By Brad Caponigro · Founder, Pointer Petroleum LLC · Reservoir engineer
Published
Royalty checks reward owners who actually read them. Consider a retired nurse in Canadian County, Oklahoma, who has been cashing royalty checks from the same SCOOP well for eight years. She never looked closely at the stubs until a nephew in petroleum accounting visited for Thanksgiving and laid three months of statements side by side on the kitchen table. Within twenty minutes he had flagged a post-production deduction that had quietly tripled, a severance tax line that looked wrong for her state, and a decimal interest that did not match her division order. She was owed money. She would not have known it without reading the paperwork.
A royalty statement (also called a check stub, revenue detail, or owner statement) is the document that accompanies your monthly royalty payment from the operator. It breaks down how your payment was calculated, showing the production volumes, product prices, deductions, and taxes that were applied before arriving at your net revenue.
Royalty statements can be confusing because every operator formats them differently, and the terminology varies from company to company. However, every statement contains the same core information: what was produced, what price it sold for, what was deducted, and what you are being paid. Understanding these components helps you verify that your payments are correct and gives you insight into the performance of the wells on your tract.
Illustrative stub — column names vary by operator, but the concepts are always in there somewhere.
Every operator uses different column headings — “residue gas,” “BTU-adjusted volume,” “POP,” “T&F,” “NGL take-in-kind” — but all five numbered quantities appear somewhere. If a statement hides one of them, ask for the corresponding detail report.
The production section of your statement shows the volume of oil, gas, and/or natural gas liquids (NGLs) that were produced and sold from the wells on your tract during the payment period. Oil is measured in barrels (BBL), natural gas in thousand cubic feet (MCF), and NGLs in gallons or barrels.
Important: Royalty payments are typically delayed by 2 to 3 months from the production date. So a payment received in April might cover production from January or February. The statement should show the production month so you can match it to the correct period.
The production volume shown on your statement is the gross volume from the well, not your share. Your share is calculated by multiplying the gross volume by your decimal interest (your royalty rate multiplied by your mineral interest fraction). This is why you may see a gross production line and a net production line on your statement.
The pricing section shows the price per unit at which each product was sold. Oil prices are shown per barrel, gas prices per MCF, and NGL prices per gallon or barrel. These are the realized prices — what the operator actually received from the purchaser — not the posted or index prices you see in the news.
Realized prices are typically lower than posted prices because of basis differentials (the difference between the local delivery point price and the benchmark price) and quality adjustments. The gross revenue is calculated by multiplying the production volume by the realized price for each product.
This is where royalty statements get complicated. Depending on your lease terms and state law, the operator may deduct various costs before calculating your royalty payment. Common deductions include:
Severance tax: A state tax on the value of production. The operator typically remits the tax and deducts the royalty owner's proportionate share on the check stub. Rates vary by state — Texas levies 4.6% on oil and 7.5% on natural gas, and North Dakota imposes both an extraction tax and a production tax that are similarly allocated to the royalty owner's share.
Gathering and transportation: Fees for moving the oil or gas from the wellhead to a sales point. Whether these can be deducted from your royalty depends on your lease language — some leases are "free of cost" and prohibit post-production deductions, while others allow proportional sharing of these costs.
Compression: Fees for compressing natural gas to pipeline pressure.
Processing: Fees for processing natural gas to remove NGLs and meet pipeline specifications.
The single most common question we hear from owners reviewing their first stub is not about price — it is "why does this month look so different from last month?" In our experience the answer is almost always one of three things: a one-time prior-period adjustment that finally cleared, a step-change in post-production deductions because the operator renegotiated a midstream contract, or a basis blowout in the regional gas market. None of those are necessarily wrong, but all three are worth asking about.
If you believe your deductions are excessive or unauthorized under your lease, consult a mineral rights attorney. Lease analysis is a specialized area, and the permissibility of deductions depends on the specific language of your lease and the case law in your state.
After subtracting deductions and taxes from gross revenue, the remaining amount is your net revenue — what you actually receive as a royalty payment. Your statement should show both the gross and net amounts so you can verify the calculation.
If you are evaluating whether to sell your mineral rights, your royalty statement is a key source of information. The production volumes show the performance of the wells on your tract, the realized prices show the effective commodity pricing, and the deductions show the operating cost burden. All of these factors feed into a mineral rights valuation.
Royalty payments are typically delayed by 2 to 3 months from the production date. This is because the operator needs time to receive payment from the purchaser, reconcile production volumes, calculate each owner's share, and process payments. The delay is standard industry practice and is specified in most mineral leases.
It depends on your lease. Some leases include "free of cost" or "at the wellhead" language that prohibits the operator from deducting post-production costs like gathering, transportation, and processing from your royalty. Other leases allow the operator to deduct a proportional share of these costs. Review your lease carefully or consult a mineral rights attorney if you are unsure.
First, review your statement carefully and compare the production volumes, prices, and deductions to prior months. If something looks significantly different, contact the operator's owner relations department for an explanation. Common issues include allocation changes, well downtime, and one-time adjustments. If you believe there is a systematic error, consult a mineral rights attorney who can review your lease and statements.
Codes vary widely between operators, but common abbreviations include BBL (barrel of oil), MCF (thousand cubic feet of gas), MMBTU (one million British thermal units), NGL (natural gas liquids), GROSS VOL (total well production), NET VOL (your share), DEC INT or OWNER INT (your decimal interest), SEV TAX (severance tax), GATH (gathering), COMP (compression), TRANS (transportation), PROC (processing), and PROD MO (production month). Most operators publish a stub legend on their owner-relations website; if yours does not, request one in writing.
Primary sources used in writing this article. These are not legal or tax advice — they are the public statutes, regulations, and authoritative materials the article draws from. Consult a qualified attorney or CPA before acting on any of them.
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