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Category: Mineral Management

Professional mineral management services, strategies, and best practices for mineral asset administration.

Operator Unclaimed Property Notice: How Mineral Owners Should Verify and Respond

Posted on by Leonardo

Valor has recovered more than $32 million in suspended and escheated royalty funds for mineral owners. A large share of that started with a single piece of mail: an operator unclaimed property notice. These letters are easy to mistake for junk, easy to misfile, and if you ignore them, a reliable way to lose years of royalty income to a state treasurer’s unclaimed property division. This post walks through what the letter actually means, how to verify it in about ten minutes, how to respond so the operator can release your funds, and how to recover money that has already been reported to the state.

What the Letter Actually Means

An operator unclaimed property notice, sometimes called a due-diligence letter or pre-escheat notice, is a required mailing under most state unclaimed property laws. State unclaimed property laws often require holders to make a final attempt to contact the apparent owner before eligible property is reported and transferred to the state. Requirements and notice thresholds vary by state.

The letter is the operator’s last attempt to make contact with you before your money moves out of their suspense account and into state custody.

If you receive one, the operator or holder has generally identified property associated with your name that may meet the state’s requirements for reporting as unclaimed property. The underlying reason can vary. Common issues may include outdated contact information, ownership or estate changes, tax-information discrepancies, unresolved title questions, unsigned division orders, or extended periods without owner contact. The notice should identify a deadline or instructions for establishing contact before the property is reported.

The letter is not a scam by default, but scam versions do exist. That is why verification comes before response. If you manage minerals across multiple states and operators, this type of notice is one of several routine items a professional mineral management team handles on your behalf. For a broader guide to identifying which type of letter you received and whether it is legitimate, read Before You Throw That Letter Away: How to Verify Any Mineral Rights Notice.

Verify the Notice in Ten Minutes

Before you sign anything or send a W-9, confirm the letter is legitimate using free public records.

Start with the operator’s name and P5 number in Texas or OCC operator number in Oklahoma. Search the Railroad Commission or Oklahoma Corporation Commission operator database and confirm active status, good standing, and bonding. Cross-check any lease name, county, and section-township-range against regulator records. The county, formation, and operator should all match what appears on your most recent royalty statements or division order.

Next, confirm the operator’s corporate standing with the Texas Comptroller’s taxable entity search or the Oklahoma Secretary of State. If a notice comes from an unfamiliar third party, independently verify the relationship before providing personal information or signing any agreement. Be particularly cautious if the sender requests an upfront fee, a percentage of recovered funds, or sensitive information through an unfamiliar website or email address. Operators do not use contingency-fee recovery firms to return your own money to you.

Verify contact information independently through the operator’s official website, regulatory filings, or previously verified owner-relations contact information rather than relying solely on the phone number or email printed on the notice. Across the 32 states and 13 basins Valor’s team works in, the pattern is consistent: real notices are formatted, professional, and signed by an identifiable owner-relations contact.

How to Respond: Certified Mail, W-9, and the Right Questions

Once you have verified the notice, follow the response method specified in the notice and keep documentation showing when and how you responded. If sending documents by mail, using a trackable delivery method such as certified mail with return receipt provides an additional record that the operator received your response before the state’s escheat deadline.

Depending on the reason for the notice, the operator may request some or all of the following:

A completed and signed IRS Form W-9 with your current legal name, mailing address, and taxpayer identification number. Missing or outdated taxpayer information is one of the single most common reasons royalty funds end up in suspense.

The operator’s response form or affidavit of ownership, fully completed and signed. If an estate is involved, include a copy of the letters testamentary, probate order, or recorded affidavit of heirship.

A cover letter that references the notice date, the operator’s internal owner number, and the specific lease or well identifiers from the letter.

A written request for information. This is the step most owners skip. Consider asking the operator to confirm or provide, when available: your net mineral acres in the tract, your decimal interest, the current lease status and primary-term expiration, the pay periods covered by the suspended funds, and the gross and net amounts being held.

That last request matters. If funds have been in suspense for an extended period, understanding both the cause of the suspension and the operator’s current ownership records can help identify discrepancies before future payments are released. For guidance on how to verify your decimal once the operator responds, read How to Calculate Your Royalty Decimal Interest.

Common Causes and a Prevention Checklist

Across Valor’s portfolio of roughly 500,000 managed wells generating approximately $650 million in annual client revenue, the causes of suspended royalties cluster into a short list:

Address changes after a move, especially when the owner updated one operator but not the other six paying on the same tract.

Name changes from marriage, divorce, or trust transfers that were never reported to owner relations.

Estate transfers where the original owner is deceased and heirs never recorded an affidavit of heirship or provided probate documents.

Missing, incorrect, or outdated taxpayer information, which may result in backup withholding or additional documentation requirements.

Division-order disputes where the owner refused to sign because the decimal looked wrong and then the file sat unresolved.

Title defects identified during the operator’s division-order title opinion that were never cured.

Prevention is cheaper than recovery. A basic checklist: notify every operator in writing promptly after any address, name, or ownership change; keep a current W-9 on file with each operator; record affidavits of heirship or probate orders in every county where you own minerals; review your royalty statements quarterly for new operators or missing payors; and keep a simple spreadsheet of every lease, operator, owner number, and decimal interest. Maintaining consolidated ownership, operator, and payment records can make it easier to identify discrepancies early and address potential suspense issues before they compound. Valor’s mineral management team maintains exactly this kind of consolidated view across every client portfolio.

If the Funds Already Escheated: State Treasurer Recovery

If the notice arrived too late, or if you suspect past funds were already turned over, recovery is still possible. Every state operates an unclaimed property database searchable by name.

If you believe funds have already been reported as unclaimed property, search the state associated with the address the operator or payor had on file for you. It can also be worth checking states where you previously lived or maintained a mailing address.

If the holder did not have a valid address for you, interstate unclaimed-property priority rules may direct the property to the holder’s state of incorporation or domicile. Because many companies are incorporated in Delaware, Delaware’s unclaimed property database can be an important secondary search, but a Delaware incorporation does not automatically mean royalty funds from a Texas or Oklahoma property were sent to Delaware. Start with the state associated with your address in the operator’s records, then check Delaware if you do not find the funds there.

Documentation requirements vary by state and by the type and age of the property. A claimant may be asked for proof of identity, documentation connecting them to the reported address or property, and in estate or ownership cases, additional probate or title records. The process is free. Do not pay a percentage-of-recovery firm to do what you can do yourself, or what a professional mineral management team will do as part of standard portfolio oversight. For a state-by-state guide to searching unclaimed mineral funds, read Valor’s unclaimed mineral funds guide.

Of the more than $32 million Valor has recovered for mineral owners, a meaningful share came from state treasurer databases that owners did not know to check.

Contact Valor Today

If you have received an unclaimed property notice and are not sure whether it is legitimate, whether to respond yourself, or whether funds may have already been reported to the state, Contact Valor today for a free, no-obligation review. Our mineral management team of CPAs, CPLs, and Certified Mineral Managers will verify the notice, assemble the response package, request the right information from the operator in writing, and search state treasurer databases for any funds that may have already been reported. We handle royalty management and suspense releases for mineral owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only and is not intended to provide specific recommendations or legal or tax-related advice. This blog should not be used as a substitute for competent legal advice from a licensed attorney in your state.

Who Actually Pays Your Royalties?

Posted on by Leonardo

When a royalty check suddenly stops showing up, the immediate question is almost always: Who is actually supposed to be paying me?

For many mineral owners, finding that answer isn’t straightforward. Oil and gas properties change hands frequently, operators sell asset packages, and purchasers reconfigure marketing channels. Valor’s mineral rights management team frequently assists clients in recovering suspended, missing, or underpaid royalties—and in many of these cases, the root cause is simply identifying and reaching the correct disbursing entity.

Understanding how royalty disbursers operate—and where to look—can save months of delay when a payment stops.

Understanding the Three Entities on Your Check Stub

In Texas and across most major energy basins, the entity responsible for distributing oil and gas proceeds is referred to as the payor (Texas Natural Resources Code § 91.401). Depending on the contractual and marketing arrangement, that payor may be the operator, the purchaser, or a third-party administrator handling payment disbursement. Confusing these three roles is one of the most common reasons payment inquiries get stalled:

  1. The Operator: This is the company designated as the operator of record, responsible for operating the well and making required regulatory filings—such as filing a Form W-1 with the Texas Railroad Commission (RRC) or spacing applications with the Oklahoma Corporation Commission (OCC). However, holding the operating permit does not automatically make them the entity responsible for disbursing royalty checks.
  2. The Purchaser (First Purchaser / Marketer): This is the entity purchasing the raw crude oil, natural gas, or natural gas liquids (NGLs) at the wellhead or tailgate. In many agreements—particularly for crude oil—the purchaser contracts directly to pay royalty owners on behalf of the operator. Under Texas law, the first purchaser is defined as the primary payor unless the parties contractually arrange for the operator or another entity to receive proceeds and pay royalty owners instead. If your stub bears the name of a midstream pipeline or marketing firm rather than the well operator, you are receiving checks from the purchaser.
  3. The Revenue Administrator (Disbursement Agent): Revenue administration is the back-office accounting function responsible for maintaining ownership decimal schedules, applying tax withholdings, issuing checks, and mailing annual 1099s. Operators may perform this in-house or outsource it to a third-party service provider. When operator assets trade, the revenue administrator may change as part of the transaction, even when physical operations on the well site remain identical. Learn more about how these moving parts fit together in our guide on what mineral management is.

Your Check Stub: The Primary Diagnostic Tool

Before filing a formal dispute or contacting a state regulatory agency, inspect your most recent check stub or remittance advice. State laws in Texas and other energy-producing jurisdictions require payors to provide extensive remittance detail—making your check stub your primary diagnostic tool.

Pay close attention to these key fields:

  • Payer Name and Remittance Address: The specific corporate entity cutting the check (and where correspondence should be directed).
  • Owner Number: The unique internal identifier assigned to you by that specific payer. You will need this whenever contacting their owner relations department.
  • Property/Lease Name and ID: The internal accounting number assigned to the well or unit.
  • Product Code: Identifies whether the payment covers oil, gas, plant products, or NGLs. Different products on the same well can have different purchasers and check disbursers.
  • Decimal Interest: Your specific share of revenue. A shift in this decimal can explain sudden changes in check amounts.
  • Production Month: Royalty payments often trail the underlying production month, and timing varies by product, purchaser, lease terms, and state requirements. For example, Texas statutory deadlines generally require payment within 60 days after the end of the month of sale for oil proceeds and 90 days for gas proceeds.

If you experience an interruption, compare older check stubs against recent ones. A change in the payer’s name, remittance address, or your owner ID may indicate that the payment arrangement or disbursing entity has changed.

What Happens During an Asset Sale or Operator Transfer?

When producing assets change hands, payment records do not always transition at the exact same time as physical operations. The outgoing and incoming parties must transfer ownership records, division-of-interest (DOI) data, tax information, payment history, and other account details before the new payment process is fully established.

During this transition, royalty owners may receive new owner numbers, updated division orders, or communications from a different payor or revenue administrator. In some transactions, payments may also be temporarily delayed or placed in suspense while ownership and payment records are reconciled.

The transition timing varies materially depending on transaction size, state requirements, lease terms, product type, and specific contractual agreements between buyer and seller. Common friction points during transfers include:

  1. Outdated Mailing Addresses: New payors send division orders or updated account notices to the address provided by the previous operator. If you moved without updating your record, mail is returned, and payments may be placed on administrative hold or in suspense.
  2. Unreconciled Suspense Balances: Existing suspense balances must be audited and reconciled. Depending on transaction terms, responsibility for historical suspense balances may remain with the prior payor or transfer to the incoming entity.

If payments stop following an asset or operator change, owners should confirm both the current operator of record and the entity currently responsible for disbursing proceeds.

How to Track Down the Right Royalty Disburser

If your checks have stopped and your stubs don’t provide a clear answer, follow these steps:

  1. Verify the Current Operator: Query state regulatory databases—such as the Texas RRC Public GIS Viewer / Operator Query or the Oklahoma OCC Well Data System—using your county, lease name, or API number.
  2. Look for Transfer Filings: Check for official transfer documents (such as a Texas RRC Form P-4). These forms formally record changes in operator of record status and often list updated contact information.
  3. Contact Owner Relations: Reach out directly to the current operator’s Owner Relations department. Provide your well name and API number, and ask specifically: “Who is the designated disburser of record for royalties on this property?”
  4. Request Division Orders: If a third-party purchaser or revenue administrator handles payments, request a division order if one is required, and confirm your owner number with them.
  5. Verify Contact and Tax Details: Confirm that your current mailing address, email, and W-9/tax ID are up-to-date with the disburser to clear any administrative holds.

If you find yourself passed between an operator, a purchaser, and a prior owner—each claiming the other is responsible—the record trail has likely broken down. Navigating these gaps is a core part of comprehensive mineral administration.

Action Checklist: Resolving Stopped or Missing Royalties

Keep this checklist alongside your ownership documents whenever addressing payment issues:

Step 1: Gather Historical Documentation

  • Collect your last 3–6 check stubs for the affected well.
  • Note the Payer Name, Remittance Address, Owner ID, Property Number, Decimal Interest, and last Production Month paid.
  • Compare old and new stubs to highlight any changing information.

Step 2: Confirm Regulatory Status

  • Search the relevant state regulatory agency (RRC, OCC, NDIC, etc.) by county and legal description.
  • Note the current operator of record and any recent operator change filings (e.g., Texas Form P-4).

Step 3: Contact Disburser Owner Relations

  • Call or email the current operator’s Owner Relations team to request the active payor name and your assigned Owner ID.
  • Contact the active disburser to confirm whether your account is active or in suspense.

Step 4: Update and Audit Records

  • Provide written confirmation of your current mailing address and W-9/tax identification.
  • Request updated division orders for any properties currently suspended.
  • Inquire about accumulated suspense balances and anticipated release dates.

Step 5: Document All Correspondence

  • Maintain a dedicated log with dates, contact names, direct phone numbers, email records, and outcomes.
  • Retain copies of all signed division orders and formal letters in a single property file.

Professional Oversight for Complex Portfolios

Tracking down missing disbursers and reconciling revenue across dozens of wells, operators, and states can quickly become a full-time job.

Through our proprietary mineral.tech® software platform, Valor provides structured oversight, automated revenue auditing, and systematic suspense tracking for mineral owners, family offices, trusts, and institutional investors nationwide. If you have questions about a missing payment or an unlocated disburser, explore our comprehensive mineral owner’s guide to learn more about options for managing your interests.

Contact Valor

If you are dealing with a stopped royalty payment, unresolved suspense balances, or need help navigating a recent operator transfer, Valor’s team of CPAs, Certified Professional Landmen (CPLs), and Certified Mineral Managers (CMMs) is here to help. We trace missing revenue, audit check stubs, and liaise directly with operator relations departments to keep your payments on track.

Contact Valor today for a confidential review of your royalty check stubs or to speak with a mineral management specialist about optimizing your asset portfolio.

The information provided by Valor in this blog is for general informational purposes only and is not intended to provide specific recommendations or legal or tax-related advice. This blog should not be used as a substitute for competent legal advice from a licensed attorney in your state.

Which Professional Do You Actually Need for Your Mineral Rights?

Posted on by Leonardo

Mineral owners encounter a wide range of professionals: landmen, oil and gas attorneys, CPAs, Certified Mineral Managers, petroleum engineers, and mineral appraisers. The questions that keep surfacing — from an owner with 0.00145 net acres wondering whether an issue is worth pursuing, to a trustee trying to establish a defensible price for a beneficiary transaction — often come down to the same confusion: which professional actually handles the problem in front of you?

This post maps each professional to their actual scope of work and tells you how to match the right one to your situation before you spend money. For the full breakdown organized by situation rather than by professional, read Attorney, CPA, Landman, or Mineral Manager: Who to Hire for What.

Start With the Problem: Title, Value, Tax, or Management

The single most useful question to ask before hiring anyone is which category your problem falls into: legal title, valuation, tax, or ongoing management. Most owners skip this step and end up paying attorney rates for work a CMM would handle at a fraction of the cost — or paying a CMM to research a title defect that requires a lawyer.

An oil and gas attorney handles legal title, lease and conveyance drafting, probate and heirship matters, and legal defects in the ownership chain. A mineral appraiser determines value using production history, decline-curve analysis, market data, and comparable transactions. These are distinct deliverables and distinct scopes of work. A valuation professional is not a legal authority. An attorney who discusses value is not providing a formal independent appraisal.

If the problem is legal ownership or title, start with an attorney or CPL depending on the issue. If the problem is value, find a professional experienced in mineral valuation. If it involves both, you need coordination — which is exactly what a mineral management team that includes CPAs, CPLs, and Certified Mineral Managers provides under one engagement.

The Six Professionals You Will Actually Encounter

Oil and gas attorney. Interprets title, drafts and negotiates legal documents, advises on probate and heirship, and fixes legal title defects. The only professional who can render a formal title opinion or represent you in court. For multi-state mineral interests, the attorney must be licensed in — or coordinate with counsel in — each mineral state. Not a valuation professional.

Landman or Certified Professional Landman. Researches courthouse records, prepares ownership and title-status reports, negotiates leases and rights-of-way, and handles title curative work. A CPL is not a lawyer and cannot render a title opinion — but a CPL builds the chain a lawyer opines on. Putting an attorney on courthouse research is the most expensive mistake mineral owners make on title work. Valor’s team of CPLs handles this work across 32 states.

CPA or oil and gas tax accountant. Handles depletion schedules, stepped-up basis at death, 1099 reconciliation, severance tax, and the tax treatment of royalty income. A good oil and gas CPA understands percentage depletion and intangible drilling costs. Does not handle title or valuation. Documenting stepped-up basis at date of death is one of the highest-value tax moves in mineral ownership and it has to happen while the documentation trail is fresh.

Certified Mineral Manager. Trained specifically in ongoing administration — revenue reconciliation, division order review, lease compliance, operator communications, and portfolio reporting. This is the role most owners do not know exists and the one they most often try to force an attorney or CPA to fill. Those professionals will do it — at the wrong rate and with the wrong expertise.

Mineral appraiser or valuation professional. Provides an independent opinion of value as of a specific date using production data, decline curves, reserve estimates, commodity price forecasts, and comparable transactions. Most important for estate tax purposes, date-of-death valuation on inherited minerals, and fiduciary transactions involving beneficiaries. A mineral appraiser is not a petroleum engineer and not an attorney.

Petroleum engineer. Models production decline, estimates recoverable reserves, and evaluates well performance. Retained when a formal reserve report is needed — for financing, acquisition due diligence, or a large estate requiring a production-based value opinion. Most individual mineral owners will not need one.

When Small Interests Do Not Justify Professional Fees

This is the question most owners with fractional inherited interests face but rarely ask directly: is this worth it?

The answer depends on the value of the interest, the nature of the issue, the cost of resolution, and whether the issue compounds over time. A legal title defect on a 0.00145 net acre interest generating $4 per month probably does not justify a full quiet title action. An ownership gap on a 40-acre tract in an active formation almost certainly does.

Do the math before you hire anyone. What is the likely value of the interest if the issue is resolved? What will resolution cost? Is there a limitations period running that makes delay expensive? Valor’s mineral management team can run that triage before any professional fees are committed. For owners with very small interests working through what to prioritize, read Just Inherited Mineral Rights? Here Is Where to Start.

State Matters: Texas, Oklahoma, and Multi-State Ownership

Which professional you need depends in part on where the minerals are located. Texas and Oklahoma have meaningfully different legal frameworks and the differences matter.

Texas. Uses the original land grant survey system. Affidavits of heirship are a common and effective title curative tool. Texas courts have consistently upheld post-production cost deductions when lease language is silent — cost-free language must be explicit to hold up. The Railroad Commission governs oil and gas regulation. For a plain-language guide to reading Texas legal descriptions and locating a tract, read How to Locate Your Mineral Tract on a Map.

Oklahoma. Uses the federal PLSS grid. Force pooling through the Oklahoma Corporation Commission establishes documented bonus and royalty terms that function as public comparables — useful for benchmarking any offer in that area. Oklahoma’s Production Revenue Standards Act creates specific statutory remedies for late payment that do not exist in Texas. For a plain-language explanation of how force pooling works in Oklahoma compared to Texas, read Forced Pooling in Oklahoma vs. Texas.

Multi-state interests. Minerals pass under the law of the state where they sit — not the decedent’s home state. Out-of-state ownership requires ancillary probate or another state-authorized transfer procedure in each mineral state. An attorney licensed in or coordinating with counsel in the mineral state is not optional. For the full breakdown of what multi-state inheritance requires, read Inherited Minerals in a State You Don’t Live In.

Trustees, Executors, and Fiduciary Situations

Trustees and executors have a specific professional need that individual owners usually do not: independent valuation when a transaction involves beneficiaries or a potential conflict of interest.

A trustee selling minerals to a related party, or distributing an interest in kind to one beneficiary rather than another, needs a defensible independent valuation — not an offer letter or an operator’s estimate. The mineral appraiser provides that number. The attorney ensures the transaction is legally proper. The CMM handles the operational transfer. These are three separate jobs and they should not be collapsed into one.

For context on how mineral interests fit inside a trust structure and what trustees need to know operationally, read Minerals in a Trust: What Bankers, Trustees, and Mineral Owners Need to Know.

The Coordinated Team: When One Professional Is Not Enough

Many mineral situations require professionals working in sequence. The most common pattern: a CPL runs the title chain, the attorney identifies the defect and drafts the curative instrument, the CPL records it, and the CMM picks up ongoing administration once ownership is clean.

For a multi-state estate: the estate attorney handles domiciliary probate and coordinates ancillary proceedings, the CPL confirms title in each mineral state, the CPA establishes stepped-up basis at death, and the CMM handles operator notifications and division order updates.

The mistake owners make is forcing a single professional into all of these roles. An attorney charging hourly rates to monitor royalty statements and chase operator correspondence is doing CMM work at attorney prices. The coordinated model — each professional doing the work they are trained for — is faster and less expensive than a single generalist handling everything.

Valor’s team operates as that coordinated structure. The $27 million recovered since 2018 came from putting the right professional on the right problem at the right time. If you are not sure which role applies to your current situation, Contact Valor for a free review before committing to any professional fees.

Contact Valor Today

Not sure which professional you need — or whether the issue is worth pursuing at all? Contact Valor today for a free, no-obligation review. Our mineral management team of CPAs, CPLs, and Certified Mineral Managers will identify what your situation actually requires, handle the work that falls within our scope, and coordinate with attorneys, appraisers, and tax advisers where the situation calls for it. We manage mineral rights across Oklahoma, Texas, and 30 other states for owners, trusts, banks, and institutions.

The information provided by Valor in this blog is for general informational purposes only and is not intended to provide specific recommendations or legal or tax-related advice. This blog should not be used as a substitute for competent legal advice from a licensed attorney in your state.

Henry Hub vs. WTI: Which Price Actually Drives Your Royalty Check?

Posted on by Leonardo

Open your royalty statement and you will see two numbers that matter more than almost anything else on the page: Open your royalty statement and you will see two numbers that matter more than almost anything else on the page: the price your operator paid you for oil and the price paid for gas. Both move independently, both reference national benchmarks — West Texas Intermediate (WTI) for oil and Henry Hub for gas — and neither benchmark alone dictates your total payout. Which benchmark impacts your income more depends on what your wells produce, where they sit, and how your operator markets the production.

Your Check Reflects a Product Mix, Not a Single Price

Every royalty check represents multiple underlying revenue streams combined into a single distribution:

  • Oil Value: Oil sales volume × applicable oil sales price
  • Gas Value: Gas sales volume × applicable gas sales price
  • NGL Value: Liquids volume × applicable NGL price (when separately reported)

Your total payout then reflects your net revenue interest (NRI) less applicable production taxes, adjustments, or permitted post-production deductions.

The relative size of these streams — your product mix — determines whether WTI or Henry Hub has a greater impact on your monthly check.

Basin / RegionPrimary Commodity ExposureKey Benchmark References
Permian Basin (Reagan, Midland, Martin)Heavily Oil-WeightedWTI (adjusted for WTI Midland/MEH pricing)
Haynesville (East TX, NW Louisiana)Primarily Dry GasHenry Hub
Anadarko Basin (Western Oklahoma)Dry Gas to Wet Gas / NGLsHenry Hub & Mont Belvieu
Eagle Ford & SCOOP/STACKMixed / Liquids-RichWTI & Mont Belvieu Liquids

A common surprise for mineral owners is discovering their true commodity exposure looks nothing like they assumed. A tract thought to be purely “an oil property” often yields substantial gas and NGL revenue once every line item is accounted for. For a deeper look at how interest structures shape what shows up on your statement, our Mineral Management Overview lays out the framework.

When WTI Matters Most

WTI (West Texas Intermediate) is the light, sweet crude benchmark priced at Cushing, Oklahoma. If your wells sit in the Permian, Eagle Ford, SCOOP/STACK oil window, Bakken, or DJ Basin, WTI movements strongly influence your crude oil revenue.

However, the realized price on your statement is rarely WTI flat. Realized sales prices may sit above or below WTI depending on regional basis, location, crude quality, contract terms, and sale timing. For example, WTI Midland is a regional crude price that can trade at a premium or discount to Cushing pricing rather than serving as a standard flat deduction.

Key items to audit on oil-weighted statements:

  • Realized Price per Barrel: Compare the reported unit price against monthly benchmark averages for the specific production month (not check month).
  • Itemized Deductions: Audit separate line items for gathering, transportation, or marketing costs.
  • Deduction Calculations: Verify whether discounts or fees are applied before or after net price realizations.

When Henry Hub Matters Most

Henry Hub is the standard U.S. natural gas benchmark, priced at Henry Hub in Erath, Louisiana. If your acreage sits in the Haynesville, Marcellus/Utica, or dry-gas windows of the Anadarko Basin, natural gas pricing dictates the bulk of your check.

Haynesville economics are closely tied to Henry Hub due to proximity to Gulf Coast LNG export terminals and industrial demand, though actual realized prices still vary based on delivery points and sales contracts. Elsewhere, regional differentials can create significant swings. In the Permian Basin, for instance, Waha hub gas has historically traded at deep discounts — and occasionally negative prices — when regional pipeline takeaway capacity fills up.

For NGL-rich acreage (wet gas in the Anadarko or Eagle Ford), products like propane, butane, ethane, and natural gasoline price against Mont Belvieu benchmarks. NGL revenue can help offset weaker dry-gas pricing, depending on liquids yield and realized NGL prices.

Understanding Payment Timing and Settlement Lag

A common question from mineral owners is: “WTI was up last month, so why did my check drop?” One common reason is settlement lag.

Royalty payments commonly trail the production or sales month by one to three months, depending on the commodity, operator practices, state statutory deadlines, and specific lease agreements. For example, under Texas law, ongoing royalty proceeds are generally payable up to 60 days after the sales month for oil and 90 days for gas. Oklahoma law similarly provides for payment timelines spanning two to three months following production.

  • Month 1: Physical Production & Field Delivery
  • Month 2: Operator Reconciliation, Invoicing & Purchaser Accounting
  • Month 3 (or 4): Royalty Distribution Issued to Owner

Because of this delay, September production may not appear on a royalty check until November or December. Building this lag into your expectations prevents unnecessary confusion during market swings. Valor’s team of CPAs, CPLs, and Certified Mineral Managers — view our credentials on the Valor Team Page — systematically audits payment timing and pricing accuracy to protect against delayed or miscalculated distributions.

When Benchmarks Diverge — Practical Audit Steps

A portfolio with both oil- and gas-linked revenue may be less exposed to movements in a single commodity when WTI and Henry Hub diverge. However, ensuring you receive full value requires routine statement verification:

  1. Compare Unit Prices: Match check unit prices against historical benchmark averages and regional market adjustments for that production month.
  2. Reconcile Volumes: Cross-reference statement volumes with state regulatory filings, keeping in mind that wellhead production and sales volumes may not match 1-to-1 due to allocations, processing shrinkage, lease fuel, or flaring.
  3. Audit Deductions: Flag any month where post-production deductions (gathering, compression, processing, transportation) jump as a percentage of gross revenue.
  4. Monitor Suspended Balances: Track held funds following title transfers, operator changes, or property acquisitions.

Valor has recovered more than $32 million for mineral owners in the past 36 months through royalty auditing, including underpayments, suspended balances, and deduction errors. Watch our 2-minute mineral management overview to see how audit recovery works.

Contact Valor Today

Understanding which benchmarks impact your check is the first step; verifying that your operator calculates your distributions accurately is where value is preserved. If you want a professional audit of your statements, deductions, and revenue accuracy across your assets, Valor’s expert team provides comprehensive mineral management solutions.

Contact Valor today for a review of your royalty statements and revenue performance.

Disclaimer: The information provided by Valor in this blog post is for general informational purposes only and does not constitute financial, legal, or tax advice.

How to Locate a Mineral Tract From a Deed Description

Posted on by Leonardo

A deed that reads “320 acres, more or less, out of the H&TC RR Co. Survey, Abstract 412, Reagan County, Texas” tells you exactly where your minerals are — if you know how to read it. Most heirs do not, and that is the reason a shoebox of family paperwork often sits untouched for years while wells produce nearby.

This guide walks through the free public tools that translate a Texas or Oklahoma legal description into a shape you can see on a map, in the order you should use them. You will finish with a repeatable process and a short list of the traps that catch first-time researchers. If you have recently inherited minerals and are not sure what you own or where it is, read Just Inherited Mineral Rights? Here Is Where to Start before working through the steps here.

Read the Deed First: Survey, Abstract, and Varas

Before any map is useful you have to decode the language on the page. Texas never adopted the federal section-township-range grid used across most of the western United States. Instead, Texas land is described by original land grant surveys, each identified by a survey name — often the original grantee, a railroad, a colonist, or an empresario — and an abstract number assigned by the county. “H&TC RR Co. Survey, A-412” means the Houston and Texas Central Railroad Company survey, abstract 412, in whatever county the deed names. The abstract number is county-specific, so A-412 in Reagan County is a different tract than A-412 in Midland County.

Older Texas deeds also use varas — a Spanish colonial unit of measure — for metes-and-bounds calls. One vara equals roughly 33.33 inches, or about 2.778 feet. A call of “1,900 varas” is therefore about 5,278 feet, or just under a mile. If your deed reads “thence north 1,900 varas to a stake,” you will need that conversion before you can sketch the tract or compare it to a modern plat.

Oklahoma is simpler on this front. It uses the standard Public Land Survey System, so tracts are described by section, township, and range — for example, “NE/4 of Section 14, Township 6 North, Range 5 West.”

Write down every element from the deed before you open a browser: county, survey name, abstract number, section-township-range for Oklahoma tracts, acreage, and any adjoining landowners or physical monuments named in the description. You will use all of it. For a broader guide to researching mineral ownership at the county level, read Valor’s courthouse mineral research guide.

Step 1: Start With the RRC Public GIS Viewer

The Texas Railroad Commission’s public GIS Map Viewer is the fastest way to see wells, leases, and survey boundaries overlaid on aerial imagery. It is free, requires no login, and covers every county in the state. Search by county and abstract number, or zoom to the county and toggle the survey and abstract layers to see the grid of original grants. Once you find your abstract, turn on the wells layer to see permitted, producing, and plugged wells inside it — often the first confirmation that your family’s tract is or was under active development.

The RRC viewer is authoritative for wells and permits but only approximate for survey boundaries. Original surveys were run with chains and compasses in the 1800s, and modern GIS shapefiles are best-fit reconstructions, so expect the lines to drift from where a modern professional survey would place them. Use the viewer to locate the general area, then move to the appraisal district for a tighter picture.

For Oklahoma, the equivalent starting point is the Oklahoma Corporation Commission’s well records combined with the BLM’s General Land Office Records site, which lets you look up any section-township-range and pull the original federal patent. For a plain-language guide to reading permit and drilling activity once you have located your tract, read How to Read Oil and Gas Activity on Your Acreage.

Step 2: Cross-Check the County Appraisal District

Every Texas county has a Central Appraisal District that maintains parcel-level maps for property tax purposes. These maps are usually more current and more precise than the RRC survey layer because they are maintained for taxation, not historical reference. Search the appraisal district site by owner name or by abstract number. A hit will return a parcel record with acreage, a legal description, and a plat showing the tract outlined against neighboring parcels.

Two things to verify at this stage. First, confirm the acreage roughly matches the deed. A deed calling for 320 acres but an appraisal district parcel showing meaningfully less suggests either a partial conveyance somewhere in the chain of title or a boundary correction — either of which needs investigation before you rely on the map.

Second, confirm the owner name. If the appraisal district still lists a great-grandparent who died decades ago, the surface has likely been sold off but the minerals may still belong to the family, since Texas allows severed mineral estates to pass separately from surface. This is one of the most common patterns Valor’s mineral management team sees, and it is exactly why professional mineral work starts with a clean title review. If the interest appears to still be titled in a deceased relative’s name, read Inherited Minerals With No Paper Trail before proceeding.

Step 3: Use the Texas GLO and Oklahoma Federal Records for the Origin Story

The Texas General Land Office maintains the original patent files for every survey in the state, most of them scanned and searchable through the GLO’s Land Grant Database. Pulling the original patent gives you the field notes, the sketch the surveyor drew in the 1800s, and the name of the original grantee. This matters for resolving conflicts between adjoining surveys — which overlap more often than you would expect — and as the ultimate authority when a modern description references “the original H&TC survey line.”

For Oklahoma tracts, the BLM General Land Office Records site is the federal equivalent. Search by state, county, and section-township-range to pull the original homestead patent or railroad grant. Oklahoma’s Public Land Survey System grid is stable and well-documented, so once you have the correct section-township-range from the deed, locating the tract on a modern map is largely mechanical. The complication in Oklahoma is usually not finding the tract — it is untangling fractional mineral interests that have been divided across generations of heirs.

Common Traps: Duplicate Names, Obsolete Lots, and Re-Surveyed Abstracts

A few patterns cause more grief than any others.

Duplicate survey names. Texas has multiple “H&TC RR Co.” surveys because the railroad received grants across dozens of counties, and there are multiple surveys in the same name because common names appear throughout the historical record. The abstract number plus the county is what makes the description unique — never rely on the survey name alone.

Obsolete lot or block numbers. Many rural Texas subdivisions from the early 1900s were platted, sold, and then vacated or re-platted decades later. A deed referencing “Lot 7, Block 3, Sunset Acres” may point to a plat that no longer legally exists, in which case you need the original plat filed at the county clerk to reconstruct the boundaries.

Re-surveyed abstracts. When a county discovers a gap or overlap between adjoining original surveys, it sometimes creates a new abstract number for the corrected area. An old deed will reference the historical abstract. The appraisal district will show the modern one. Both describe the same ground at different points in history.

Obsolete physical monuments. Deeds that reference “the large post oak” or “the fence corner” are legally valid but functionally ambiguous if those features no longer exist. Resolving them usually requires a professional surveyor or an experienced landman. Valor’s team of certified professional landmen and Certified Mineral Managers works through these situations every week.

When to Stop and Call a Professional

The free tools above will take most owners a long way. Stop and bring in professional help when:

The survey name and abstract number do not appear in any of the databases above — this usually means the original grant predates the current county’s organization and the records are in an archived predecessor county.

The deed describes adjoining owners or monuments rather than a survey name and abstract, and those references are not resolvable from modern records.

The appraisal district shows meaningfully less acreage than the deed and the chain of conveyances is unclear.

You have located the tract but found a well or lease on it that does not match any division order or royalty check in your records.

In each of these cases, a CPL running a title search from the original patent forward is the right next step — not more time in the free databases. For context on what that process looks like and what it costs, read Attorney, CPA, Landman, or Mineral Manager: Who to Hire for What.

Valor has recovered more than $32 million for mineral owners across roughly 500,000 wells in 32 states, and most of that work started with someone holding a deed they could not read. If you have gone as far as you can on your own, Contact Valor and our team will take it from there.

Contact Valor Today

Locating a mineral tract is step one. Confirming the ownership is clean, finding out which wells are producing from it, and getting paid are steps two, three, and four. Contact Valor today for a free, no-obligation mineral asset review — our mineral management team of CPAs, CPLs, and Certified Mineral Managers will locate your tract, run the title, identify any wells or operators connected to it, and tell you what you actually own before you respond to any offer or sign any document. We handle mineral ownership verification for owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only and is not intended to provide specific recommendations or legal or tax-related advice. This blog should not be used as a substitute for competent legal advice from a licensed attorney in your state.

What Are Leases Going For? How to Benchmark a Lease Offer When Bonus Data Is Private

Posted on by Leonardo

An offer letter shows up in the mail. It lists a per-acre bonus, a royalty fraction, a primary term, and a signature line. What it does not tell you is what your neighbor received last month for comparable acreage in the same formation.

That information gap is one of the biggest challenges mineral owners face when evaluating a lease offer — and one of the most consequential. Valor has recovered more than $32 million for mineral owners, and a meaningful share of that came from lease terms negotiated correctly the first time rather than fixed after the fact. This post covers why bonus data is hard to find, where real comparables live, how to evaluate a tiered offer, and which clauses matter as much as or more than the headline number.

For a plain-language breakdown of the specific lease clauses that control long-term value, read How to Negotiate an Oil and Gas Lease first.

Why Bonus Amounts Are Not in Public Records

When a lease is recorded at the county clerk’s office in Texas or Oklahoma, the document filed is typically a memorandum of lease or the lease itself. The consideration line almost always states a nominal amount rather than the actual negotiated bonus. That is deliberate — operators do not want the bonus they paid you to become the floor for the next owner across the section line.

The practical consequence is that there is no MLS for mineral leases. You cannot pull up a state database and see what an operator paid nearby owners last quarter. Landmen know the market because they are actively making offers across an area and seeing current terms in real time. Mineral owners typically have a much narrower view.

That asymmetry is structural, and it is why the first move on any offer is not to negotiate the bonus in isolation — it is to build a broader picture of the market before you respond.

Where Real Comparables Actually Live

Useful comparables exist. They require triangulation across three sources, none of which will hand you a bonus number directly.

Recorded leases at the county clerk. The bonus amount is typically not disclosed, but the royalty fraction, primary term, depth clauses, Pugh clause language, shut-in provisions, and post-production cost language are all there. If recently recorded leases in your section consistently show a stronger royalty position or shorter primary term than the offer in front of you, that is a meaningful signal worth acting on. For a guide to pulling county records yourself, read Valor’s courthouse mineral research guide.

OCC pooling orders in Oklahoma. When an operator force-pools a section under the Oklahoma Corporation Commission, the resulting order documents the bonus and royalty alternatives established through the pooling process. These are public. Pulling recent pooling orders in your township and range gives you a defensible bonus-and-royalty reference point for that specific formation — the closest thing to a published price sheet that exists in either state. For context on how force pooling works and what it means for unleased owners, read Forced Pooling in Oklahoma vs. Texas.

RRC filings in Texas. Railroad Commission permit and completion filings show who is drilling, where activity is concentrated, and how development is progressing near your tract. If an operator has filed several horizontal permits within a mile of your acreage in recent months, the offer in your hand is part of an active leasing campaign — and the bonus is negotiable. Permit density is a leverage indicator, not a price indicator, but it tells you which side of the table has urgency. For a plain-language guide to reading permit and drilling activity near your acreage, read How to Read Oil and Gas Activity on Your Acreage.

Building this picture takes time and a working knowledge of what to look for. It is the work Valor’s mineral management team does before any client responds to an offer.

How to Think About a Tiered Offer

Operators frequently present three options on a single offer letter. The structure is almost always the same: a higher bonus paired with a lower royalty, a middle option, and a lower bonus paired with a higher royalty. The bonus is guaranteed cash at signing. Royalty is a percentage of production revenue that only pays if and when a well is drilled and produces.

A real-world example from an active Anadarko Basin leasing campaign this week: a landman presented three options at one thousand dollars per acre at three-sixteenths royalty, eight hundred dollars per acre at one-fifth royalty, and one hundred dollars per acre at one-fourth royalty. The instinct is to circle the highest bonus. That can be a mistake if the long-term royalty economics are ignored.

The real question is: how much production, over what timeframe, does it take for the higher-royalty option to overtake the higher-bonus option? The answer depends on unit size, your net acre position inside that unit, expected production, commodity prices, and timing. There is no universal break-even, but the math is workable using realistic production assumptions for the area.

If drilling is relatively likely based on nearby permit activity, the higher-royalty option will often create substantially more long-term value than the larger upfront bonus. If the acreage is speculative with limited nearby development, the guaranteed upfront consideration may weigh more heavily in the decision. You cannot make that call by looking at the bonus number alone. For help converting your net mineral acres to net royalty acres so you can run the economics accurately, read Net Mineral Acres vs. Net Royalty Acres: How to Read an Offer Correctly.

Clauses That Move More Money Than the Bonus

The bonus is the number that gets circled on the offer letter. It is rarely the number that determines what the lease is worth over its life. Four clauses deserve equal or greater attention.

Option to extend. A primary term with an option to extend at the same bonus per acre gives the lessee additional time to develop under terms negotiated at the outset. Owners should either strike the option, price it at a meaningful premium, or shorten the primary term in exchange for removing it.

Paid-up versus delay rental. A paid-up lease provides the agreed consideration at signing and requires no annual payments to maintain the lease during the primary term. A delay-rental lease requires periodic payments to keep the lease in force. Paid-up structures are more common today, but confirm which structure is being offered before comparing headline bonus numbers across competing offers.

Cost-free royalty language. Post-production costs — gathering, compression, treating, transportation, and marketing — can materially reduce royalty economics depending on lease language and applicable law. On gas-weighted wells, significant deductions can mean a higher royalty subject to full costs pays less than a lower cost-free royalty. For a full explanation of how sales-point language produces legal deductions even under a clause that says no deductions, read Cost-Free Royalty Clauses: Why You Still See Deductions on Your Check.

Pugh clause and depth severance. Without appropriate acreage and depth-release provisions, production from a limited portion of the leased premises can hold substantially more acreage or depth than the owner expected at signing. These are the terms Valor’s lease negotiation team reviews on every client offer before a response is made.

What a Real Benchmarking Process Looks Like

Valor manages roughly 500,000 wells across 32 states and 13 major basins. When an offer lands on a client’s tract in the Permian, the SCOOP/STACK, or the Haynesville, we are often already seeing recent lease activity, permit pace, and pooling terms in that area. That visibility provides the context the operator is already working from.

A defensible benchmarking process reviews recently recorded leases in the section and adjoining sections, recent OCC pooling orders for Oklahoma tracts, RRC permit and completion activity for Texas tracts, the economics of any tiered offer against realistic production assumptions, and the lease form itself for cost-free royalty language, Pugh clauses, extension options, and shut-in provisions. Done properly, it usually changes the outcome.

An offer letter is a starting position, not a final price. If you are holding one now and have no way to benchmark it, Contact Valor — our mineral management team can pull the comparables and review the lease before you sign. For owners who want to evaluate whether they should lease at all before responding, read Before You Sell or Lease.

Contact Valor Today

An offer letter is a starting position. Understanding the surrounding market, development activity, royalty structure, and lease language before responding can materially affect the outcome. Contact Valor today for a free, no-obligation review — our lease negotiation team will pull available comparables, evaluate tiered offer economics, and mark up the lease form for cost-free royalty language, Pugh clauses, and extension options before you sign anything. We handle lease offers and lease negotiations for mineral owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only and is not intended to provide specific recommendations or legal or tax-related advice. This blog should not be used as a substitute for competent legal advice from a licensed attorney in your state.

Royalties in Suspense: The Letter That Starts the Clock

Posted on by Leonardo

Valor has recovered more than $32 million in royalty proceeds for mineral owners — and a meaningful share of that money was sitting in suspense at an operator, waiting on a letter that never got written. If your royalty payments have stopped, slowed, or never started on a well you know is producing, there is a real chance your interest is in suspense. This post explains what suspense actually means, why operators hold funds, how to kick off the certified-letter process, and why getting all the way to a full recovery usually requires more than a single letter.

What suspense actually means

Suspense is an accounting status, not a penalty. When an operator cannot pay a mineral owner with confidence, they park the money in a suspense account and continue accruing your share of proceeds month over month. The funds are still yours. The operator is holding them because paying the wrong party — or paying the right party at the wrong address, or paying without a valid W-9 — creates a larger problem than not paying at all.

Common reasons an interest lands in suspense: an unrecorded death in the chain of title, a divorce decree that never made it to the county clerk, a missing or expired W-9, a bad mailing address after uncashed checks are returned, a title dispute between heirs, unrecorded assignments, or a division order the owner never signed and returned. On newly drilled wells, suspense often reflects title curative that is still open — the operator’s landman flagged a gap and revenue accounting will not release funds until it clears.

Suspense is usually resolvable. It is almost never resolved automatically. Across the more than 500,000 wells in Valor’s managed portfolio, the pattern is consistent: the interests that get paid fastest belong to owners who put their request in writing and follow up. If you believe funds may already be sitting in suspense or have escheated to the state, start with Valor’s unclaimed mineral funds guide before you draft the letter.

Why the certified letter matters more than the phone call

Both Texas and Oklahoma have statutory frameworks governing how quickly operators must pay royalties after first production, and both provide for statutory interest on late-paid proceeds. The specifics — timing windows, interest rates, and notice requirements — vary by state and by the reason for the delay. Any owner planning to pursue a formal claim should confirm current statutory language with qualified counsel.

Here is the part that catches owners off guard: those remedies generally require the owner to make a written demand. A phone call to owner relations does not create a record you can later prove. A certified letter does. The certified mail receipt, the return receipt card, and a dated copy of your letter are the paper trail that establishes when the operator was formally notified, what you asked for, and how long they have taken to respond.

The certified letter also forces the file onto someone’s desk. Verbal inquiries get logged. Written demands with tracking numbers get escalated to revenue accounting, land, and sometimes legal. That escalation is exactly what you want — and it is a step most owners can take on their own. What comes after the letter is where things get more complicated.

What to put in the letter — and where the checklist gets hard

A good demand letter is short, specific, and unambiguous. Vague letters get vague responses. Include at minimum:

Your identifying information. Full legal name, current mailing address, phone number, email, and Social Security number or EIN — or a statement that a current W-9 is enclosed.

The operator’s information. Operator name and your owner or interest number if you have one from a prior check stub or division order.

The well and property information. Well name, API number, county and state, lease name, and if you know them, the section, township, and range or the abstract and survey.

Your interest. The nature of your interest — royalty, overriding royalty, non-participating royalty, or working interest — and your decimal if known. If you are not sure what your decimal should be, Valor’s royalty decimal calculator is a useful starting point.

A clear written demand. A statement that you are the rightful owner, that you believe proceeds are being held in suspense, and that you are making a formal written demand for release of all suspended funds and for regular payment going forward.

Supporting documents. A copy of the deed, probate order, divorce decree, assignment, or other instrument that establishes your ownership. A signed W-9. A signed division order if one was previously sent to you.

A request for documentation. Ask the operator to identify in writing any specific title or documentation defect they believe is preventing payment so you can cure it.

If any of those items are missing — a decimal you cannot verify, a deed you cannot locate, a probate you never completed, or a title gap you cannot explain — that is exactly where professional help makes the difference between a letter that produces results and one that gets filed away. Valor’s mineral management team runs this diagnostic every day. The letter is the starting gun. Everything behind it is the race.

Send the letter certified mail, return receipt requested, to the operator’s designated address for payment inquiries — usually printed on the back of a check stub or on the division order. If you cannot find that address, use the address on file with the Texas Railroad Commission or the Oklahoma Corporation Commission. Keep the green return receipt card when it comes back. Scan the whole packet before mailing.

Suspended funds vs. underpayment claims — do not confuse them

Suspended funds are proceeds the operator has calculated, accrued, and is holding for you. They generally do not expire on their own. Once title, address, and W-9 issues are cleared, those funds get released — often in a single catch-up check covering many months or years.

Underpayment claims are different. An underpayment is money the operator paid, but paid incorrectly — wrong decimal, wrong price, improper deductions, missed volumes, or paid to the wrong party. These claims are subject to state statutes of limitation that vary by state and theory of recovery. Every month you wait, the oldest month of a potential underpayment claim rolls closer to the edge of what may be recoverable.

If your certified letter produces a runs history, review it against production reported to the Texas Railroad Commission or Oklahoma Corporation Commission for the same well and months. Compare volumes, prices, and your decimal. Discrepancies that show a consistent pattern are what underpayment claims are built on — and building one correctly requires someone who knows what to compare and how to document it before the limitations window closes. For context on how to read your check stub against public production data, read Why Your Royalty Check Suddenly Stopped and Why Is My Royalty Check So Small?

The $32 million Valor has recovered includes both workstreams: suspended funds released by written demand, and underpayment claims documented against public production records before the limitations period closed. The first step on both is the same. Getting all the way to recovery on either one is not.

What to do if the operator does not respond

Operators are expected to respond to written demands. Many do, promptly. Some do not — because the file is genuinely complicated, because owner relations is understaffed, or because the operator has changed hands and records are in transition. If 30 days pass with no substantive response, escalate in this order:

Send a second certified letter referencing the first, attaching the return receipt, and noting that statutory interest may be accruing.

Contact the operator’s designated agent for service of process, listed with the Texas Railroad Commission or the Oklahoma Corporation Commission. This puts the letter in front of a corporate officer, not a queue.

File a complaint with the Texas Railroad Commission or the Oklahoma Corporation Commission. These agencies do not adjudicate private royalty disputes, but complaints get logged and operators notice.

Engage qualified counsel. Texas and Oklahoma both have provisions that may allow recovery of attorneys’ fees on certain payment claims after proper written notice — one more reason the certified letter matters from the beginning.

If the operator is in bankruptcy, file a proof of claim to preserve your position.

This escalation sequence is something most owners can start. But navigating it fully — knowing which escalation step fits which operator response, building the documentation package for a formal claim, and pursuing underpayment recovery before the statutory window closes — is where most owners reach the limit of what they can do alone. Valor’s mineral management team handles this work daily across 32 states and 13 basins. The certified letter gets you on the record. Getting paid is a different job.

Contact Valor Today

Sending the certified letter is a step you can take today. Getting the operator to release everything owed — suspended funds, back royalties, and statutory interest — is where Valor comes in. Contact Valor for a free, no-obligation review — our mineral management team of CPAs, CPLs, and Certified Mineral Managers will identify what is holding your funds, build the documentation package that operators and state regulators respond to, and pursue recovery through every available channel. We handle royalty management and suspense releases for owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only and is not intended to provide specific recommendations or legal or tax-related advice. This blog should not be used as a substitute for competent legal advice from a licensed attorney in your state.

Two Division Orders for One Well: What It Means and What to Check

Posted on by Leonardo

You open a division order for a new horizontal well on your tract, run the decimal yourself, and the number does not match. Or you receive two division orders for what appears to be the same well.

Neither is necessarily a mistake. In many cases the difference comes from how production is allocated across multiple units or tracts — a second calculation step the standard acreage formula does not include.

This post walks through allocation wells and multi-unit horizontals, shows a simplified 60/40 example, and points to the Texas and Oklahoma records that help you understand how production was allocated so you can verify your decimal before you sign. For the foundational decimal formula on a standard pooled unit, read How to Calculate Your Royalty Decimal Interest first.

When the standard acreage formula is not enough

For a standard pooled or spaced unit, the decimal calculation is generally straightforward: your net mineral acres in the unit, divided by total unit acres, multiplied by your royalty rate. A 10-acre interest in a 640-acre unit at a 3/16 royalty produces a decimal of 0.00292969. That basic calculation is covered in Valor’s royalty decimal calculator.

Certain multi-unit and allocation-style horizontal wells add another layer to that formula. A conventional horizontal well contained within a standard pooled or spaced unit can still use the familiar acreage-based calculation. The math becomes more complicated when a well’s productive interval extends across separately treated units or tracts and production must be allocated among them.

In a lateral-length allocation scenario, if 60% of the productive interval sits under Section A and 40% sits under Section B, 60% of the well’s production may be allocated to Section A and 40% to Section B. An owner’s unit decimal would then be adjusted by the allocation factor applicable to that unit. Overlooking that additional step is one of the most common reasons an owner cannot reproduce the decimal shown on a division order.

A worked 60/40 example

Say you own 20 net mineral acres in Section A. Section A is a 640-acre unit. Section B, immediately south, is also 640 acres. A horizontal well produces across both units, with 60% of the productive interval attributed to Section A and 40% attributed to Section B. Your lease royalty is 3/16 or 0.1875.

Here is a simplified example of how a 60% allocation factor affects the decimal:

Step 1. Calculate your unit decimal in Section A:
20 ÷ 640 × 0.1875 = 0.00585938

Step 2. Apply Section A’s 60% allocation factor:
0.00585938 × 0.60 = 0.00351563

The resulting decimal is 0.00351563, not 0.00585938. If you calculated only the first step, the difference is almost certainly an allocation factor being applied — not an operator error.

If you also own minerals in Section B, you will likely receive a separate division order for that unit. The decimal for Section B would be calculated independently using the ownership, royalty rate, unit information, and allocation factor applicable there.

The same general concept applies when a multiunit well crosses three units. In Oklahoma, approved allocation factors generally reflect the well’s completion interval across the affected units. Texas allocation and production-sharing wells require a review of both regulatory filings and the governing agreements, so the governing documents — not just the RRC filing — control the royalty calculation.

Where to look in Texas

In Texas, Railroad Commission records are the right starting point for understanding how the well was permitted and which tracts were associated with it — but they do not by themselves determine how your royalty must be calculated. Lease terms, pooling authority, production-sharing agreements, and other governing documents may also affect the answer.

Start with the W-1 drilling permit application, which provides information about the well location and permitted wellbore. Review the full W-1 permit packet, horizontal wellbore information, associated plat, and P-16 acreage designation to understand the well path and the tracts or acreage associated with the well.

For an allocation or production-sharing well, compare those filings against the governing lease, pooling, or production-sharing documents before assuming that a particular footage percentage is also your royalty allocation percentage. The P-16 acreage designation shows the tracts and acreage associated with the well but should not be treated by itself as proof of the royalty allocation required under your lease.

RRC records can generally be searched by API number, lease name, or operator. If your division order or check detail lists the API number, that is the fastest place to start. If the permit records, well path, and allocation reflected in your division order do not appear to reconcile, send the question to the operator in writing before you sign anything.

For a broader guide to reviewing public records related to mineral ownership, read Valor’s courthouse mineral research guide.

Where to look in Oklahoma

Oklahoma handles multiunit horizontals through a formal spacing, pooling, and multiunit-well framework administered by the Oklahoma Corporation Commission.

For a multiunit horizontal well, start with the OCC multiunit horizontal well order. The order identifies the affected units and establishes or approves the allocation factors used to allocate production and proceeds among them. Oklahoma law generally calculates each affected unit’s allocation factor using the portion of the completion interval located within that unit compared with the well’s entire completion interval, although the Commission may approve adjustments when necessary.

Form 1002A, the Completion Report, provides additional well-completion information. Associated plats and well records can help you understand the completed lateral. Pooling orders may also be relevant if an owner’s working interest was subject to forced pooling, but they are separate from the OCC order approving the multiunit horizontal well.

If you cannot reconcile your ownership with the applicable OCC orders and well records, investigate rather than assuming the discrepancy is harmless. A missed tract in a pooling order is one of the most common sources of missing royalty payments. For more context on Oklahoma pooling and how it differs from Texas, read Forced Pooling in Oklahoma vs. Texas.

What to do when multiple division orders show up

If you receive two or three division orders associated with what appears to be the same well, do not assume one is a duplicate. Multiple documents typically reflect ownership in different units, though a second document could also be an amended or corrected division order superseding the first.

Work through this checklist before you sign either one:

Confirm the API number. If the API is the same on multiple documents, compare the remaining property and unit information to understand why separate division orders were issued.

Compare the unit or legal descriptions. Review the section-township-range information, unit name, or other property description on each document. They should differ if the lateral crosses multiple units.

Recalculate each decimal independently. Use the acreage, royalty rate, and allocation information applicable to that specific unit. Do not assume the two decimals will have a predetermined mathematical relationship to one another.

Review the supporting records. In Texas, review the W-1 permit packet, P-16, and related agreements where applicable. In Oklahoma, review the multiunit horizontal well order and relevant completion records.

Ask questions before signing a decimal you cannot reconcile. A discrepancy does not automatically mean the operator made an error, but you should understand what is driving the difference before you sign. For more guidance on checking the math behind your division order, read How to Calculate Your Royalty Decimal Interest.

If you received a division order with an unfamiliar format and are not sure what type of document you are holding, read Division Order, Lease Offer, or Buyout? How to Read the Letter About Your Mineral Rights before you respond to anything.

Contact Valor Today

Division order math becomes more complicated when a horizontal well produces across multiple units or tracts, and the difference carries through to every royalty payment. Contact Valor today for a free, no-obligation review — our royalty management team will review your decimal against the applicable well, unit, and allocation records, pull the underlying RRC or OCC filings, and help determine whether the division orders you received are consistent with your ownership and the available well information. We handle division order verification and decimal review for mineral owners across Texas, Oklahoma, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only and is not intended to provide specific recommendations or legal or tax-related advice. This blog should not be used as a substitute for competent legal advice from a licensed attorney in your state.

Net Mineral Acres vs. Net Royalty Acres: How to Read an Offer Correctly

Posted on by Leonardo

In the past 36 months, Valor has recovered more than $32 million for mineral owners — and a meaningful share of that came from owners who signed leases or accepted offers priced against a unit they did not fully understand. The single most common source of confusion is the difference between net mineral acres and net royalty acres. They sound like the same thing. They are not.

One measures the dirt you own. The other measures the income stream that dirt produces, normalized so buyers can compare a tract in Reeves County against a tract in Grady County on the same yardstick. If you have an offer letter in front of you quoting a price per NRA, this post will show you how to translate it back to what you actually own — and what to check before you sign anything.

What net mineral acres actually measure

Net mineral acres is the plainest number in the mineral world. If you own 100% of the minerals under a 40-acre tract, you own 40 net mineral acres. If you own an undivided 25% interest under that same 40-acre tract, you own 10 net mineral acres. The formula is gross acres multiplied by your undivided mineral interest.

NMA does not care about your lease. It does not care whether you are leased at 1/8, 3/16, 1/5, or 1/4. It does not care whether the tract is producing, held by production, or completely unleased. It is a static measurement of the physical mineral estate you own — the same number today as it will be in ten years, unless you buy, sell, or inherit into a different position.

That stability is why NMA is the right unit for title work, probate, tax rendition, and estate planning. It is also why NMA on its own is a poor unit for pricing an offer. Two owners with identical 10 NMA positions can have wildly different economic value depending on how their minerals are leased. If you have not yet confirmed your NMA from county deed records, Valor’s courthouse mineral research guide walks through how to do that by state.

What net royalty acres actually measure

Net royalty acres is a normalized unit. It exists because buyers need one number that lets them compare a tract leased at a 1/8 royalty in a legacy East Texas field to a tract leased at 1/4 in the Midland Basin without doing algebra on every deal. The industry standard benchmark is a 1/8 royalty — the historical default going back a century.

The formula is: NRA = NMA × (royalty rate ÷ 1/8) or equivalently NRA = NMA × royalty rate × 8.

Work through the four examples that matter most:

10 NMA leased at 1/4 royalty: 10 × (0.25 ÷ 0.125) = 10 × 2 = 20 NRA
10 NMA leased at 1/8 royalty: 10 × (0.125 ÷ 0.125) = 10 × 1 = 10 NRA
10 NMA leased at 3/16 royalty: 10 × (0.1875 ÷ 0.125) = 10 × 1.5 = 15 NRA
10 NMA leased at 1/5 royalty: 10 × (0.20 ÷ 0.125) = 10 × 1.6 = 16 NRA

Same 10 acres of dirt in every case. The revenue interest under each barrel produced, however, ranges from 10 to 20 NRA. A buyer paying $10,000 per NRA would offer $100,000 for the 1/8 position and $200,000 for the 1/4 position — and both offers would be internally consistent from the buyer’s point of view.

This is also why royalty rate matters so much at the lease stage. The royalty fraction you negotiate today determines your NRA count for the life of every well drilled under that lease. For a full breakdown of why royalty rate beats bonus in the long run, read How to Negotiate an Oil and Gas Lease.

Why offer letters quote price per NRA — and why that matters to you

Almost every serious mineral buyer — private capital, royalty aggregators, publicly traded royalty trusts — underwrites in dollars per NRA. They do this because NRA is directly proportional to the barrel and MCF revenue stream a buyer will collect. A tract’s NRA count multiplied by projected production per acre and commodity price gives them a discounted cash flow input. NMA does not.

The practical consequence for a mineral owner: if you receive an offer that says “$8,500 per net royalty acre,” you cannot evaluate it until you know your NRA count — which means you need both your NMA and your royalty rate. If your family records show 40 NMA and your lease is at a 3/16 royalty, that is 60 NRA and the offer is $510,000, not $340,000.

This is where owners get hurt. If an owner sees “$8,500 per acre” and mentally applies it to their 40 NMA, they anchor to $340,000 and may accept an offer well below what the buyer was actually prepared to pay for their 60 NRA position. For context on what buyers already know about your tract before they send that letter, read You Just Got an Offer for Your Minerals. Here’s What the Buyer Already Knows.

The reverse problem also occurs. An owner with a 1/8 lease who assumes the buyer’s per-NRA quote applies to NMA overestimates the offer and pushes back on a fair number. Either way the mismatch between the unit the buyer is using and the unit the owner is thinking in creates avoidable friction and money left on the table. Valor’s mineral management team reviews offer letters routinely and translates them into both units before a client responds. If you have received an offer and want to understand whether the letter is a division order, lease offer, or purchase offer before doing the math, read Division Order, Lease Offer, or Buyout? How to Read the Letter About Your Mineral Rights.

Lease offers use the same math — with higher stakes

The NMA versus NRA distinction is not limited to purchase offers. It runs through lease bonus negotiations too, but with a twist: the royalty rate is the thing being negotiated, so the NRA figure is a moving target during the discussion.

Consider 20 NMA in a Reagan County section. A landman offers $2,000 per acre bonus at a 3/16 royalty. That is $40,000 in bonus for 30 NRA of long-term revenue exposure. A competing landman offers $1,500 per acre bonus at a 1/4 royalty. That is $30,000 in bonus for 40 NRA. The bonus is lower but the NRA count is 33% higher — and over a typical horizontal well’s producing life, the incremental royalty stream can dwarf the bonus differential many times over.

Owners who evaluate lease offers only on the front-end bonus per NMA systematically undervalue the royalty rate. This is one of the most expensive mistakes in the entire mineral owner playbook and it compounds every year the well produces. Across the 500,000 wells Valor manages, the pattern is consistent: royalty rate drives lifetime revenue far more than bonus does.

A simple checklist before you sign anything

Before you respond to a purchase offer or a lease proposal, work through these five items:

Confirm your NMA from title. Do not rely on family memory or an old division order. Pull the deeds and calculate gross acres multiplied by your undivided interest. If title is unclear or the paper trail is broken, read Inherited Minerals With No Paper Trail before you respond to anything.

Confirm the royalty rate on record. For a purchase offer this is the royalty in your existing lease. For a lease offer this is what is on the table. If you are not sure what your current royalty rate is, Valor’s royalty decimal calculator can help you work backward from your check stub.

Convert to NRA using NMA × royalty rate × 8. Write both numbers down side by side before you read the offer price.

Ask the counterparty which unit their price applies to — in writing. “/acre“isambiguous.“/acre” is ambiguous. “/acre”isambiguous.”/NRA” or “$/NMA” is not. The distinction can be worth tens of thousands of dollars on a modest interest.

Compare against recent arm’s-length transactions in the same county and formation. A fair $/NRA in the Midland Basin is not a fair $/NRA in the SCOOP and neither is a fair $/NRA in the Haynesville. Valor manages minerals across 32 states and 13 major basins and can benchmark any offer against what comparable acreage is actually trading for. Start at Before You Sell or Lease for the full framework.

Contact Valor Today

Getting NMA and NRA right is the difference between negotiating from your buyer’s spreadsheet and negotiating from your own. Contact Valor today for a free, no-obligation review — our mineral management team will translate your offer into both units, benchmark it against comparable transactions in your county and formation, and tell you whether the number on the table lines up with what your minerals are actually worth. We review lease offers and purchase offers for owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only and is not intended to provide specific recommendations or legal or tax-related advice. This blog should not be used as a substitute for competent legal advice from a licensed attorney in your state.

When a Co-Owner of Your Minerals Passes Away

Posted on by Leonardo

Valor has recovered more than $32 million for mineral owners, and a meaningful share of that work has involved families navigating mineral ownership after the loss of a loved one. During an already difficult time, it is understandable for title updates and operator paperwork to fall behind. Unfortunately, when that happens, royalty payments may be placed in suspense until ownership records are brought up to date.

If you own minerals with a spouse, sibling, parent, or business partner, the form of ownership on your deed determines what happens to the interest when one co-owner passes away. It also affects what the surviving owner or family may need to do before county records and royalty payments can be updated.

This post walks through the three ways minerals are commonly co-owned in Texas and Oklahoma, what generally happens under each form of ownership, and the documents that may need to be recorded to keep title records accurate and payments moving.

The three ways minerals are commonly co-owned

Before determining what happens after a co-owner’s death, the first step is understanding how the interest was held. In Texas and Oklahoma, mineral interests are typically co-owned in one of three ways, and each has different consequences for succession.

Tenancy in common is the default. If a deed conveys minerals to two or more people without survivorship language, they generally hold as tenants in common. Each owner has a distinct fractional share they can sell, lease, devise by will, or pass through intestate succession. When a tenant in common passes away, their share does not automatically transfer to the other co-owners. Instead, it generally passes to their heirs or devisees through probate or an heirship proceeding.

Joint tenancy with right of survivorship (JTWROS) works differently. Upon the death of one joint tenant, that owner’s interest passes automatically to the surviving joint tenant or tenants outside of probate. In Texas, JTWROS is not presumed — it must be created by a written agreement that specifically states survivorship intent under Texas Estates Code section 111.001. Oklahoma is similar: survivorship language must be explicit in the granting instrument. If the deed simply says “to John and Mary Smith,” that generally creates a tenancy in common rather than JTWROS.

Community property with right of survivorship is Texas-specific. Available to married couples, it combines community property tax treatment — including the potential for a double step-up in basis at the first spouse’s death — with automatic survivorship, and it must be created by a written survivorship agreement that meets statutory requirements. Oklahoma is not a community property state, so this form does not apply there.

Because small differences in deed language can have significant consequences, it is important to review the recorded instrument rather than assume how an interest will pass. If you have not confirmed what your deed says or need help locating it, Valor’s courthouse mineral research guide walks through how to find it by state.

What actually transfers at death under each form

Consider a husband and wife who each own an undivided one-half of the minerals under a 320-acre tract in Reeves County. If the husband passes away, what happens to his interest depends entirely on how the deed was written.

If they held the minerals as tenants in common, the wife continues to own her original one-half interest. The husband’s one-half becomes part of his estate. If he had a will, it generally passes according to the terms of that will. If he died intestate and the minerals were his separate property, Texas descent rules may result in the surviving spouse sharing ownership with children or other family members.

If they held the minerals as JTWROS or community property with right of survivorship, the surviving spouse generally becomes the owner of the deceased spouse’s interest automatically. Probate may not be required for that transfer. Even so, the operator does not automatically know that a death has occurred, and the county records will continue to show both owners until the appropriate documentation is recorded.

This is an easy step to overlook, especially while a family is managing everything that follows the loss of a loved one. A surviving owner may reasonably assume that survivorship language means there is nothing further to do. In practice, operators and county records generally still require documentation before ownership records and royalty payments can be updated.

Valor’s mineral management team regularly helps families work through these situations. Addressing the documentation as early as reasonably possible can make the process more straightforward and help reduce payment delays. For more context on how suspense works and how funds may be released, read Why Your Royalty Check Suddenly Stopped.

Documents you may need to record

The specific paperwork depends on the form of ownership and whether the estate goes through probate. Below is a practical overview of some of the most common scenarios.

For JTWROS or community property with survivorship in Texas: record a certified copy of the death certificate in the deed records of every county where the minerals are located, along with any required affidavit of survivorship identifying the specific deed that created the survivorship interest — including book and page or instrument number — the legal description of the minerals, and the surviving owner. The operator may also request copies of the recorded documents, a W-9 in the survivor’s name, and information needed to update the division order.

For tenancy in common with a will: probate may be required before the deceased owner’s interest can be transferred. Once the will is admitted to probate and the appropriate court documents are available, certified copies may need to be recorded in the county deed records. If the executor conveys minerals by executor’s deed, that document should also be recorded. Operators will generally require the relevant recorded documents and new W-9s for each beneficiary.

For tenancy in common where the decedent died intestate: in Texas, an affidavit of heirship may be used in some circumstances to establish family history and heirship. In Oklahoma, certain estates may qualify for procedures such as a summary determination of heirship under 58 O.S. section 393, while others may require formal probate. Once heirship is established, the appropriate documents should be recorded and provided to the operator along with new W-9s and updated contact information for each heir.

For a broader discussion of probate and heirship when minerals are located in another state, read Inherited Minerals in a State You Don’t Live In.

In every case: update the property tax rolls with the appropriate county appraisal district, notify every operator paying on every well — not just the largest one — and keep certified copies of important ownership documents in a place where family members or future representatives can find them. One common source of delays is updating ownership with one operator while unintentionally overlooking others.

Royalty suspense and what families can do

Every operator has a slightly different suspense policy, but the general process is similar. Once an operator receives notice that an owner has passed away, it may place royalty payments in suspense until it receives sufficient documentation establishing who is legally entitled to receive the funds.

The exact requirements vary, but operators commonly request proof of death, documentation showing who inherited the interest, and a new W-9 for each new payee. During that period, payments may continue to accrue even though they are not being distributed. Depending on the size of the interest and the length of the delay, the balance can become significant.

In Texas, certain unclaimed mineral proceeds may eventually be reported to the state under Property Code Chapter 74. If you believe royalties may already have been remitted as unclaimed property, search the relevant state’s unclaimed property database before contacting the operator.

To help minimize delays, families can often address the county-recording and operator-notification processes at the same time, once the necessary legal documents are available.

Advance planning can also make these transitions easier for loved ones. If you want automatic survivorship with a spouse, an attorney can help determine whether a written survivorship agreement that complies with Texas Estates Code section 111.001 or the applicable Oklahoma requirements is appropriate. If you want your share to pass to specific children or other beneficiaries, a transfer-on-death deed may be an option in some circumstances. Texas allows TOD deeds for real property, including minerals, under Estates Code Chapter 114.

For owners with meaningful interests, a revocable living trust may also help avoid probate and provide greater continuity through generational transitions.

None of this is legal advice — mineral ownership, probate, and succession laws vary by state and by individual circumstances, so owners and families should work with an oil and gas or estate-planning attorney licensed in the relevant state.

The broader takeaway is simple: thoughtful planning during an owner’s lifetime can reduce uncertainty and administrative burden for loved ones later.

Contact Valor Today

Managing mineral interests after the loss of a family member can add an unfamiliar administrative burden at a time when families already have a great deal to handle.

If you are unsure what documents need to be recorded, whether royalties have been placed in suspense, or whether operator and county records reflect the correct ownership, contact Valor for a free, no-obligation review. Our mineral management team can help you understand what your specific situation may require, identify suspended royalties, and work through the ownership updates needed by operators and county records.

Valor works with owners and families managing inherited mineral rights and co-ownership title matters across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only and is not intended to provide specific recommendations or legal or tax-related advice. This blog should not be used as a substitute for competent legal advice from a licensed attorney in your state.