Oil and gas royalties are your share of the money from oil and gas produced under your mineral rights, paid without you covering the cost of drilling. Your lease or a state pooling order sets the share, and each payment equals your decimal interest times the volume sold times the price, less taxes and allowed deductions. Checks change as wells decline, prices move and deductions, title holds or new wells change what is paid.
What are oil and gas royalties?
Oil and gas royalties are the fraction of production that the owner of the mineral rights keeps when leasing to an operator. The operator pays to drill, complete and run the well, and your royalty does not share those costs: a 2015 Texas A&M AgriLife Extension ag law post states the general Texas rule that "neither royalty nor overriding royalties are subject to production costs."
Usually the royalty clause in the lease that you, or an earlier owner of the mineral rights, signed sets your share. If your mineral rights were never leased and the state pooled them into a drilling unit, the pooling order or statute sets it instead; our guide to pooling and unitization explains how that works state by state.
What is a typical royalty rate?
A typical royalty rate is a fraction between 1/8 and 1/4 of production, written into the lease of your mineral rights. The Kansas Geological Survey's petroleum primer says the royalty "is usually 1/8 (12 1/2%)" but may be any amount the parties agree to. Pennsylvania sets a floor by law: Penn State Extension notes that landowners there are entitled to at least 12.5% of all natural gas removed from the property.
Leases on mineral rights can carry higher fractions such as 3/16, 1/5 or 1/4, which are 0.1875, 0.20 and 0.25 as decimals. On the same well, a 1/4 royalty pays exactly twice what a 1/8 royalty pays, so the rate is one of the lease terms that most affects what your mineral rights are worth.
How are oil and gas royalties calculated?
Each line of a royalty payment follows one formula: your decimal interest × the volume sold × the price, minus your share of production taxes and any deductions the lease allows. Your decimal comes from the net mineral acres you own in the unit, the unit's total acres and your royalty rate. It turns the whole well's revenue into the share your mineral rights earn.
Worked example with illustrative numbers
- Your decimal interest: 0.005
- Gas sold from the well in one month: 20,000 Mcf
- Example price: $3.00 per Mcf (an illustration, not a current market price)
- Gross value of the well's gas: 20,000 × $3.00 = $60,000
- Your share before taxes and deductions: $60,000 × 0.005 = $300
- Less example taxes of $20 and deductions of $30: $300 − $50 = $250 net
Our oil and gas royalty calculator runs the same steps with your own numbers, and our guide on how to read a royalty check matches them to a real stub.
What can be deducted from oil and gas royalties?
Production costs cannot come off oil and gas royalties, but post-production costs often can, unless the lease says otherwise. The same AgriLife post says royalty owners "are typically subject to paying their share of post-production costs, including taxes, treatment, and transportation costs": the cost of getting oil or gas from the well to a commercial market.
The wording of the royalty clause decides how much comes off. Under Texas case law, a royalty on "market value at the well" means market value less those post-production costs. In the Hyder case, the Texas Supreme Court read a gas royalty "free and clear of all production and post-production costs and expenses" as payable on the price actually received, with no deductions. Courts in other states read similar words differently. If deductions eat a large share of the income from your mineral rights, have an oil and gas attorney compare your lease with your stubs.
When are oil and gas royalties paid?
Oil and gas royalties are paid in arrears, usually monthly, and state law sets the outer deadlines. In Texas, Natural Resources Code §91.402 requires the first payment within 120 days after the end of the month of first sale, then payment on the lease schedule or, if the lease is silent, within 60 days after the month oil is sold and 90 days after the month gas is sold.
In Oklahoma, the Corporation Commission's royalty owner booklet (2022) says the Production Revenue Standards Act calls for first payment within six months of the date of first sale, with interest due if it is late. A new well on your mineral rights can produce for months before your first check arrives.
Why is my royalty check going down?
Your royalty check usually goes down because the well is producing less, the price fell or more was deducted; less often, part of your interest is on hold. New shale wells start at their highest rate and fall fast: the U.S. Energy Information Administration reported in 2014 that first-year decline rates in the Eagle Ford had ranged between 60% and 70%, and second-year declines had risen from 30% for wells drilled in 2009 to nearly 50% for wells drilled in 2011 and 2012. A check that drops by half or more in a well's first year can be normal for new wells on your mineral rights.
| Cause | What you'll see on the stub | What to do |
|---|---|---|
| Production decline | Volume falls month after month; price and decimal stay the same | Expected on newer wells; track the trend over 6 to 12 months |
| Lower price | Similar volume, lower price per barrel or Mcf | Compare the price with your other wells for the same month |
| Higher deductions | New or larger gathering, processing or transport lines | Read the royalty clause; ask the payor what each charge covers |
| Suspended interest | A well or month missing, or no check at all | Ask owner relations what is in suspense and what releases it |
| New wells or a new unit | New well names, or a new decimal if a unit was formed or redrawn | Ask for the new division order and check the math |
New wells usually add to oil and gas royalties rather than cut them. The Oklahoma Corporation Commission's 2022 booklet says an operator needs an increased density order to drill more wells in a spacing unit, so that filing is a sign more production may be coming to your mineral rights.
What happens to oil and gas royalties when you inherit mineral rights?
When you inherit mineral rights, the oil and gas royalties keep accruing, but the payor can hold them in suspense until it sees proof the interest is now yours. Expect to send recorded documents such as a probated will or an affidavit of heirship before you get a division order in your name.
Unclaimed money can drift away. The Oklahoma Corporation Commission's 2022 booklet says royalties owed to owners listed as unlocatable in a pooling order go to its Mineral Owner Escrow Account and then to the State Treasurer's unclaimed property office. Royalties from inherited mineral rights are taxable income; our guide to taxes on royalty income covers reporting, and a CPA can apply it to your return. If several heirs now share small decimals, see our page on selling inherited mineral rights.
Can you sell oil and gas royalties for a lump sum?
Yes. You can sell some or all of your oil and gas royalties for one cash payment, and the buyer takes on the future checks and the risk that they shrink. Buyers price producing mineral rights from recent net income, decline and the chance of more wells, so have six to twelve months of stubs ready.
Run your numbers through our mineral rights value calculator for a rough range, and see what buyers look for when you sell oil and gas royalties. Oklahoma owners can also read about selling Oklahoma mineral rights. When you're ready, get free cash offers on your mineral rights from up to three independent buyers active in your county, with no fees, no commissions and no obligation.
This guide is general information, not legal or tax advice. Your lease, any pooling order and state law control how royalties on your mineral rights are paid.