Royalty Deductions Explained: Why Your Check Is Smaller Than You Expected

Gathering, Compression, Processing, Transportation, Severance Tax — Which Are Proper, Which Aren't, and How to Tell

Quick answer: Royalty checks run below volume × price × decimal for two reasons: severance taxes, which every state levies and every owner bears, and post-production deductions — gathering, compression, dehydration, processing, transportation, marketing — which are chargeable to a royalty owner only when the lease allows them. A cost-free royalty clause can prohibit them; the lease language, not the operator's habit, controls.

"Why is my check smaller than it should be?" is the most common question royalty owners ask — and the answer almost always lives in the deduction column of the check stub. This guide walks through every common deduction family, which ones are properly charged to a royalty interest, and the audit steps that catch the improper ones. To see where deductions sit on an actual stub, click through the interactive check stub decoder.

The Two Kinds of Reductions — Only One Is Negotiable

Severance taxes are a state tax on production. The operator withholds your share and remits it; rates vary by state and product (Texas: 4.6% oil, 7.5% gas), and some wells qualify for reduced-rate incentives — see the severance tax rates by state for the full table. No lease clause makes severance tax go away — but the rate applied should match your state and the well's status.

Post-production deductions are different: they are the operator's costs of moving and improving the product between the wellhead and the sale point, shared out to interest owners. Whether your royalty bears them is a contract question — decided by the royalty clause in your lease, and litigated in every producing state. That is why two neighbors with identical wells can see very different deduction lines.

The Deduction Families, Decoded
Deduction What it is Chargeable to a royalty owner? Red flag
Gathering Moving gas from the wellhead into a pipeline system Lease-dependent Charged on a cost-free royalty
Compression Pressurizing gas to enter or move through a pipeline Lease-dependent Rates creeping up on the same well over time
Dehydration Removing water so gas meets pipeline specs Lease-dependent Duplicated inside a bundled processing fee
Processing Separating natural gas liquids (NGLs) from the gas stream Lease-dependent Processing charged but NGL revenue never appears on your stub
Transportation Moving oil or gas from the lease to the sale point Lease-dependent Far above rates on comparable wells nearby
Marketing Fees for arranging the sale, often to an operator affiliate Lease-dependent — most disputed Paid to the operator's own affiliate at above-market rates
Severance tax State tax on production, withheld by the operator Yes — always Rate doesn't match your state/product, or no incentive rate on a qualifying well
What Your Lease Actually Says

The battleground is the royalty clause's valuation point. Leases that pay royalty on value "at the well" generally permit netting post-production costs, because the product is valued before those costs were incurred. Leases that pay "at the point of sale" or carry an express cost-free royalty / no-deductions clause point the other way. Courts read this language closely — and similar-sounding clauses have produced different outcomes state by state — so the practical rule for an owner is simple: find your royalty clause, read it against the deduction column, and treat any mismatch as an open question for the operator. What you should never do is assume the deductions are right because they've always been there.

Why Gas Checks Carry Heavier Deductions Than Oil

Gas must be gathered, compressed, dehydrated, and often processed before it can be sold — each step a potential deduction. Oil frequently moves by truck or short pipeline with fewer intermediate charges. That is why a mixed oil-and-gas stub commonly shows modest deductions on the oil line and much heavier ones on the gas line — a pattern, not necessarily a problem. The problem patterns are the ones in the table above.

How to Audit Your Deductions in Four Steps
  1. Map every deduction code. List each code on the stub (GATH, COMP, DEHY, PROC, TRAN, MKT) and ask the operator for definitions of anything vague like "OTH."
  2. Read your lease's royalty clause. Find the valuation point ("at the well" vs. "at the point of sale") and any cost-free or no-deductions language. The lease — not the operator's habit — controls what is chargeable to you.
  3. Trend the percentages. Compute deductions as a percentage of your gross for each month and each well. Creeping percentages, sudden jumps, or rates far above comparable wells are the classic signals.
  4. Raise it and recover. Document the discrepancy — stub, lease clause, math — and submit a written inquiry to the operator's owner relations. Improper deductions are recoverable, often with statutory interest.
Want every deduction on every check audited — automatically? Valor's royalty management team audits deductions against your actual lease language across every operator, every month, and pursues the recoveries. Valor never buys minerals — audit and administration only. Have Valor audit your royalty checks →

Royalty Deductions FAQ

Two reasons. First, severance taxes: every producing state levies a tax on production, the operator withholds it, and every owner bears their share. Second, post-production deductions: costs of moving and improving the product between the wellhead and the sale point — gathering, compression, dehydration, processing, transportation, marketing. Whether those can be charged to YOUR royalty depends entirely on your lease language.

The costs incurred after the well produces but before the product is sold: gathering (moving gas from the wellhead into a pipeline system), compression (pressurizing it for the pipeline), dehydration (removing water), processing (separating natural gas liquids), transportation (moving product to the sale point), and marketing fees. Gas typically carries more of these than oil because gas requires more midstream handling before sale.

Generally no — that is exactly what a cost-free or no-deductions clause is for. But the details matter: courts read royalty clauses closely, 'at the well' valuation language can cut the other way, and similar-sounding clauses have produced different outcomes in different states. If deductions appear on a lease you negotiated to be cost-free, that line item deserves a written inquiry, not a shrug.

There is no universal number — it varies by product, basin, midstream contracts, and lease terms, and gas runs meaningfully heavier than oil. The audit signal isn't a magic percentage; it's the pattern: deductions creeping up over time on the same well, a sudden jump with no explanation, rates far above comparable wells, or any deduction at all on a cost-free royalty.

Document the discrepancy — the stub lines, the lease clause, and your math — and submit a written inquiry to the operator's owner-relations department. Operators correct verified errors and pay the accrued difference, and several states add statutory interest on late or wrongly withheld royalties. Professional royalty auditing does this systematically across every operator and every month, which is how multi-year recoveries get found.

Key Takeaways