#Why You Need a Structured Reconciliation Process
Royalty statements are not self-verifying documents. They are the output of an operator's revenue accounting system — a system that ingests production data, applies pricing, calculates deductions, and distributes proceeds across dozens or hundreds of interest owners. At every step, there is an opportunity for error. Transposed digits, stale pricing references, incorrect decimal interests, outdated tax rates, and improperly applied deductions are not hypothetical risks. They are recurring realities that cost mineral owners and non-operated working interest holders real money every month.
The problem is not that mineral owners are unaware errors exist. The problem is that most lack a systematic method for finding them. A check stub arrives, the dollar amount looks roughly correct, and it gets deposited without scrutiny. Even owners who do attempt to verify their payments often check only one dimension — typically the price or the gross amount — while ignoring the other variables that feed into the final number.
This article provides a structured five-point checklist for manually reconciling your royalty statements. Each checkpoint targets a specific category of operator error. Worked through sequentially, these five checks cover the full anatomy of a royalty payment: what was produced, what it sold for, what was deducted, what share is yours, and what taxes were withheld. None of these steps require proprietary software. All of them rely on publicly available data sources, your own lease documents, and basic arithmetic.
The discipline is in doing all five, every month, for every well.
#Checkpoint 1: Volume Verification
Volume is the foundation of every royalty calculation. If the production volumes on your check stub are wrong, every downstream number — gross revenue, net revenue, deductions, taxes — will be wrong too. Volume verification is the single highest-value audit step you can perform.
#What to Gather
You need two documents: your royalty statement (check stub) and the corresponding state regulatory production filing for the same well and production month.
In Texas, production data is filed with the Railroad Commission of Texas (RRC). Operators submit monthly production reports on Form PR (formerly the P-1 and P-2 forms), and these filings are searchable through the RRC's Production Data Query system at rrc.texas.gov. You can search by lease number, operator name, or API number. The RRC typically publishes production data with a two- to three-month lag from the production month.
In Oklahoma, production filings go to the Oklahoma Corporation Commission (OCC). The OCC's Imaging Web Application and the Well Browse system at occeweb.com provide access to completion reports, well records, and production data. Gross production figures are also available through the Oklahoma Tax Commission's gross production reporting.
In North Dakota, the North Dakota Industrial Commission (NDIC) — specifically its Oil and Gas Division — publishes well-level production data through its online database at dmr.nd.gov. Monthly production by well is searchable by API number, file number, operator, or field.
#What to Compare
Pull the gross oil production (in barrels) and gross gas production (in MCF) from the state filing for the production month shown on your check stub. Compare these volumes directly to what appears on your statement.
For oil, your check stub may show net sales barrels rather than gross production. Net sales volumes will be slightly lower than gross production due to basic sediment and water (BS&W) deductions, typically ranging from 0.5% to 3% for clean crude. A small difference attributable to BS&W is normal. A large discrepancy — more than 5% — warrants investigation.
For gas, be aware that state filings report wellhead volumes in MCF, while your statement may report sales volumes in MMBTU. These are different units connected by the BTU heating value of the gas stream. You cannot compare MCF to MMBTU directly without knowing the BTU factor. If your statement reports gas in MMBTU, you will need the BTU conversion factor (available from the gas purchaser's statement or the operator) to translate between the two.
#Red Flags
- Statement volumes significantly lower than state-reported production with no corresponding operational explanation (shut-in, workover, equipment failure)
- Zero production reported on your statement for a month when state records show active production
- Sudden volume drops that do not correlate with known field activity
- Gas volumes that appear on state records but are absent from your check stub, potentially indicating unreported gas sales or improper classification of marketed gas as flared
- Volume figures that are exactly the same month after month, which may indicate the operator is using a static allocation rather than actual metered production
#Checkpoint 2: Price Verification
Once you have confirmed that the volumes are correct, the next question is whether you were paid a fair price for those volumes. Pricing errors are among the most common operator mistakes, and they range from applying the wrong month's index price to using a benchmark that does not match the actual point of sale.
#What to Gather
You need your check stub (showing the price per barrel or per MMBTU applied to your production), and you need the relevant commodity index prices for the production month.
For crude oil, the primary benchmark is the NYMEX WTI (West Texas Intermediate) settlement price, published by CME Group. The monthly average of daily settlement prices for the front-month WTI futures contract is the standard reference. However, most production does not sell at WTI flat. Regional posted prices — such as WTI Midland, WTI Houston, or LLS (Light Louisiana Sweet) — reflect basis differentials that account for transportation costs, quality differences, and local supply-demand dynamics. The posted price your operator uses should be specified in your gas purchase contract or oil purchase agreement.
For natural gas, the primary benchmark is the NYMEX Henry Hub settlement price. But as with crude, basin-specific pricing hubs apply. Permian Basin gas might reference Waha, Midcontinent gas might reference NGPL Midcontinent or Panhandle Eastern, and Appalachian gas might reference Dominion South or Transco Zone 6. These basin-level prices are published in industry pricing bulletins such as Platts Gas Daily, Natural Gas Intelligence (NGI), and the Intercontinental Exchange (ICE) day-ahead and monthly indices.
For NGLs, pricing is based on product-specific benchmarks at Mont Belvieu, Texas, or Conway, Kansas — the two primary NGL trading hubs. Each NGL component (ethane, propane, normal butane, isobutane, natural gasoline) has its own price. Your NGL revenue depends on the plant's extraction economics and the terms of your processing agreement.
#What to Compare
Calculate the expected price by starting with the relevant index price and applying known adjustments. For crude oil, subtract the basis differential for your delivery point from the WTI settlement. For natural gas, use the basin-specific hub price rather than Henry Hub unless your purchase contract specifies Henry Hub as the reference. For NGLs, apply the component-weighted average price based on the plant's product yield.
Compare this expected price to the price shown on your check stub. A variance of a few cents per barrel or per MMBTU is common and may reflect timing differences between index settlement dates and actual sales dates. A variance of a dollar or more per unit is significant and should be investigated.
#Red Flags
- Price on your statement does not correspond to any recognized index or posted price for the production month
- The same price appears on your statement for multiple consecutive months, suggesting a stale pricing reference
- Gas prices that appear to be Henry Hub rather than the local basin hub, resulting in an inflated or deflated price depending on the basis differential direction
- Oil prices that do not reflect the standard gravity adjustment for your crude quality (lighter crude generally commands a premium, heavier crude a discount)
- NGL revenue that seems disproportionately low relative to gas production in a rich-gas area, which could indicate an incorrect plant allocation or a processing agreement applied on less favorable terms than your contract specifies
#Checkpoint 3: Deduction Audit
Gross revenue is not what you receive. Between the wellhead and your mailbox, the operator deducts costs for moving, processing, and marketing the production. These deductions — gathering, processing, transportation, and compression — can consume 15% to 40% of gross revenue depending on the basin, the infrastructure, and the terms of your lease. Verifying that each deduction is permissible and correctly calculated is the third checkpoint.
#What to Gather
You need three documents: your royalty check stub showing each line-item deduction, your oil and gas lease (specifically the royalty clause, and any cost-free or market-value language), and any division order or supplemental agreement that addresses post-production costs.
Read your lease carefully. The language of the royalty clause determines what deductions, if any, the operator may charge against your royalty. In some states and under some lease forms, the royalty is calculated on production "at the well" — meaning the operator can deduct reasonable post-production costs incurred to move and process the product from the wellhead to the point of sale. In other cases, the lease calls for royalty on the "market value at the well" or provides that the royalty shall be "free of cost" — language that may prohibit or limit certain deductions depending on the jurisdiction and case law.
If you have a gas processing or gas gathering agreement (or can request a copy from the operator), pull the specific rates. These contracts typically specify fees in cents per MCF (for gathering) or as a percentage of proceeds (for processing under a percent-of-proceeds or percent-of-index arrangement).
#What to Compare
For each deduction line item on your check stub, verify the following:
Gathering fees. Compare the per-unit gathering fee on your statement to the rate in the gathering agreement. Gathering fees in major basins typically range from $0.15 to $0.75 per MCF for gas and $0.50 to $2.50 per barrel for oil, depending on the system and distance to market. Fees that significantly exceed these ranges deserve a closer look.
Processing fees. If your gas is processed at a plant, verify the processing deduction matches the terms of the processing agreement. Under a percent-of-proceeds (POP) arrangement, the processor retains a percentage of the NGL revenue (commonly 25% to 50%) and returns the remainder. Under a fee-based arrangement, the processor charges a flat per-MMBTU fee. Confirm that the arrangement type and the rate match your contract.
Transportation fees. Transportation costs move product from the gathering system to the sales point. These should correspond to actual tariff rates on the relevant pipeline system. FERC-regulated interstate pipeline tariffs are publicly available. Intrastate tariffs are regulated by state commissions.
Compression fees. Some operators deduct compression costs separately. Verify that compression is not already embedded in the gathering fee — double-charging for compression is a known error pattern.
#Red Flags
- Deductions that appear on your check stub but are not authorized by your lease
- Deduction rates that exceed the contractual rates in the gathering, processing, or transportation agreements
- New deduction line items that appear without explanation or correspondence from the operator
- Deductions that increase significantly from one month to the next without a corresponding change in infrastructure or contract terms
- Compression charged as a separate line item when the gathering agreement already includes compression in its fee
- Deductions applied to royalty interests in states where case law or lease language prohibits post-production cost deductions against royalties (Texas courts, for example, have addressed this issue extensively, and the outcome depends on specific lease language)
#Checkpoint 4: Interest Decimal Check
Your net revenue interest (NRI) is the decimal fraction of production revenue to which you are entitled after all burdens — royalties, overriding royalties, and other non-cost-bearing interests — have been accounted for. An incorrect NRI on your division order or in the operator's accounting system will cause every payment to be wrong by a consistent percentage. Because the error is proportional rather than absolute, it can be difficult to detect without an independent recalculation.
#What to Gather
You need your division order (the document you signed confirming your decimal interest in the well), your oil and gas lease (showing the royalty fraction), and the title opinion or title runsheet for the unit or pooled acreage if available.
If the well is part of a pooled unit or a spacing unit, you also need the pooling order or spacing order from the relevant state commission. In Oklahoma, pooling orders are issued by the OCC and are searchable through the OCC's Imaging Web Application. In Texas, the RRC issues spacing permits and unitization orders. In North Dakota, spacing orders from the NDIC define the drilling and spacing units.
#What to Compare
Recalculate your NRI from first principles using this formula:
NRI = (Net Mineral Acres / Unit Acres) x Royalty Fraction x Lease Fraction
For example, if you own 80 net mineral acres in a 640-acre spacing unit, and your lease provides for a 3/16 royalty:
NRI = (80 / 640) x 0.1875 = 0.0234375
That decimal — 0.0234375 — should be carried to at least eight decimal places. Rounding to fewer places introduces a small but persistent error that compounds across every payment. On a well generating $100,000 in monthly gross revenue, the difference between a six-place decimal and an eight-place decimal can amount to several dollars per month. Across a large portfolio over several years, these rounding discrepancies add up.
Compare your independently calculated NRI against the decimal shown on your division order and on your check stub. If the three numbers do not match, identify where the discrepancy originates. Common sources of NRI errors include:
- Incorrect net mineral acreage (failure to account for prior conveyances, reservations, or inheritances)
- Wrong unit acreage (using the nominal section size rather than the surveyed acreage)
- Wrong royalty fraction (using 1/8 when the lease specifies 3/16 or 1/4)
- Failure to account for an overriding royalty interest that should have been carved from the working interest, not from the mineral owner's royalty
#Red Flags
- Division order decimal that does not match your independent NRI calculation
- Decimal carried to fewer than eight places on the division order or check stub
- A change in your decimal from one month to the next without a corresponding title event (a new well, a lease amendment, a probate)
- Different decimals for oil and gas on the same lease when the lease provides a single royalty fraction for both products
- A division order that arrives for signature with a decimal lower than what your title documents support — never sign a division order without verifying the decimal independently
#Checkpoint 5: Tax Withholding Verification
The final checkpoint covers severance tax and any other tax withholdings shown on your statement. Severance taxes are state-level taxes imposed on the extraction of natural resources. They are typically calculated as a percentage of the gross value of production and are withheld by the operator before distributing proceeds to interest owners.
#What to Gather
You need your check stub showing the tax withholding amounts, and you need the current severance tax rates for the state where the well is located.
Each producing state sets its own severance tax rates, and these rates change over time as state legislatures adjust them. The relevant rates as of the production month on your statement are what matter — not the rates in effect when the payment was issued.
Key state severance tax rates to verify:
Texas. Texas imposes a crude oil production tax of 4.6% of market value and a natural gas production tax of 7.5% of market value. These rates are administered by the Texas Comptroller of Public Accounts. Certain categories of production qualify for reduced rates or exemptions, including enhanced oil recovery projects (which may qualify for a reduced rate of 2.3%), low-producing wells (qualifying for exemption when the price drops below specified thresholds), and production from high-cost gas wells.
Oklahoma. Oklahoma's gross production tax rate on oil and gas is 5% of the gross value, although new wells have historically been subject to an incentive rate (as low as 2%) for a specified period following first production. The Oklahoma Tax Commission administers these rates, and the applicable rate depends on the well's spud date and production history.
North Dakota. North Dakota imposes two separate levies: a 5% oil extraction tax and a 5% gross production tax, for a combined rate of approximately 10% on oil production. The state also has provisions for reduced rates under certain pricing triggers — when the average price of oil falls below specified thresholds, the extraction tax rate may be reduced. The North Dakota Tax Commissioner administers these taxes.
New Mexico. New Mexico imposes multiple levies on oil and gas production, including severance tax, conservation tax, and an emergency school tax, with combined effective rates that vary by product type. The New Mexico Taxation and Revenue Department publishes the current schedules.
#What to Compare
Multiply the gross value of production (before deductions) by the applicable state severance tax rate. Compare this to the tax amount shown on your check stub. The tax should be withheld proportionally — that is, your share of the tax should equal your NRI multiplied by the total tax on the well's gross production.
Also verify that any applicable exemptions or reduced rates have been applied. If your well qualifies for a low-producing well exemption or an enhanced recovery incentive rate, and the operator is withholding at the standard rate, you are effectively overpaying taxes through the operator's withholding.
#Red Flags
- Tax withholding rate on your check stub that does not match the current statutory rate for the state
- Standard tax rate applied to a well that qualifies for a reduced rate or exemption
- Tax calculated on net revenue (after deductions) rather than gross value, which may be incorrect depending on the state's tax base definition
- Federal tax withholding that should not apply (federal income tax withholding on royalty payments is generally required only for certain foreign persons or in backup withholding situations — most domestic mineral owners should not see federal withholding)
- Different tax withholding rates applied to oil and gas from the same well in a state with a single uniform rate
#Putting It All Together
Working through all five checkpoints for a single well takes approximately 30 to 45 minutes once you have assembled the necessary documents and are familiar with the data sources. For a portfolio of 10 wells across two operators, expect to invest a full working day each month in reconciliation. For 50 wells, you are looking at a week of dedicated effort.
The value of the exercise depends on your tolerance for error. Industry studies and audit firm reports consistently indicate that 1% to 3% of royalty payments contain material errors — meaning errors large enough to warrant an adjustment. For a mineral portfolio generating $500,000 in annual royalty income, a 2% error rate translates to $10,000 per year in over-deductions, under-reported volumes, or misapplied pricing. Over a five-year look-back period (the statute of limitations for royalty claims in many states), that compounds to $50,000 in recoverable revenue.
The five-checkpoint approach is thorough but labor-intensive. It works well for mineral owners with a manageable number of wells who are willing to dedicate the time each month. It becomes impractical at scale — not because any individual step is difficult, but because doing all five steps across dozens or hundreds of wells every month is simply more work than most revenue teams can sustain without errors of their own.
#Related Reading
- Common Operator Payment Errors
- Royalty Underpayment Detection Guide
- Automated Royalty Reconciliation ROI
#How AGR Automates the Five-Point Reconciliation
AGR's reconciliation engine was built around these same five checkpoints — not as a monthly manual exercise, but as a continuous, automated process that runs against every well in your portfolio every time new data arrives.
Volume verification is performed automatically by ingesting state regulatory production data from the Texas RRC, Oklahoma OCC, North Dakota NDIC, and other state commissions, then matching reported volumes against operator check stub data at the well and product level. Discrepancies are flagged the moment filings are published, not weeks later when someone has time to run a manual comparison.
Price verification pulls daily and monthly settlement prices from NYMEX, basin-specific index publications, and NGL hub pricing at Mont Belvieu and Conway. The system applies the correct benchmark and basis differential for each well based on its location, delivery point, and purchase contract terms, then compares the expected price to the operator's reported price.
Deduction audits are driven by digitized lease terms and contract data. The platform knows which deductions are permissible under each lease, what the contractual gathering, processing, and transportation rates are, and whether a deduction line item on a check stub falls within expected bounds. Out-of-range deductions are flagged for review.
Interest decimal verification is maintained through a title and division order management module that tracks NRI calculations to eight or more decimal places, cross-references division orders against lease terms and pooling orders, and alerts you when an operator's decimal does not match your independently calculated interest.
Tax withholding verification applies current state severance tax rates — updated as legislatures change them — to the gross value of production and compares expected withholding to actual withholding on each statement. Exemptions and incentive rates are tracked by well and applied automatically based on qualifying criteria.
All five checkpoints run in parallel, across your entire portfolio, every reconciliation cycle. Exceptions are surfaced in a prioritized dashboard ranked by dollar impact, and every flagged item includes the underlying data, the expected value, the reported value, and the variance — giving you the documentation you need to approach the operator with a specific, well-supported inquiry.
The checklist in this article is a reliable manual process. AGR's platform turns that process into a system that scales without losing rigor.
Learn how AGR's reconciliation engine automates these five checkpoints across your entire portfolio.