#The Quiet Cost of Underpaid Royalties
Royalty underpayments are one of the most persistent and under-addressed problems in the oil and gas industry. They happen more often than most mineral owners realize, and they do not always stem from bad intent. Data entry errors, system migration glitches, incorrect price postings, and stale division orders can all produce payments that fall short of what is actually owed. In other cases, the issues are more systematic: improper post-production deductions, pricing methodologies that consistently disadvantage the royalty owner, or production volumes that do not reconcile with state records.
Regardless of the cause, the financial impact compounds over time. A 3% pricing discrepancy on a well producing 100 barrels of oil per day at $70 per barrel translates to roughly $6,300 per month in underpaid revenue for the full working interest — and that is before accounting for the dozens or hundreds of wells in a typical portfolio. Over the multi-decade life of a producing property, these shortfalls can reach six or seven figures.
This guide lays out a practical, five-pillar framework for detecting royalty underpayments. Whether you are a mineral owner reviewing a handful of check stubs or a revenue team managing thousands of interests, these methods give you a structured approach to verifying that you are being paid correctly.
#The Five Pillars of Underpayment Detection
#Pillar 1: Production Volume Verification
The foundation of any royalty audit is confirming that the volumes reported on your check stub match what was actually produced. Every major producing state requires operators to report production to a regulatory commission, and those filings are publicly accessible. When the volumes on your royalty statement diverge from the volumes reported to the state, you have an immediate red flag.
Start by pulling production data from the relevant state agency:
- Texas: The Railroad Commission of Texas (RRC) maintains a Production Data Query system at rrc.texas.gov. You can search by API number, lease number, or operator name to retrieve monthly oil, gas, and condensate production for any well in the state.
- Oklahoma: The Oklahoma Corporation Commission (OCC) publishes Gross Production reports. Well-level production data is available through the OCC's online imaging and document system.
- New Mexico: The Oil Conservation Division (OCD) under the Energy, Minerals and Natural Resources Department (EMNRD) provides well production data through its online portal.
- North Dakota: The North Dakota Industrial Commission's Department of Mineral Resources (NDIC DMR) Oil and Gas Division publishes monthly well production data, searchable by well name, API number, or operator.
When comparing these state records against your royalty statement, watch for several specific scenarios. The most obvious is a month where the operator reports zero production on your check stub but the state commission shows the well was actively producing. This can happen when payments are diverted to suspense, when a new purchaser takes over mid-month, or when the operator simply misses a well in its revenue run. Also pay close attention to wells that are part of a pooled or unitized spacing unit. Your share of production should reflect the correct allocation factor based on your tract's acreage relative to the total unit, and that factor should be updated whenever the unit is modified or a well is recompleted to a different formation.
#Pillar 2: Pricing Benchmarking
Even when the volumes are correct, the price applied to those volumes may not be. Pricing errors are among the most common — and most costly — sources of underpayment. The goal of pricing benchmarking is not to demand that you receive exactly the published index price, but to establish a reasonable range and investigate when your realized price falls outside it.
For crude oil, the primary domestic benchmark is West Texas Intermediate (WTI), priced at Cushing, Oklahoma. Your realized price will differ from WTI based on gravity adjustments (oil with an API gravity near 40 degrees generally commands the best price, with discounts for heavier or very light crudes) and basis differentials (the cost of transporting oil from the wellhead to Cushing or another delivery point). In the Permian Basin, for example, the Midland-to-Cushing differential has historically ranged from a few cents to several dollars per barrel depending on pipeline capacity.
For natural gas, the primary national benchmark is Henry Hub in Louisiana. Regional hubs provide more localized pricing: Waha Hub serves the Permian Basin, and ONEOK indices are commonly referenced in Oklahoma and the Mid-Continent. Gas pricing should also account for the BTU factor — gas with a higher heating value per cubic foot is worth more per MCF than lean gas, and the price on your statement should reflect that adjustment.
For natural gas liquids (NGLs), published prices at Mont Belvieu, Texas (the dominant NGL hub) or Conway, Kansas provide the relevant benchmarks. NGL pricing is typically broken out by product — ethane, propane, normal butane, isobutane, and natural gasoline — and your check stub should either show component-level pricing or a blended NGL price that is reconcilable to published component values.
If your operator consistently pays below the applicable published index by more than the typical gathering and transportation differential for your basin, that pattern warrants a formal inquiry. A one-month anomaly could be a timing issue or a contract-specific pricing mechanism, but a persistent gap suggests a structural problem.
#Pillar 3: Deduction Analysis
Post-production deductions are the single most litigated area of royalty payment disputes, and they are also the area where underpayments most frequently hide. The key to deduction analysis is granularity: you need to see every deduction line by line, not just a single net figure.
Start by itemizing every deduction category on your check stub and calculating each one as a percentage of gross royalty revenue. Then compare those percentages to industry norms for your basin:
- Gathering fees: Typically 5% to 15% of gross revenue, depending on the distance from the well to the main pipeline system and whether the gathering system is operated by a third party or an affiliate of the operator.
- Processing (plant) fees: Typically 10% to 25% of gross revenue for gas that requires treatment at a processing plant. The wide range reflects differences in gas composition — wetter gas with more extractable NGLs generally incurs higher processing fees but also generates higher total revenue.
- Transportation: Typically 3% to 10% of gross revenue, reflecting pipeline tariffs from the point of sale to the delivery hub.
Any deduction that falls significantly outside these ranges deserves scrutiny. Equally important, flag any new deduction categories that appear on your statement for the first time. Operators occasionally introduce charges — marketing fees, compression fees, or line-item surcharges — that may not be authorized under your lease.
The ultimate test for any deduction is your lease language. If your lease contains a "cost-free" or "free of cost" royalty clause, the operator may be prohibited from passing post-production costs through to your royalty interest. If it uses "at the well" language, the permissibility of deductions depends on how your state's courts have interpreted that phrase. Cross-referencing every deduction against the specific terms of your lease is essential. For a deeper look at how deductions appear on your statements, see our guide on how to read and audit your royalty statement.
#Pillar 4: Interest and NRI Verification
Your net revenue interest (NRI) — the decimal that determines your fractional share of production revenue — is the multiplier in every royalty calculation. Even a small error in the fifth or sixth decimal place, applied across months and years of production, can produce a significant cumulative shortfall.
Begin by confirming that the decimal interest on your most recent royalty statement matches the decimal on your signed division order. Then confirm that the division order decimal accurately reflects the chain of title documented in your deed, mineral conveyance, or probate records. In pooled or unitized properties, verify that the pooling ratio — your tract acreage divided by total unit acreage — is correct and that it has been updated to reflect any changes in unit boundaries.
Pay particular attention after a well is recompleted to a different producing formation, or when a new well is drilled within the same spacing unit. These events can trigger changes to the unit tract factor, and operators do not always update division orders promptly. If your decimal has not changed but the well's producing horizon or the unit configuration has, you may be receiving an incorrect share of production.
#Pillar 5: Timing and Payment Compliance
State statutes impose specific deadlines on when royalty payments must be made, and failure to comply may entitle you to statutory interest on late payments.
In Texas, the Natural Resources Code Section 91.402 requires operators to make the first royalty payment within 120 days after the end of the month of first sale. Subsequent payments are due on the date specified in the division order. If the operator fails to pay within those timeframes, the royalty owner may be entitled to interest on the unpaid amount, and in some circumstances, the operator may be liable for additional penalties.
Most other producing states have analogous statutes, though the specific timelines and interest rates vary. The critical discipline is tracking your payment history month by month and flagging any gaps. A missing check does not always mean the operator forgot about you — it can mean your funds were placed in suspense due to a title question, a pending division order, or an ownership dispute. But you will not know unless you track it, and money left in suspense can eventually be subject to state escheatment laws if the underlying issue is not resolved.
For a detailed look at how suspense and payment gaps interact with common operator errors, see our analysis of volume discrepancies and operator payment errors.
#Building Your Audit Spreadsheet
You do not need specialized software to start detecting underpayments. A basic spreadsheet can serve as a powerful audit tool when structured correctly. Here is a practical template:
| Column | Data | Source | |--------|------|--------| | A: Month | Production month | Check stub | | B: Gross Production | Total well production (BBL or MCF) | State commission records | | C: Net Production | Operator-reported production on your stub | Check stub | | D: Price Per Unit | Price applied by operator | Check stub | | E: Benchmark Price | Published index price (WTI, Henry Hub, etc.) | EIA or pricing service | | F: Gross Revenue | Column B multiplied by Column E | Calculated | | G: Your NRI | Your decimal interest | Division order | | H: Expected Royalty | Column F multiplied by Column G | Calculated | | I: Actual Payment | Amount received | Check stub | | J: Variance | Column H minus Column I | Calculated |
Populate this spreadsheet for every producing month and every well. The variance column is your early warning system. A positive variance means you received less than expected; a negative variance means you received more (which can happen when index prices lag actual contract prices). The value of this exercise is pattern recognition: isolated variances may reflect timing or measurement differences, but persistent positive variances across multiple months point to a structural underpayment.
#When to Escalate
Not every variance requires legal action, but knowing when to escalate — and how — protects your rights and creates the paper trail you may eventually need.
Persistent variances above 5% warrant a formal inquiry. A one-time 2% discrepancy might be a rounding or timing issue, but if you see 5% or greater shortfalls recurring month after month, something systematic is wrong.
Send a written demand for an accounting. A certified letter to the operator's revenue or division order department creates a legal record that you have identified a discrepancy and requested an explanation. Most operators have internal audit teams that will review the claim, and many legitimate errors are corrected at this stage without further action.
Consider hiring a royalty audit firm. Professional royalty auditors specialize in exactly this kind of analysis, and most work on a contingency fee basis, typically 25% to 35% of recovered funds. This means there is no upfront cost to you — the auditor only gets paid if they find money that is owed to you. For mineral owners with large portfolios or complex title situations, a professional audit can surface issues that a spreadsheet review might miss.
For systematic or high-dollar issues, consult an oil and gas attorney. If the operator refuses to provide an accounting, if the underpayment involves unauthorized deductions that violate your lease terms, or if the total amount at stake justifies litigation, legal counsel with specific experience in oil and gas revenue disputes is essential. Many oil and gas attorneys also work on contingency or hybrid fee arrangements for royalty underpayment claims.
#Related Reading
- Common Operator Payment Errors
- Automated Royalty Reconciliation ROI
- A 5-Point Manual Reconciliation Checklist
#Stop Leaving Money on the Table
Underpayment detection is not a one-time exercise. Production volumes change, commodity prices fluctuate, operators update their systems, and new deductions can appear without warning. The mineral owners and revenue teams who catch errors consistently are the ones who have a repeatable, systematic process — not those who audit once and assume the problem is solved.
The five-pillar framework outlined in this guide — production verification, pricing benchmarking, deduction analysis, interest verification, and timing compliance — covers the full surface area of royalty underpayment risk. Applied month after month, it gives you the ability to detect problems early and recover revenue before small discrepancies become large losses.
AGR's reconciliation platform was built to automate all five of these pillars. It ingests your royalty statements, cross-references production data from state commissions, benchmarks pricing against published indices, analyzes deductions against lease terms, verifies decimal interests, and tracks payment timing — continuously, across your entire portfolio, without manual effort. Discrepancies are flagged the moment they appear, not months or years later.
See how AGR's AI-powered reconciliation protects your revenue.