Permian interests trade at 8–15x the value of non-producing interests in the same basin. Buyers apply 10–15% discount rates to Permian interests and 15–20%+ to Barnett Shale gas interests.

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Key Takeaways

• A producing mineral interest has at least one active well generating royalty income; it generates immediate cash flow from closing once the division order is processed
• Under Texas Property Code § 1.002, it is real property; under Texas Natural Resources Code, the operator is obligated to pay royalties as specified in the lease once the division order is processed
• Wolfcamp/Barnett wells show 60–80% first-year decline; mature Barnett wells decline 5–10% annually — model the decline curve before pricing
• 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; producing Permian interests trade at 40–60x monthly royalties; Barnett Shale interests trade at 30–45x
• In Comanche, Eastland, and Palo Pinto Counties, prior deed reservations routinely reduce stated ownership; unestablished heirship under the Texas Estates Code is the most common title defect
• 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%

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Frequently Asked Questions

What is the difference between a producing and non-producing mineral interest?

A producing mineral interest has at least one active well generating royalty income. A non-producing interest has no active well — it may be unleased, leased but undrilled, or subject to an expired lease. Producing interests command a significant premium: producing Permian interests trade at 8–15x the value of non-producing interests in the same basin.

How soon after closing will I receive royalty payments?

After closing and recording the deed, the buyer executes a division order and submits it to the operator. Operators typically take 60 to 90 days to update their records and begin directing payments. Royalties earned during the transition period are typically paid retroactively once the division order is processed.

What happens if the well stops producing after I close?

If production ceases, the HBP lease expires and the mineral interest reverts to non-producing status. The mineral owner retains the mineral estate and can re-lease it when a new operator is interested. The value of the interest drops significantly — from producing to non-producing pricing — but the ownership is not lost.

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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.