Texas Mineral Rights Royalties: What You Should Be Getting Paid (and How to Check)

If you own mineral rights in Texas and those rights are covered by an oil and gas lease, you should be receiving royalty payments whenever oil or gas is produced from wells on your property. But many mineral rights owners in Texas receive far less than they should — or nothing at all — because they don’t understand how royalties work or how to verify their payments are correct.

How Texas Mineral Rights Royalties Work

When an oil and gas company leases your mineral rights, the lease agreement sets out a royalty rate — typically expressed as a fraction such as 1/8 (12.5%), 3/16 (18.75%), 1/5 (20%), or 1/4 (25%). This fraction represents the portion of oil or gas production value that flows to you as the mineral rights owner, before operating costs are deducted.

For example: if a well on your property produces 100 barrels of oil per day at $75/barrel, and your royalty rate is 1/5 (20%), you would receive approximately $1,500 per day in royalties — or roughly $45,000 per month from that single well, minus any applicable taxes and deductions.

What Is a Good Royalty Rate for Texas Mineral Rights?

Royalty rates have generally increased over the past two decades as mineral rights owners have become more sophisticated and competition for leases has intensified. Here’s what to expect in today’s market:

• 1/8 (12.5%): The historical “standard” rate, but now considered low. If you have a lease with this rate and it’s up for renewal, you should negotiate for more.
• 3/16 (18.75%): A common middle-ground rate in many Texas markets.
• 1/5 (20%) or 1/4 (25%): Rates achievable in high-demand areas, particularly the Permian Basin, where operators compete aggressively for acreage.
• Above 25%: Possible in the most prized acreage positions, though less common.

If your current lease has a 1/8 royalty rate and your minerals are in an active area, you’re likely leaving significant money on the table. When your lease expires, negotiate for a higher rate before signing a new one.

Common Problems With Royalty Payments

Royalty underpayment is one of the most widespread issues in the Texas oil and gas industry. Studies have found that a significant percentage of royalty owners receive incorrect payments. Here are the most common issues to watch for:

1. Improper Post-Production Cost Deductions

Texas law and most lease agreements limit the deductions operators can take from royalty payments. “Post-production costs” include costs for gathering, transportation, compression, processing, and marketing the gas or oil after it leaves the wellhead. Depending on your lease language, some or all of these costs may not be deductible from your royalty. Many operators deduct costs they shouldn’t — review your lease carefully or consult an attorney if you see unusual deductions on your royalty statements.

2. Errors in Production Allocation

When a well covers multiple leases or tracts, production must be allocated among the mineral rights owners based on their percentage interest. Errors in these calculations — sometimes significant — can result in underpayment to some owners. If you own a fractional mineral interest, make sure the decimal interest on your division order matches what your deed says you own.

3. Late Payments

Texas law (specifically the Texas Natural Resources Code) requires operators to pay royalties within 120 days of first production, and subsequently within 60 days after the end of each month in which production is sold. If you’re not receiving payments within these timeframes, you may be entitled to interest on the late payments at a rate of 18% per year.

4. Failure to Pay on Bonus and Delay Rentals

Beyond royalties, your lease should include an upfront bonus payment and, in some leases, delay rental payments during the primary term before production begins. Make sure all lease payments are received as agreed.

How to Check If Your Royalty Payments Are Correct

1. Request Your Division Order

A division order is a document the operator sends you that specifies the exact decimal interest you’re being paid on. This decimal should be consistent with your deed. For example, if you own 50 net mineral acres in a 640-acre unit with a 20% royalty rate, your decimal interest should be: (50/640) × 0.20 = 0.015625. Ask for a copy if you haven’t received one.

2. Review Your Royalty Statements

Royalty statements should show the well name, production volumes, price received, any deductions, and the resulting payment to you. Compare the price received to public market prices for that month — large discrepancies can indicate improper pricing or marketing arrangements.

3. Consult a Royalty Audit Specialist

If you receive significant royalty income, a professional royalty audit can identify underpayments. Many audit firms work on a contingency basis — they only get paid if they find and recover underpayments for you.

How Royalty Income Affects the Value of Your Mineral Rights

Your monthly royalty income is a direct input into the value of your mineral rights if you decide to sell. Mineral rights buyers typically value producing rights at a multiple of the monthly royalty income — often 36 to 60 times the monthly check, depending on the production decline curve and market conditions.

This means a mineral owner receiving $2,000 per month in royalties might expect an offer of $72,000 to $120,000 for those rights. If your royalty payments are being underpaid, your minerals may also be undervalued by buyers who rely on those payments as a baseline.

Use our free Texas Mineral Rights Calculator to see how your royalty income translates to an estimated market value for your position. You can input your monthly royalty, county, and acreage to get a customized estimate in minutes.