If you asked a room full of mineral owners whether they thought their royalty checks were accurate, most would say yes — because the checks arrive on time, the amounts vary in ways that roughly track the news about gas prices, and no one has flagged a problem. That confidence is mostly unearned. Royalty underpayment is one of the most widespread and least-prosecuted financial abuses in the oil and gas industry, and it survives because auditing your own royalties is work most owners don't know how to do.
These are the most common methods — and the checks that expose them.
1. Post-production deductions your lease doesn't allow
Post-production costs — gathering, compression, processing, and transportation — are real costs. The question is who bears them: the operator or the royalty owner. That question is answered by your lease, and the answer varies enormously. "Market value at the wellhead" language typically allows deductions; "gross proceeds" or "free of cost" language typically doesn't. Many operators apply deductions to everyone's royalties as a default, regardless of what individual leases say, because most owners never check. In Pennsylvania especially, where the Guaranteed Minimum Royalty Act is often read by operators as permitting deductions unless a lease explicitly forbids them, this is a systematic problem.
2. Wrong decimal interest
Your division order decimal is derived from your net acres, the unit acreage, and your royalty rate. Any error in those inputs compounds into every check for the life of the well. The calculation is straightforward; the errors are common. We've seen decimals that were wrong because unit boundaries shifted during drilling, because a fractional heir's interest was miscalculated during probate, or simply because someone transposed digits in a data entry step. A wrong decimal is often invisible on a single statement but obvious when you do the arithmetic yourself.
3. Missing or understated NGL royalties
Wet-gas wells — common in southwestern Pennsylvania, the West Virginia panhandle, and the Ohio border region — produce natural gas liquids (propane, butane, ethane, pentane) that are separated at a processing plant and sold independently. NGL prices and volumes should appear as separate line items on your royalty statement. If you're on a wet-gas well and see only a single "GAS" line on your check, ask why. Improperly accounting for NGLs can cut effective royalties by 20–40% on a wet-gas well. It's one of the most financially significant audit targets we pursue for owners in Washington and Greene counties.
4. Royalties held in suspense — and not released
When an operator has a question about title — an estate that hasn't fully probated, a disputed interest, an address they can't locate — they're permitted to hold royalties in suspense rather than pay them out. This is legal. What's not legal is holding them indefinitely without notice, or failing to release them once the title question is resolved. Suspense balances often sit for years and are never proactively disclosed.
If you've inherited mineral rights, recently bought land, or changed your name or address, check with the operator directly whether you have a suspense balance. Pennsylvania and West Virginia both have unclaimed property laws that require operators to eventually escheats these funds to the state — but "eventually" can mean a decade.
5. Production volumes that don't match state records
Operators report production volumes to state regulators — Pennsylvania's DEP and West Virginia's DEP maintain publicly searchable well production databases. If the volumes on your royalty statements don't align with the production data reported to the state for the same wells, that's a red flag. Small discrepancies can reflect timing differences (calendar month vs. production month); large or persistent gaps deserve a written explanation from the operator.
6. Old leases with 12.5% royalties on modern wells
This isn't fraud, but it's a form of systematic underpayment relative to market. A lease signed in 1990 at a standard 1/8 (12.5%) royalty rate, if it's still alive through held-by-production on a marginal old well, may be controlling a new horizontal Marcellus well drilled nearby. That means you're receiving 12.5% on a modern well when comparable new leases in your county are getting 18–20%. Whether that lease can be challenged depends on the specifics — but it's always worth examining whether the HBP claim is legitimate before accepting it as permanent.
How a royalty audit works
We start with your lease, your division order, and twelve to thirty-six months of statements. We verify the decimal, check which deductions your lease permits, confirm NGL lines against well type, and compare volumes to state production data. If we find underpayment, we quantify the discrepancy and pursue a correction — through direct operator negotiation in most cases, through legal process if necessary. Our fee comes from what we recover; there's no cost if we find nothing. Most audits take two to four weeks.
If you've never had your royalties audited, and your well has been producing for more than two years, the audit almost certainly pays. Contact us to get started, or call us directly. And if an operator sends you a "royalty reconciliation" or asks you to sign a release of back-payment claims — call us before you sign anything.
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