#Payment Errors Are More Common Than You Think
If you own mineral rights or hold a non-operated working interest, there is a reasonable chance that at least one of your royalty payments contains an error right now. The revenue chain is long — production is measured at the wellhead, processed through facilities, sold to purchasers, allocated across interest owners, and disbursed as a check or ACH deposit. At every step, data moves between different systems, companies, and units of measurement.
Some errors are simple data entry mistakes — a transposed digit, a miskeyed volume, a pricing figure from the wrong column. Others are systemic: a flawed allocation model, a BTU factor never updated after a composition change, or a pricing index that does not match the point of sale. Unless you actively audit your statements, these errors compound month after month.
This article covers the most common operator payment errors, focusing on the two costliest areas: production volume discrepancies and unit conversion mistakes.
#Volume Discrepancies: When Production Numbers Do Not Match
The most straightforward audit check is comparing your statement volumes against state regulatory filings. In Texas, operators report monthly production to the Railroad Commission of Texas (RRC). In Oklahoma, filings go to the Oklahoma Corporation Commission (OCC). These are public record and searchable online by API number or operator name.
When your statement volumes do not match, something has gone wrong. Here are the most common causes.
#Allocation Errors in Commingled Production
When multiple wells produce into a shared gathering system or central tank battery, the operator must allocate total production back to individual wells. Allocation is typically based on well tests or continuous metering at each wellsite. If a well test is outdated or a meter is malfunctioning, the allocation percentages will be wrong — some wells get credited with too much production while others receive too little.
#Metering Errors
Accurate production measurement depends on properly calibrated equipment. The API publishes standards for orifice meter calibration (API MPMS Chapter 14) and liquid measurement (API MPMS Chapter 5), and most state commissions require operators to calibrate meters on a regular schedule. A meter that drifts out of calibration can systematically undercount or overcount production for months. If your volumes suddenly drop without a corresponding operational event, a metering issue is worth investigating.
#Gas Flaring and Venting
Operators sometimes flare or vent gas that cannot be captured — during well completions, equipment failures, or when pipeline capacity is unavailable. Flared volumes are reported to state commissions but should not appear as sales volumes on your statement. The error arises in the other direction: when an operator reports zero gas production for a period during which some gas was actually captured and sold alongside the flared volumes. If state records show gas production but your statement shows none, the operator may have incorrectly classified all gas as flared when a portion was marketed.
#Net vs. Gross Production Confusion
State commission reports typically show gross wellhead production. Your royalty statement may show net production — volumes after shrinkage, processing losses, or BS&W (basic sediment and water) deductions. For gas, shrinkage occurs when NGLs and impurities are removed at a processing plant. It is normal for statement volumes to be lower than commission volumes. The error occurs when an operator applies net volumes but prices them as gross, or when the shrinkage factor is incorrect.
#Unit Conversion Mistakes: The Most Expensive Errors in Gas Accounting
If volume discrepancies are the most common errors, unit conversion mistakes are the most costly per occurrence. The problem: natural gas is measured in one unit, priced in another, and the conversion depends on a physical property — heating value — that varies from well to well and month to month.
#MCF vs. MMBTU: Understanding the Difference
Natural gas production is measured in MCF — thousand cubic feet (the "M" is the Roman numeral for one thousand). At the wellhead, meters measure the physical volume of gas flowing through the pipe.
But gas is sold by energy content, measured in British thermal units (BTU). The standard pricing unit is MMBTU — one million BTU. A buyer purchasing gas to fuel a power plant cares about the energy delivered, not the volume. The conversion between MCF and MMBTU depends on the BTU content per cubic foot, determined by the gas stream's chemical composition.
#The BTU Factor
The BTU factor (also called the heating value or energy content) is expressed as BTU per cubic foot. It varies based on the composition of the gas:
- Dry gas (predominantly methane) has a heating value of approximately 1,020 BTU per cubic foot.
- Wet gas (containing heavier hydrocarbons like ethane, propane, and butane) can range from 1,100 to 1,400 BTU per cubic foot or higher, depending on the richness of the gas stream.
The conversion formula is:
MCF x BTU factor / 1,000 = MMBTU
For example, if a well produces 10,000 MCF of gas with a heating value of 1,200 BTU per cubic foot:
10,000 MCF x 1,200 / 1,000 = 12,000 MMBTU
If that same gas were incorrectly assigned a BTU factor of 1,000 (essentially treating it as pipeline-quality dry gas when it is actually rich wet gas):
10,000 MCF x 1,000 / 1,000 = 10,000 MMBTU
At a gas price of $3.00 per MMBTU, that single error produces a gross revenue difference of $6,000 for one month on one well. Applied to the royalty owner's fractional interest over many months, the cumulative underpayment is substantial.
This is one of the most common unit conversion errors: applying a default or outdated BTU factor instead of the actual heating value. The correct BTU factor should come from periodic gas chromatograph reports that the operator or gas purchaser performs on the stream.
#Oil Measurement: Stock Tank Barrels vs. Sales Barrels
Oil is measured in barrels (one barrel equals 42 US gallons), but not all barrels are the same. Stock tank barrels reflect the volume in the lease tank, including basic sediment and water (BS&W). Sales barrels are the net volume after BS&W deduction — typically 1% to 3% for clean crude, but potentially much higher for wells with water issues. Errors arise when an operator reports stock tank barrels to the state but pays on sales barrels without disclosing the BS&W deduction, or when an incorrect BS&W percentage is applied.
#NGL Measurement and Plant Allocation
Natural gas liquids extracted at a processing plant — ethane, propane, butane, and natural gasoline — are measured in gallons per MCF (GPM). The GPM yield depends on inlet gas richness and plant efficiency. Revenue from NGL sales should be allocated back to the wells that supplied raw gas in proportion to each well's contribution. Errors occur when the plant's allocation model is flawed, when GPM yields are not updated for gas composition changes, or when NGL revenue is simply omitted from the statement.
#Condensate vs. Oil Classification
Condensate is a light hydrocarbon liquid that condenses from the gas stream at the surface, typically with an API gravity above 50 degrees. It is often priced differently from crude oil. Some operators classify condensate as oil for payment purposes, applying the wrong pricing benchmark. Condensate may trade at a premium or discount to crude depending on market conditions, so misclassification directly affects your payment.
#Pricing Errors: Using the Wrong Benchmark
Even when volumes and conversions are correct, pricing can be wrong. There is no single "price of oil" or "price of gas" — there are dozens of regional benchmarks reflecting local supply, demand, and transportation dynamics.
#Posted Price vs. Actual Sales Price
Historically, operators paid royalties based on a "posted price" published by major purchasers. Many modern leases require payment based on the actual price received ("proceeds" or "amount realized"). Posted prices can lag the NYMEX settlement by several days, and during volatile periods the gap can be significant. If your lease entitles you to proceeds-based pricing and your operator is paying on posted prices, you may be underpaid.
#Oil Pricing: WTI Cushing vs. WTI Midland
WTI (West Texas Intermediate) is the most widely quoted US crude benchmark, settled at Cushing, Oklahoma. But Permian Basin production is priced at WTI Midland, which trades at a basis differential to Cushing — ranging from a discount of several dollars per barrel (when pipeline capacity is tight) to near parity. An operator using Cushing pricing for a Midland-priced well introduces an error on every barrel sold.
#Gas Pricing: Henry Hub vs. Regional Hubs
Henry Hub in Erath, Louisiana is the national gas benchmark and NYMEX delivery point. But wellhead gas is sold at regional hubs that can trade at significant premiums or discounts. Waha Hub in West Texas, for example, has historically traded at a substantial discount to Henry Hub due to pipeline constraints and abundant associated gas — at times even going negative. If your operator applies Henry Hub pricing to gas sold at Waha, you may be overpaid, but the reverse error — applying a depressed regional index when gas was sold downstream — is an underpayment.
#Gravity Adjustments for Crude Oil
Crude oil pricing is adjusted based on API gravity — a measure of how light or heavy the oil is. Lighter crude (higher API gravity, typically 38 to 45 degrees) generally commands a premium because it yields more valuable refined products; heavier crude is discounted. These adjustments should correspond to the actual gravity of your well's crude, not a default or field-wide average.
#Timing and Allocation Errors
#Prior-Period Adjustments
Operators routinely make prior-period adjustments (PPAs) to correct previous months' errors. These are legitimate, but should be transparently disclosed with a clear explanation of which production month is being corrected and why. Opaque or unexplained PPAs that reduce your current payment deserve scrutiny.
#Missing Plant Product Revenue
If your well produces gas processed at a plant, you should receive revenue from both residue gas and extracted NGLs. Some operators fail to allocate plant product revenue back to the royalty owner. If your statement shows gas revenue but no NGL revenue on a well producing wet gas, ask the operator for the plant statement.
#How to Catch These Errors
You do not need specialized software to begin auditing, though systematic tools make the process far more efficient at scale. Here are four practical steps any royalty owner can take.
Cross-reference production volumes with state commission data. The Texas RRC, Oklahoma OCC, and New Mexico OCD all offer free online queries. Search by API number and compare reported volumes against your statement.
Track pricing against published indices. Use the EIA website for monthly average WTI and Henry Hub prices. Platts and Argus publish more granular regional pricing for basin-specific benchmarks. Compare these to your check stub.
Request the operator's gas analysis report. If you suspect a BTU factor error, ask for the most recent gas chromatograph report on your well's stream. It will show the actual heating value that should be used in the MCF-to-MMBTU conversion.
Compare your check stub month over month. Sudden, unexplained changes in volume, price, or deductions are red flags. Production declines gradually on most wells; a sharp drop without a corresponding operational event warrants investigation.
#Related Reading
- Royalty Underpayment Detection Guide
- A 5-Point Manual Reconciliation Checklist
- Production Volume Verification
#Stop Leaving Money on the Table
Payment errors in oil and gas are not the exception — they are a structural feature of an industry built on complex measurement, multi-party transactions, and legacy accounting systems. Operators are not necessarily acting in bad faith; they manage enormous data volumes across thousands of revenue interests, and mistakes are inevitable.
The question is whether those mistakes are caught or whether they quietly reduce your income for years. Manual auditing works, but it does not scale. When you own interests in multiple wells across multiple operators, the only practical approach is automated reconciliation that flags discrepancies as they occur.
AGR's reconciliation module was built for exactly this purpose — it cross-references your royalty statement data against state production filings, validates BTU factors and unit conversions, compares pricing to published benchmarks, and surfaces errors before they compound.
See how AGR's reconciliation platform catches payment errors automatically.
For a deeper dive into reading your royalty statement line by line, see our companion guide: How to Read & Audit Your Royalty Statement.