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Category: Mineral Rights

Understanding mineral rights ownership, acquisition, valuation, and transfer processes.

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.

Cost-Free Royalty Clauses: Why You Still See Deductions on Your Check

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 a single misunderstood contractual mechanic: where the operator legally sets the point of sale for royalty calculation. If your lease has a cost-free, no-deductions, or no-expenses royalty clause and you are still seeing deductions on your check stub, you are not necessarily being cheated. In most cases you are being paid according to a lease definition you may not have negotiated tightly enough.

This post explains the sale-point relocation mechanism, why it produces legal deductions under an ostensibly cost-free clause, and what mineral owners in Texas, Oklahoma, and across the other states Valor works in should do about it. For the foundational explanation of what post-production deductions are and how at-the-wellhead versus gross proceeds language controls them, read Why Is My Royalty Check So Small? Post-Production Deductions, Explained first.

What a cost-free royalty clause actually protects

A cost-free royalty clause — sometimes titled “no deductions,” “no post-production costs,” or “gross proceeds” — says the operator cannot deduct costs from your royalty before it is calculated. On its face it sounds absolute. In practice it protects royalty only up to a specific point in the production stream. That point is called the point of sale, and it is defined either explicitly in the lease or implicitly by the operator’s marketing arrangement.

Here is the mechanic that trips up most mineral owners. Royalty is calculated as a percentage of the value of production at the point of sale. A cost-free clause says the operator absorbs the costs required to make the product marketable and get it to the sale point. It does not say the operator absorbs costs incurred after the sale point. Those downstream costs — gathering fees paid to a midstream pipeline, compression at a booster station, processing at a gas plant, transportation to a downstream index hub — are typically netted out of the sales price, which lowers the number your royalty percentage is applied against.

This is why two owners with identical “cost-free” language can receive materially different net royalties from the same well. The difference is not the clause. The difference is where the operator drew the sale-point line. Valor’s mineral management team sees this pattern across the 500,000 wells we monitor: identical-looking lease language, radically different net proceeds.

How operators legally relocate the sale point

Operators have three common ways to set the sale point at or near the wellhead — each defensible under most lease forms and applicable case law in producing states.

Wellhead sale to an affiliate marketer. The producer sells the raw stream to a marketing subsidiary at the wellhead for an index-minus price. The index-minus deduction reflects everything the affiliate will spend downstream. That deduction is baked into the sales price, not itemized on the check stub. Your royalty is calculated on the depressed wellhead price.

Sale at the tailgate of a gathering system. The gathering fee is treated as a pre-sale cost the operator absorbs, but processing, treating, and transportation are treated as post-sale. Whether these are pre-sale or post-sale is a factual determination courts have gone both ways on. Texas courts generally hold that post-production costs are deductible unless the lease expressly prohibits them. Oklahoma’s implied covenant to market has historically been interpreted more favorably toward owners, but the specific lease language still controls in both states.

Btu-adjusted sale after processing. The operator sells residue gas and NGLs separately after processing, then allocates costs back against each stream. The check stub shows deductions labeled PROC, T&F, or FUEL — and under many lease forms these are legally supportable even where the lease says “no deductions,” because the sale of the processed products is defined as a separate downstream sale.

None of this is fraud. It is contract mechanics playing out as the lease was drafted. Which is precisely why the fix is contractual, not adversarial.

Reading your check stub for sale-point clues

The line items on your check stub are the fingerprints of the operator’s sale-point definition. A few patterns to watch for:

GPT / GATH — gathering and transport. If your lease says cost-free and you still see this, the sale point sits downstream of the gathering system.

COMP — compression. Deductibility depends on whether it is required to make the gas marketable, which is typically pre-sale, or to reach a better market, which is typically post-sale.

DEHY / TREAT — dehydration and treating. Usually required to make gas marketable and often absorbed under a strong cost-free clause, but not always.

PROC / P&F — processing and fractionation. Under a wellhead-sale definition, generally deductible.

T&F / TRANS — transportation and fuel to the market hub. Almost universally treated as post-sale.

A useful diagnostic: total your monthly deductions and divide by gross value. If the ratio consistently exceeds 20% on gas royalty, the sale point is set well upstream of the market and the cost-free clause is doing far less work than the language implies. Two patterns Valor has seen recently: a 28% purchaser-paid deduction on a 25% no-expenses lease, and a 40%+ gathering charge on Oklahoma horizontal wells. Both are within ranges that warrant a lease-language review. For a full guide to reading every line on your check stub, read How to Read Your Royalty Check Stub Line by Line.

What language actually moves the sale point downstream

If you have leverage at lease negotiation or renewal, the clause language matters more than the clause title. “No deductions” alone is insufficient. Strong protective language does three things at once.

Define the point of sale explicitly. Not at the wellhead, but at the tailgate of the processing plant, at a named interstate pipeline delivery point, or at a specific published index hub such as Henry Hub or Waha. If the lease says royalty is calculated on proceeds at the index price, downstream costs cannot be netted out because the index price already reflects them. This is the single most important variable in the entire clause. For a full breakdown of cost-free royalty language and how to negotiate it before you sign, read How to Negotiate an Oil and Gas Lease.

Enumerate the specific costs the operator cannot deduct. A well-drafted clause lists gathering, compression, dehydration, treating, processing, fractionation, transportation, marketing, and fuel — by name. Enumeration prevents an operator from arguing a specific cost falls outside a general “no deductions” phrase.

Address affiliate sales directly. Require that any sale to an affiliate be at arm’s length or at the price the affiliate ultimately receives from an unaffiliated third party. This closes the wellhead-sale-to-marketing-subsidiary loophole.

For owners who cannot renegotiate an existing lease, the leverage points shift to lease expiration, Pugh clause enforcement, ratification requests on new units, and where the facts support it, challenges based on the operator’s duty to market. Those challenges require careful legal analysis and a clean production and revenue record, which is why the record-keeping matters as much as the clause itself.

Three questions to send the operator in writing

If you suspect sale-point relocation is producing improper deductions, send these three questions to owner relations by certified mail before escalating:

What is the defined point of sale under my lease, and where in the production stream does it sit? Request the operator’s written interpretation of the royalty clause and the marketing arrangement documentation.

What is included in each deduction line on my check stub, and is each cost incurred before or after the defined point of sale? Request a cost-by-cost breakdown with the contract or tariff that governs each charge.

For any sale to an affiliate, what price did the affiliate ultimately receive from an unaffiliated third party? This targets the wellhead-sale-to-marketing-subsidiary structure directly.

The responses — or the refusal to respond — will tell you whether a line-by-line reconciliation is warranted. Persistent refusal to provide cost documentation is itself a red flag and in most states the owner has a statutory right to request detailed accounting. Valor’s royalty management team handles these reconciliations as part of standard portfolio oversight.

Contact Valor Today

If your check stubs show deductions your lease appears to prohibit, the answer is rarely a phone call to the operator. It is a line-by-line reconciliation of lease language, sale-point mechanics, and reported proceeds. Contact Valor today for a free, no-obligation review — our royalty management team will pull your lease, map the sale point against your check stub deductions, and tell you whether the math lines up with what your lease actually requires. We handle royalty audits and lease-language reviews 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.

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.

Inherited Mineral Rights in Another State: Probate, Trusts, and What to Do Next

Posted on by Leonardo

If you just inherited mineral rights in Texas, Oklahoma, or any other state where a family member owned acreage, the first thing to understand is jurisdictional. Title to mineral interests is generally governed by the law of the state where the minerals are located, even when the owner lived and completed probate elsewhere. That distinction drives everything that happens next — which court handles what, what additional proceedings you may need to open, and whether the trust your parent set up in Florida or California can actually take title to a Reeves County royalty interest.

Valor has recovered more than $28 million for mineral owners in the past 36 months and manages interests across 32 states and 13 major basins. The pattern is consistent: heirs and executors lose months, sometimes years, because no one explained the rules at the start.

Why the mineral state’s law governs title

Real property — and mineral interests are real property in Texas, Oklahoma, and most producing states — is governed by the law of the state where the property is located. A Florida probate alone may not be sufficient to establish record title to a Texas mineral interest. Texas law governs how the interest transfers, who has authority to sign leases and division orders, and what documents the county clerk will accept for recording.

A title examiner reviewing the ownership chain for an operator will generally require documentation that establishes the transfer under the law of the mineral state. Without that, the interest sits in title limbo and operators may place royalties in suspense pending satisfactory title documentation.

The practical effect for heirs: you may need to coordinate title transfer work in multiple states before a single royalty check is released. Understanding the required proceedings early can reduce delays that otherwise extend the administration significantly. If you are just starting this process, read Just Inherited Mineral Rights? Here Is Where to Start for the foundational steps before working through the jurisdictional issues covered here.

Domiciliary probate vs. ancillary proceedings: understanding the options

Domiciliary probate is the primary proceeding, opened in the county where the decedent was legally domiciled at death. That court has authority over personal property, bank accounts, and — critically — appoints the executor who will act for the estate.

When minerals are located outside the decedent’s home state, an ancillary probate or another state-authorized title transfer procedure may be required in each mineral state. The purpose is to give the mineral state jurisdiction to recognize the will or apply intestate succession, confirm the executor’s authority in that state, and issue orders the county clerk will record.

Ancillary probate is common, but it is not always the only path. Depending on the state and circumstances, alternatives may include recording authenticated foreign probate documents, a muniment of title procedure, an affidavit of heirship, summary proceedings, or small estate procedures. In Texas, venue and the appropriate probate court depend on the county, the type of proceeding, and the local court structure. In Oklahoma, proceedings run through the district court of the county of situs.

When minerals sit in multiple states, potentially multiple proceedings or other state-specific transfer processes may be required — one for each state where the minerals are located. The mineral state may require authenticated documents from the domiciliary proceeding before it will recognize the will or authorize a local transfer. Because procedures and local filing requirements differ by state, consider retaining counsel licensed in each relevant jurisdiction. For a practical guide to the county records and courthouse research steps that support this process, read Valor’s courthouse mineral research guide.

Do you need a second trust for out-of-state minerals? Usually no.

This is one of the most common questions our mineral management team fields: the decedent set up a revocable living trust in their home state, and the family assumes they need a separate trust in Texas or Oklahoma to hold the minerals. In many ordinary estate-planning situations, a separate trust is not required.

A properly drafted revocable trust can hold real property, including mineral interests, in multiple states. What matters is not where the trust was created but what powers the trust instrument gives the trustee and what state law provides. A Texas trust holding Oklahoma minerals does not need a separate Oklahoma trust. A Montana decedent with North Dakota minerals does not need a North Dakota trust if the Montana trust instrument is properly drafted and the minerals are correctly titled into it.

If the minerals were properly conveyed to the trust during the grantor’s lifetime, the trustee may be able to administer them without probate. If they remained in the grantor’s individual name, a pour-over will may direct them to the trust, but probate or another state-authorized transfer process may still be required before the trustee can act on them.

Where families most commonly run into problems is when the trust exists on paper but the minerals were never actually transferred into it. A trust with a schedule of assets listing “Texas minerals” is not the same as a recorded mineral deed conveying those interests to the trustee. If the deed was never executed and recorded in the mineral county, the minerals remain in the decedent’s individual name and require a title transfer procedure to get them properly into the trust.

The rare case where a second trust makes sense is when there is a specific state-law objective — creditor protection under a particular state’s asset protection statute, or a directed trust arrangement — that the home-state trust cannot accomplish. For ordinary succession planning, one trust with clean deeds into it is cleaner and cheaper. For guidance on how mineral interests fit within a trust structure, read Minerals in a Trust: What Bankers, Trustees, and Mineral Owners Need to Know.

Trustee powers: confirm authority before acting

Even a well-drafted single trust can create friction if questions arise about the trustee’s authority to act on producing minerals. Producing minerals are not passive assets. A trustee holding a Reagan County royalty interest will be asked to sign division orders, ratifications, pooling amendments, and sometimes new leases when acreage comes off production.

The trust instrument and applicable state law should give the trustee sufficient authority to lease, pool, convey, ratify agreements, and execute division orders. Texas, for example, grants trustees broad statutory mineral-management powers, subject to the terms and limitations of the trust instrument. Clear express language in the trust can reduce uncertainty and minimize title objections regardless of what state law provides.

If questions arise about trustee authority, operators may place royalties in suspense pending satisfactory documentation. Resolving that may require a court order, a trust amendment, or a certification of trust depending on the circumstances and applicable state law. For context on what a division order requires and why unsigned or disputed ones can cause suspense, read Division Order, Lease Offer, or Buyout? How to Read the Letter About Your Mineral Rights.

Language to consider including during drafting: express power to execute oil, gas, and mineral leases on terms the trustee deems reasonable; power to pool, unitize, and ratify existing units; power to execute division orders, transfer orders, and stipulations of interest; and power to convey or sell mineral and royalty interests. Review the trust instrument and applicable state law with qualified counsel before acting.

This question comes up in almost every multi-state estate. An executor inheriting a small royalty in another state faces a real cost-benefit problem: transfer proceedings and legal fees may exceed the value of the interest.

The options are not simply abandon it or spend the money. Selling is possible if a mineral buyer will make an offer — small fractional interests are harder to market but not impossible. Deeding to the surface owner is another path if the surface and mineral ownership can be reunited cleanly. Donating the interest to a qualified charitable organization may be an option, although acceptance, valuation, appraisal requirements, and tax deduction rules should be reviewed with the organization and the owner’s tax adviser before proceeding.

Do not simply abandon a mineral interest without understanding the consequences. Depending on the state and how the interest is assessed, delinquent taxes associated with mineral property can create liens or lead to adverse consequences. Confirm the applicable tax treatment with qualified counsel before deciding to retain, transfer, or disclaim an interest. If you need help evaluating options for a small interest, Valor’s mineral management team can help you assess the production history, identify whether the interest has recoverable value, and find any unclaimed funds before any decision is made. The unclaimed mineral funds guide is a useful starting point.

A practical checklist for heirs and executors

If you are the executor or an heir on an estate with minerals outside the decedent’s home state, work through these steps in order. Getting them right up front compresses timelines and reduces the chance you discover a problem years in.

Identify every state where minerals exist. Check tax returns, operator tax forms, division order files, royalty statements, county records, and applicable state or local property tax records. Do not assume the estate inventory is complete.

Open domiciliary probate first. Get the will admitted and the executor qualified in the home state. Order multiple certified and authenticated copies — you will need them for any ancillary or foreign probate recognition proceedings.

Determine what title transfer procedure is required in each mineral state. Ancillary probate is common but not always the only path. Retain counsel licensed in each relevant jurisdiction to identify the appropriate procedure.

Check for an existing trust and confirm the minerals are actually in it. A schedule of assets listing minerals is not a recorded conveyance. If the deed was never executed and recorded in the mineral county, the minerals still require a title transfer procedure.

Review trustee powers and applicable state law before acting. Confirm the trust instrument and state law give the trustee sufficient authority to lease, pool, and execute division orders before responding to any operator request.

Notify operators in writing. Once the appropriate title documents are recorded, send certified copies to every operator with a transfer order request. Operators generally release suspended funds after their title requirements have been satisfied, subject to applicable law and any remaining ownership disputes. If royalties may already have been reported or remitted to the state as unclaimed property, search the relevant state’s unclaimed property database for each state before reaching out to operators.

Contact Valor Today

Inherited minerals in an unfamiliar state do not have to become a multi-year administrative problem. Contact Valor today for a free, no-obligation review — our mineral management team will help you organize the estate’s mineral position, identify every interest and its current pay status, coordinate with local counsel on ancillary proceedings, and work to get suspended royalties released as quickly as the paperwork allows. We handle inherited mineral rights and estate transfers for owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only, not 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.

How to Calculate Your Royalty Decimal Interest

Posted on by Leonardo

You opened the division order, saw a decimal like 0.00564234, and could not figure out where the number came from. You are not alone. This is one of the most common questions mineral owners ask after a horizontal well is completed, and the answer almost never appears on the paperwork itself.

Valor has recovered more than $28 million for mineral owners in the past 36 months, and a meaningful share of those recoveries started with an owner who did the decimal math themselves and found an error. This post walks through the exact formula, a fully worked horizontal well example, and how to find the missing inputs when your paperwork does not spell them out.

The formula for a standard leased mineral interest

For most standard pooled or spaced units, a mineral owner’s royalty decimal is built from the same three inputs: your net mineral acres in the tract, the size of the drilling or spacing unit the well is producing from, and your royalty rate under the lease.

The formula is:

Net Mineral Acres ÷ Drilling Unit Acres × Royalty Rate = Decimal Interest

If you want to run the numbers quickly before working through the steps below, Valor’s royalty decimal calculator does this math precisely and estimates your monthly share from any decimal.

For a conventional acreage-based pooled unit, the basic calculation does not change merely because the well is horizontal. Production-sharing wells, allocation wells, and units governed by special allocation provisions may require a different calculation — but for many owners receiving a standard division order on a conventional horizontal or vertical well, this is the basic formula.

If the number on your division order does not reconcile to those three inputs, one of the inputs on the operator’s side does not match what you believe to be true. Finding which one is the entire exercise.

For context on where decimal interests fit into ownership, leasing, and payment tracking, our mineral management overview covers the full lifecycle Valor manages for owners across 32 states and 13 basins.

A fully worked horizontal well example

Assume you inherited 14.4444 net mineral acres in a section in Martin County, Texas. The operator drills a horizontal Wolfcamp well and pools your tract into a standard 640-acre drilling unit. Your lease reserves a 25% royalty. The math looks like this:

14.4444 ÷ 640 × 0.25 = 0.00564234

Walking through it: 14.4444 divided by 640 equals 0.02256938 — your fractional mineral ownership in the unit. Multiply by the 0.25 royalty rate reserved in your lease and you get 0.00564234, the figure you would generally expect to see on the division order and associated check details, subject to any later ownership or unit adjustments.

To sanity-check, multiply the decimal by the well’s gross monthly revenue. If the well produces $500,000 in gross revenue in a given month, your gross royalty before taxes and post-production deductions is $500,000 × 0.00564234 = $2,821.17. That amount should approximate your gross royalty attributable to the well before applicable taxes, adjustments, and any deductions permitted under your lease. Check stub presentation varies by operator.

Operators commonly report decimal interests to six or eight decimal places. Even small rounding differences can affect payments over the productive life of a well.

Why a horizontal well decimal looks so much smaller

Owners who received royalties from an older vertical well on the same tract are often surprised at how much smaller the horizontal decimal is. The formula did not change — the denominator did.

A vertical well on a 40-acre or 80-acre proration unit gave you a much larger fraction of that smaller unit. Using the same 14.4444 net mineral acres and 25% royalty on an 80-acre vertical unit, the decimal would be 14.4444 ÷ 80 × 0.25 = 0.04513875 — roughly eight times larger than the horizontal decimal.

That does not mean you are worse off. Horizontal wells often produce substantially more than older vertical wells, so a smaller decimal does not by itself mean you will receive less revenue. The check stub optics can be jarring the first month, and it is why many owners call in convinced there is an error when there is not.

The corollary: if two horizontal wells are drilled in the same section and one is a 640-acre unit and the other is a 1,280-acre two-section unit, your decimal in the 1,280-acre unit will be exactly half — assuming the same acreage is committed, the same royalty rate applies, and production is allocated strictly by acreage.

Finding the spacing-unit size when the paperwork does not say

Division orders in Texas and Oklahoma routinely omit the drilling-unit acreage. They show the decimal, the well name, and sometimes the lease — but not the denominator you need to verify the math. Here is where to find it:

Texas wells. Texas wells. Search the RRC well records for the W-1 drilling permit, W-2 or G-1 completion packet, Form P-16 acreage designation, and any associated certified plat or acreage documentation. For a pooled unit, also review the recorded unit designation or pooling declaration in the county clerk’s records where the tract sits. For a broader guide to using RRC and county records to locate your interests, read Just Inherited Mineral Rights? Here Is Where to Start.

Oklahoma wells. The Oklahoma Corporation Commission spacing order sets the unit. Search by section-township-range or by the OCC cause number, which may appear on the division order or related well documents. Force-pooled owners will also find their election terms in the pooling order. For a plain-language explanation of how force pooling works and what it means for your decimal, read Forced Pooling in Oklahoma vs. Texas.

Both states. Request the unit designation, plat, and supporting ownership calculation from the operator. If the operator will not explain the calculation or provide supporting information, consider escalating the request or consulting a qualified land or legal professional.

Once you have the unit size, plug it into the formula. If the decimal still does not reconcile, the next issue to investigate is often the net mineral acreage, including possible title issues, unrecorded conveyances, or miscalculations of inherited fractional interests.

When your math and the division order do not agree

Three common reasons a calculated decimal does not match the one on the division order:

Your net mineral acre count is wrong. Inherited interests get fractionalized across generations. If a great-grandparent owned 160 acres and it was split five ways, then three ways in the next generation, your actual NMA may differ from the round number in family records. Confirming the interest generally requires reviewing the relevant county records and chain of title, often through a professional title examination. If you recently inherited and have not yet verified what you own, read Just Inherited Mineral Rights? Here Is Where to Start before you respond to any division order.

The unit is larger than you thought. Multi-section horizontal units are standard now. If you assumed 640 acres and the plat shows a 1,280-acre unit, your decimal will be exactly half of what you calculated. This is not an error — it is a paperwork gap.

The royalty rate on the operator’s file does not match your lease. If your lease reserves 25% but the operator’s records show 20%, your decimal will be 20% too low, and every check for the life of the well will be short. In Valor’s experience this is one of the most common and recoverable error categories we find across the portfolio. For a full breakdown of what royalty rate language in your lease actually controls, read Why Is My Royalty Check So Small? Post-Production Deductions, Explained.

Do not sign without first investigating a material discrepancy. Ask the operator to explain the calculation and provide supporting documents. Because division-order laws and the consequences of refusing to sign vary by state, consult a qualified attorney when a discrepancy cannot be resolved. If you have not received a division order and believe you should have, here is what to do.

This kind of decimal verification is a routine part of what Valor’s team of CPAs, CPLs, and Certified Mineral Managers does across the portfolio we manage — roughly 500,000 wells generating approximately $650 million in annual client revenue.

Contact Valor Today

If you are staring at a division order or a first check stub and the numbers do not add up, the explanation is often found in the unit documents, title records, lease, or operator ownership calculation. Contact Valor today for a free, no-obligation consultation to discuss the discrepancy and determine whether a more detailed division order review is appropriate. Our royalty management team handles division order verification and royalty audits for owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only, not 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 professional attorney in your state.

Before You Throw That Letter Away: How to Verify Any Mineral Rights Notice

Posted on by Valor

A letter arrived about your mineral rights. The return address is a company you have never heard of. It references a well you cannot place. It is asking for your tax ID or your signature.

Before you throw it away — read this first.

Last week on one of the most active mineral rights forums online, an owner asked whether a suspense notice from Plains Marketing was a scam. The top reply said “100000000% SCAM, throw that in the trash.” That answer was completely wrong. A landman in the same thread corrected it: he had a client who received the exact same kind of letter with $800,000 sitting in suspense behind it.

That scenario plays out constantly. In the past 36 months, Valor has recovered more than $28 million for mineral owners — and a surprising share of that money started with a letter the owner nearly threw away. This post walks through why most of these letters are legitimate, gives you a four-step routine to verify any letter in about 30 minutes, and identifies the narrow set of red flags that actually indicate a real scam.

Why mineral rights letters look like scams even when they are not

Valor manages more than 500,000 wells across 32 states and 13 basins. Across that footprint, the same categories of mail show up in owners’ mailboxes every week — and they almost always look worse than they are.

Three types account for the majority of concern:

Suspense notices. An operator is holding your royalty payments because something in the title chain, address, tax ID, or division order cannot be reconciled. The letter is a request for information, not a threat. Until you respond, your money sits in an account earning you nothing. If you believe funds may already be sitting in suspense, here is how to find unclaimed mineral funds.

W-9 requests from operators you do not recognize. Wells change hands constantly. The operator who drilled your section in 2014 may have sold the wellbore to a successor in 2022, who sold it again in 2025. Each time the operating interest transfers, the new payor is legally required to collect a fresh W-9 before cutting you a check. The company name on the letter will almost never match the name you have been dealing with. That is normal, not suspicious. For a plain-language explanation of what happens to your royalty payments when an operator sells, read What Happens to Your Royalty Payments When Your Operator Sells.

Unclaimed property notices from state treasurers. Every state escheats unclaimed royalty proceeds after a statutory dormancy period — typically three to five years. Treasurers then send notices to the last known address. These letters can look like phishing because they arrive out of nowhere and reference money the owner did not know existed. They are real.

None of these are scams. They are the mechanical output of a system that moves ownership, payments, and tax reporting across dozens of counterparties. The instinct to shred them is exactly what costs owners money. For the broader context on how these workflows fit together, our mineral management overview lays out the moving parts.

How to verify any mineral rights letter in 30 minutes

This routine works for almost any letter you will receive. You do not need a lawyer for steps one through four — only for the rare cases that fail all four.

Step 1: Identify the sender against public records. If the letter is from an operator, look up the company name on the Texas Railroad Commission’s operator query for Texas wells or the Oklahoma Corporation Commission’s website for Oklahoma. Legitimate operators have a P5 number in Texas or an OCC operator ID in Oklahoma. If the entity shows up in the state’s regulatory system with an active status, that is a strong first signal. If you cannot find them at all, that is worth noting before you respond.

Step 2: Match the property described in the letter to your records. The letter should reference a specific lease name, well name, API number, or legal description — section, township, and range, or abstract and survey. Pull your last division order or a prior check detail statement. If the property matches something you already own, the letter is almost certainly connected to a real interest. If you have never confirmed what you own at the county level, Valor’s courthouse mineral research guide walks through how to do that by state.

Step 3: Call the sender using a number you found independently. Do not call the number printed on the letter. Look up the operator’s main line through the state regulator’s records or their corporate website. Ask for owner relations, reference the letter, and confirm it originated with them. If the number on the letter and the number you found independently do not match, call the one you found yourself.

Step 4: Cross-check state treasurer notices at the source. Every state runs a free unclaimed property search — Texas at ClaimItTexas.gov, Oklahoma at the state treasurer’s site. If the notice references funds held by the state, that same claim should be searchable on the official portal using your name. If it shows up there, the letter is real.

The actual red flags that indicate a real scam

Real scams targeting mineral owners exist, but they do not look like suspense notices or W-9 requests. They look like unsolicited purchase offers and pressure tactics. Watch for these specific patterns:

Pressure to sign within days. Legitimate operators, state treasurers, and title companies operate on months-long timelines. Anyone insisting you must sign within 48 or 72 hours is manufacturing urgency to short-circuit your verification.

Requests for money upfront. No legitimate suspense release, W-9 processing, or unclaimed property claim requires you to pay a fee or wire funds. State treasurers return unclaimed property for free. Operators do not charge you to receive your own royalties.

Offers to buy your minerals sight-unseen at a flat per-acre number. A legitimate offer will let you take weeks to evaluate. A predatory one arrives with a check already enclosed and a deed pre-drafted, betting on your confusion. Before responding to any purchase offer, read Got an Offer to Buy Your Mineral Rights? How to Tell If It’s Actually Fair.

Payment instructions that route around normal channels. If a purported operator asks you to update banking information via a link in an email or send tax documents to a personal Gmail address, stop.

Vague property descriptions. A legitimate letter names the lease, well, or legal description. A scam letter tends to reference “your mineral interests” generically because the sender does not actually know what you own.

The through-line is simple: legitimate mail asks you to provide information. Fraudulent mail asks you to surrender something — money, signatures, or account access — before you have had time to think.

What ignoring a real letter actually costs you

The cost of throwing away a legitimate letter is not zero, and it compounds quietly.

A suspense notice ignored for 36 months means royalties sitting in the operator’s account instead of yours, and eventually escheating to the state. A W-9 request ignored means the operator withholds 24% backup withholding on every check going forward — money you have to chase back through your tax return. An unclaimed property notice ignored means the funds get harder to claim as time passes, because the documentation trail supporting your ownership gets colder.

Our mineral management team spends a real share of its time reversing the consequences of letters owners wish they had opened sooner. It is almost always cheaper and faster to respond to a legitimate letter in the first 30 days than to unwind the fallout years later. Valor is SOC 1 Type II certified, which means our controls around client data and communications are independently audited every year — the standard you should expect from anyone you hand a sensitive letter to.

If you are not sure which type of letter you received — division order, lease offer, or purchase offer — read Division Order, Lease Offer, or Buyout? How to Read the Letter About Your Mineral Rights before you respond to anything.

Contact Valor Today

If a letter arrived and still feels wrong after you have walked the four-step routine — or if you would rather not walk it alone — Contact Valor today for a free, no-obligation review. Our mineral management team will verify the sender, match the property to your ownership records, and tell you exactly what the letter is and what to do next before you sign, send, or shred anything. We handle letter verification, suspense releases, and unclaimed mineral fund recovery for owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only, not 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 professional attorney in your state.

You Just Got an Offer for Your Minerals. Here’s What the Buyer Already Knows.

Posted on by Leonardo

Mineral buyers do not send letters at random. Before an offer reaches your mailbox, an acquisitions team has already pulled your production history from public state filings, mapped every permit within a mile of your tract, modeled the decline curve on your producing wells, and calculated the return they need to justify the purchase. The offer is not a guess. It is a discount to a number they already trust. This post walks through what the buyer knows, how they built that number, and what you need in front of you before you respond.

The Buyer Has Already Pulled Your Production History

Before a single letter goes out, an acquisitions team pulls every public data point tied to your tract. In Texas, that means Railroad Commission filings — production reports, W-2 completions, plugging records, permit history. In Oklahoma, it is Corporation Commission filings and OTC gross production tax data. This is not proprietary information. It is public. But it takes time and tooling to assemble it into a usable picture, and most mineral owners have never done that work on their own tract.

The buyer knows your monthly BBL and MCF for every producing well tied to your interest, going back years. They know whether production is climbing, flat, or in decline. They know which operator is on the lease, how that operator performs across their portfolio, and how quickly that operator typically brings new wells online. If your interest sits in a stacked-pay county — Reagan, Martin, Reeves, Karnes, Grady, Canadian — they have modeled how many additional benches the operator is likely to develop and on what timeline.

You are negotiating against someone who has done homework you have not done. That is not a moral failing. It is the structural reality of the transaction, and it is the first thing to correct before you respond to any offer. Valor’s mineral management practice runs this same assembly on behalf of owners across 13 major basins, so the information gap closes before an offer letter forces a decision.

The Offer Is a Discount to a Forward Cash Flow Model

Mineral buyers do not price offers off your last royalty check. They price off a discounted cash flow model that runs 10, 20, sometimes 30 years forward. The inputs are straightforward: current production, decline curves from analog wells in the same formation, forward price decks for oil and gas, expected future drilling on the tract, and a discount rate that reflects the buyer’s cost of capital and target return.

Here is the mechanic that matters. The buyer builds a forward value number. Then they offer a fraction of it. The spread between the offer and the modeled value is the buyer’s margin — the return they need to justify the acquisition, plus a cushion for the risk that their model is wrong. That spread is not hidden. It is the entire business model of a mineral acquisition firm.

None of this means the offer is unfair. Buyers take real risk — prices fall, wells underperform, operators go bankrupt, drilling plans slip. What it means is that the offer number tells you almost nothing about what your minerals are worth. It tells you what the buyer needs to pay to hit their return target. Those are two different numbers, and the gap between them is where mineral owners either capture value or leave it on the table. For a deeper look at how to evaluate whether a specific offer is fair, read Got an Offer to Buy Your Mineral Rights? How to Tell If It’s Actually Fair.

Offset Activity Is Often the Biggest Piece of the Model

The single largest driver of upside in most mineral valuations is not what is producing today. It is what is going to be drilled tomorrow. Buyers know this. They map every permit filed within a defined radius of your tract, track rig locations, and cross-reference operator development plans disclosed in investor presentations. If a major is running a multi-rig program in your county and has permits stacked up on adjacent sections, that is a signal — and the buyer has priced it in.

Mineral owners rarely have this view. Most only see the wells currently producing on their interest. They do not see the permits filed last month two sections over, the new lateral geometries being tested in the same bench, or the offset operator’s completion designs that suggest heavier proppant loads and better recoveries. That information is public, but it takes work to compile. For a plain-language guide to reading permit activity and offset drilling near your acreage, read How to Read Oil and Gas Activity on Your Acreage.

The practical implication: an offer that looks generous relative to your last twelve months of royalty income can still be well below fair value if a wave of new development is coming. An offer that looks stingy against a peak production year can be reasonable if wells are deep into decline with no new drilling in sight. Context is everything, and context comes from the same public data the buyer is already using. Working with a team of CPAs, CPLs, and Certified Mineral Managers is one way to compress that information gap quickly.

What You Need in Front of You Before You Respond

You do not have to match the buyer’s model line for line. You need to close enough of the information gap that you can make an informed decision instead of a reactive one. That means assembling five things before you respond to anything:

Production history by well. Monthly volumes for every well tied to your interest, at least the last 24 months, ideally the last 60. Texas RRC and Oklahoma OCC both have this publicly available.

Current lease terms. Royalty rate, primary term status, any post-production deduction language, Pugh clauses, and depth severances. If you have not reviewed your lease recently, here is what the key clauses actually mean.

Offset permit and drilling activity. Every permit within a defined radius, filed in the last 12 to 24 months, with operator and target formation. This is the single most important input the buyer has that most owners lack.

Operator quality signal. Is the operator on your lease a well-capitalized, active driller, or a legacy holder unlikely to develop further? The answer changes the forward value picture significantly.

A cash flow view. Even a rough one — what current wells are likely to pay over the next 5 to 10 years at reasonable price assumptions. Valor’s royalty management team can run this for you quickly using the same public data the buyer is already working from.

With those five pieces in hand, the offer letter becomes what it should have been all along: a data point, not a deadline. You can compare it to a defensible internal number, push back on price, carve out depths or reserve a portion of the interest, or walk away. In the past 36 months, Valor has recovered $32 million for mineral owners — much of it by helping owners see what buyers, operators, and prior managers had already priced in and not shared.

When Selling Is the Right Answer — and When It Is Not

None of this is an argument against selling minerals. There are good reasons to sell: estate simplification, portfolio diversification, tax planning, a life event that makes lumpy royalty income impractical, or a genuinely strong offer at a cyclical price peak. Selling can be the right decision. Selling blind is almost never the right decision.

The mineral owners who transact well share a few habits. They understand what they own before an offer arrives, not after. They keep current title, lease, and division order records. They monitor offset activity in their county on a rolling basis. And they treat unsolicited offers as the beginning of a conversation, not the terms of one. Across the roughly 500,000 wells and $650 million in annual client revenue Valor manages, the owners who consistently protect value treat their minerals as an actively managed asset, not a mailbox check.

If you are weighing a sale and want to understand what your options actually are, read Before You Sell or Lease for the full framework.

Contact Valor Today

If an offer just landed and you do not yet have the picture the buyer has, that gap is closable. Contact Valor today for a free, no-obligation review — our mineral management team will verify what you own, pull your production history, map permit and drilling activity near your tract, and flag what the offer is not telling you before you respond. We handle mineral rights evaluations and offer reviews for owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only, not 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 professional attorney in your state.

Why Is My Royalty Check So Small? Post-Production Deductions, Explained

Posted on by Leonardo

You open the envelope, and the number is smaller than last month — even though the well is still producing and prices have not collapsed. In the past 36 months, Valor has recovered more than $32 million for mineral owners in exactly this situation: checks that looked wrong, and were. Post-production deductions are the single most common reason a royalty check underdelivers, and they are also the most misunderstood line item on the statement. This post covers what those deductions are, why they hit hardest in low-price months, how your lease decides whether they are allowed, and what to do before you call the operator.

What Post-Production Deductions Actually Are

Post-production costs are the expenses an operator incurs to move raw hydrocarbons from the wellhead to a marketable point of sale. The five categories you will see most often on a check stub are:

  • 1. Gathering — moving gas through low-pressure pipe from the wellhead to a central point
  • 2. Compression — boosting pressure so gas can enter a larger pipeline
  • 3. Treating and dehydration — removing water, CO2, and H2S
  • 4. Processing — stripping out natural gas liquids like ethane, propane, and butane at a plant
  • 5. Transportation — long-haul pipeline tariffs to the sales point

Each of these has a real cost, and someone has to pay it. The question your lease answers — or fails to answer clearly — is whether the operator pays the full cost out of its working interest, or whether it can charge a proportionate share back against your royalty. When deductions are permitted, they scale with your royalty fraction, so every dollar of gathering, compression, and processing booked against the well flows through in proportion to your interest.

The result: two royalty owners on adjacent tracts, producing from the same formation, at the same wellhead price, can receive materially different net checks depending on how their leases were negotiated 10, 30, or 60 years ago.

Why the Math Gets Ugly When Prices Drop

Most gathering, compression, and processing fees are structured as a flat rate per unit of volume — a fixed number of cents or dollars per Mcf. Those fees do not scale with the commodity price. They are the same when gas is trading high as when it is trading low.

The consequence is that the deduction stack takes up a much larger share of gross value in weak-price months. When the sales price falls, the flat fees do not. What used to be a tolerable percentage of the gross becomes a much larger percentage of a much smaller number, and the net royalty compresses hard. That is why owners in dry-gas plays across the country routinely report that a check looks fine one quarter and shockingly thin the next, even when volumes are steady.

Liquids-rich gas is a partial hedge — NGL revenue can offset processing fees — but only if the operator is remitting your proportionate share of NGL proceeds correctly, and only if the plant economics work in your favor that month. Frequently one or both of those conditions is not met, and the owner has no way to see it without reconciling the statement line by line.

“At the Wellhead” vs. “Gross Proceeds” — The Language That Decides Everything

Nearly every dispute over post-production deductions turns on a single clause in the oil and gas lease: where royalty is calculated and what value it is calculated against.

Leases that say royalty is paid on the value at the wellhead generally permit the operator to deduct post-production costs before calculating your share. The logic: if royalty is owed at the wellhead, then any cost incurred downstream of the wellhead to enhance value can be netted back out. Texas courts have generally supported this reading, and the state’s default rule — absent explicit lease language to the contrary — is that post-production costs are shared.

Leases that say royalty is paid on gross proceeds, the amount realized, or the market value at the point of sale — with no wellhead qualifier and often with an express prohibition on deductions — generally do not permit the operator to charge post-production costs back to the royalty owner. Oklahoma has historically been friendlier to the gross-proceeds interpretation than Texas, but the specific language of your lease still controls, and case law continues to evolve in both states.

The practical takeaway: pull your lease, find the royalty clause, and read the exact words. If it says “at the well” or “at the wellhead,” deductions are likely permitted. If it says “gross proceeds received by lessee” or contains an express no-deductions clause, deductions on your check may be improper. This is the single most valuable 15 minutes a mineral owner can spend. For a full breakdown of how to negotiate cost-free royalty language before you sign, read How to Negotiate an Oil and Gas Lease.

How to Actually Read the Statement

Operator check stubs are not standardized. One operator will list deductions as GATH, COMP, TRANS, PROC, DEHY. Another will bundle everything into a single “Deducts” column with no breakdown. A third will show a gross value and a net value with the delta unlabeled. All three are common, and all three are generally legal under state royalty statutes as long as the owner can request detail. If you have never read a check stub line by line, our royalty check stub guide walks through every field.

Here is what to reconcile every month, or at minimum every quarter:

Volumes. Compare the Mcf and BBL on your check to the state regulator’s production reporting — Texas Railroad Commission or Oklahoma Corporation Commission filings. They should match, allowing for a reporting lag.

Price. Compare the price per unit on your check to the posted price or index for that basin and month. A significant discount often signals either legitimate quality and location differentials or an issue worth questioning.

Decimal interest. Confirm the decimal on your check matches the decimal on your division order. Ownership changes, unit revisions, and pooling amendments all shift decimals, and errors are common. If you have not received a division order and believe you should have, here is what to do.

Deduction codes. Ask the operator in writing for a description of every code. You are entitled to know what you are being charged for.

Severance and ad valorem tax. These are separate from post-production deductions. Confirm they match state rates.

If the operator refuses to provide a code key or a breakdown, most state statutes give royalty owners the right to request detailed accounting. In Texas, that request should be in writing and reference the statutory right to information. Persistent refusal is itself a red flag.

When to Push Back — and How

Not every small check is a bad check. Sometimes prices are simply low, a well is in natural decline, or an operator has legitimately incurred higher processing costs because of a plant outage. Pushing back on every downtick will burn goodwill without recovering a dollar.

Push back when the evidence supports it:

  • Your lease contains a gross-proceeds or no-deductions clause and deductions are appearing on the check
  • Your decimal interest is wrong
  • Volumes on the check do not match state filings
  • The operator has changed its deduction methodology mid-lease without notice
  • You are seeing charges — marketing fees, affiliate transportation fees, unspecified “other” — that do not fit a recognized category

The right sequence is almost always: request a written breakdown of all deduction codes and calculations, compare against your lease language and state production filings, send a formal demand letter identifying the specific charges you dispute and citing the lease clause, and if unresolved escalate to counsel or a professional mineral manager who can pursue audit rights or statutory remedies.

Across the 500,000 wells we cover, the most productive recoveries come from owners who catch the issue early and negotiate from specific evidence rather than general frustration. If your check stopped entirely rather than just running small, read Why Your Royalty Check Suddenly Stopped for the full breakdown on recoupment and shut-ins.

Small royalty checks are sometimes just the market. Sometimes they are a lease-language problem, a decimal error, or an improper deduction that will keep compounding until someone catches it.

Contact Valor Today

If your royalty checks are running smaller than they should and the operator’s math does not add up, a second set of eyes on your statements and lease language is the fastest way to find out why. Contact Valor today for a free, no-obligation review — our royalty management team will audit your check stubs, verify your decimal interest, compare your deductions against your lease language, and flag anything that should not be there. We handle royalty audits and statement reviews for owners across Oklahoma, Texas, and 30 other states.

The information provided by Valor in this blog is for general informational purposes only, not 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 professional attorney in your state.