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Category: 2026

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. Since 2018, Valor has recovered more than $27 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.

Why Your Royalty Check Suddenly Stopped: A Mineral Owner’s Response Guide

Posted on by Leonardo

A royalty check that arrives on the 25th of every month for two years, then doesn’t — that silence is the single most common reason a mineral owner picks up the phone to a firm like ours. Since 2018, Valor has recovered more than $27 million for mineral owners across 32 states and 13 major basins, and a meaningful share of that money started with exactly that question: where did my check go? The answer is almost never mysterious. It is one of a handful of recurring causes, and every one of them has a defined response. This post walks through what actually happened, how to read the statement that came with the stoppage, and the step-by-step checklist to work through before you assume the worst.

The Five Reasons Checks Actually Stop

Before you assume fraud, theft, or a well going dry, understand that royalty payment stoppages fall into a short list of causes. Across the roughly 500,000 wells in our mineral management portfolio, the same handful of issues account for the overwhelming majority of interruptions.

Overpayment recoupment. The operator paid you too much in a prior month — usually because of a decimal-interest error, a bad division order, or a mistaken well allocation — and is now clawing that money back by withholding future checks until the balance is zero.

Prior-period adjustments (PPAs). Volumes, prices, or deductions from earlier months were restated. If the restatement reduces what you were owed, the difference is netted against current production, sometimes wiping out a month or two of payment entirely.

Frac-protect shut-ins. An offset operator is completing a new well nearby, and your producing well was temporarily shut in to protect the frac. No production, no royalty — but often no notification either.

Title or ownership issues. A death in the family, an unrecorded deed, a probate that was not filed with the operator, or a curative title question can move your interest into suspense. The money is accruing — it just is not leaving the operator’s account. If you recently inherited minerals and have not yet resolved title, read Just Inherited Mineral Rights? Here Are the First 6 Things to Do before contacting the operator.

Minimum-pay thresholds. Most operators hold small balances and release them annually or when the balance clears the threshold. If your production dropped, you may simply be below the cutoff.

Each cause has a different fix, and the wrong response to the right cause can cost you money. The first move is diagnosis, not escalation. For a broader view of how these pieces fit together, our royalty management overview lays out the full lifecycle of the interests we watch.

Overpayment Recoupment: The Silent Zero-Dollar Statement

Recoupment is the cause owners misidentify most often. The check does not arrive, but the operator did nothing legally wrong — they overpaid you months ago and now they are taking it back.

Here is how it usually looks on a statement: production volumes appear as normal, gross value looks correct, but the net owner amount is zero — or negative and carried forward. Somewhere on the detail, often in small type, there is a line labeled “prior-period adjustment,” “recoupment,” or a negative dollar figure with a date reference to an earlier production month. If you are not sure how to read your statement line by line, our guide to reading your royalty check stub walks through every field.

The right response is not to demand the money. The right response is to demand the math. Ask the operator in writing for the production month being adjusted, the specific error being corrected, the recalculated net owner value, and the running balance to be recouped. If the math holds up, the withholding is legitimate. If it does not — and in our experience across 32 states, it often does not — you have grounds to contest. Recoupments that reach back beyond the statutory look-back window in Texas or Oklahoma may not survive a formal challenge, and owners who never audit these adjustments simply absorb the loss.

That is a meaningful part of what our $27 million recovery figure represents: money that was already technically paid, then taken back on paper, and never questioned.

Prior-Period Adjustments and Frac-Protect Shut-Ins

PPAs and shut-ins look different but produce the same visible result: no deposit. Untangling which one you are dealing with takes five minutes if you know where to look.

Prior-period adjustments are corrections to already-reported production or revenue — a gas plant re-runs volumes, a purchaser restates pricing, a severance-tax audit changes withholding. The tell: current-month production is normal, but net proceeds are reduced or zeroed by a line item referring to an earlier date.

Frac-protect shut-ins are operational. When an offset operator stimulates a new horizontal within a defined radius of your producing well, your well is often shut in temporarily to protect the new completion. The tell: production volumes for the month are zero or dramatically reduced, but the well is not plugged and the lease is still held by production from other wells in the unit. For a plain-language explanation of how drilling activity near your acreage affects your royalties, read How to Read Oil and Gas Activity on Your Acreage.

Neither cause is grounds for panic. Both are grounds for documentation. Save the statements, note the well name and API number, and flag any month where no statement arrives at all. Public records at the Texas Railroad Commission and Oklahoma Corporation Commission will confirm whether the well is producing, shut in, or plugged.

The Six-Step Response Checklist

Before you call the operator, work through this in order. It takes about an hour and it will change how the conversation goes.

  1. 1. Pull your last 12 months of check stubs. Line them up chronologically. Look at gross volume, gross value, deductions, decimal interest, and net owner value. Note the last month you were paid and the amount.
  2. 2. Confirm the well is still producing. Check the state regulator’s public well records for the API or lease number. If the well is shut in, plugged, or transferred to a new operator, the record will show it.
  3. 3. Read every line of your last statement, including the fine print. Look for “recoupment,” “prior-period,” “adjustment,” “suspense,” or a reference date well before the statement date.
  4. 4. Confirm your address, ownership, and tax ID with the operator. A returned check, an outdated W-9, or an unrecorded transfer will silently move you into suspense. If you have not received a division order and believe you should have, here is what to do.
  5. 5. Send one written request, not five phone calls. Email owner relations. Ask for: current well status, current decimal interest of record, any active recoupment balance, any suspense balance, and the reason for the payment interruption.
  6. 6. If the response does not reconcile with your records, get a second set of eyes. This is where an independent audit matters. Our royalty management team does this work daily, and the patterns we spot are not always obvious to someone auditing their own statements in isolation.

Owners who follow this sequence resolve most stoppages quickly. Owners who skip step one and lead with a phone call typically get told the operator is researching it — and the check remains stopped.

When to Escalate

Texas and Oklahoma both have statutes governing timely payment of royalties, with defined exceptions for title disputes and suspense. If your check has been stopped for months with no clear explanation, you have leverage — but only if you have documented the timeline.

A certified letter demanding accounting under the applicable state statute, a formal dispute of any stale recoupment, and if necessary involving the state regulator or counsel will usually move the file. The certified letter alone resolves a surprising percentage of cases because it forces the operator’s revenue accounting team to actually pull your account.

The cases that require more are usually the ones where multiple issues have compounded in the same window. Those files are a large part of what drives the recovery total behind our mineral management practice. If your situation involves a lease offer arriving at the same time your checks stopped, treat those as two separate issues and do not sign anything until both are resolved.

Contact Valor Today

If your royalty check stopped and the operator’s explanation does not add up, the next step is a second look at your last 12 months of statements. Contact Valor today for a free, no-obligation review — our royalty management team will audit your statements, verify your decimal interest, and identify any recoupment, suspense, or deduction issue that may be costing you. We handle royalty management and statement 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.

Valor | Energy Connection – July 20, 2026

Posted on by Valor

July 20, 2026 Edition

At Valor, our goal is to keep you informed of the latest news and updates from the oil and gas industry. We are committed to sharing the insights and knowledge that our team gathers to help you stay ahead in this dynamic sector. From mergers and acquisitions to regulatory changes and technological advancements, we cover all the key developments that impact the industry. Stay tuned for weekly updates to keep you well-informed.


  • Magnolia buys WildFire Energy in $4.06 billion deal, adds 500 miles of pipelines
  • Summary: Magnolia Oil & Gas agreed to acquire WildFire Energy for $4.06 billion, adding 500 miles of pipelines and expanding its position to over 1.25 million net acres. The transaction includes assets producing about 53,000 boe/d with 70% oil, $600 million in assumed notes, and 32.2 million common shares issued to WildFire owners. Magnolia expects at least $100 million in annual cost savings and operational synergies from the purchase, while also boosting its quarterly dividend by 9% to $0.18 per share.
  • Read more

    Oil’s oversupply narrative just died
  • Summary: Renewed geopolitical hostilities pushed Brent above $85 per barrel as the oversupply narrative flipped into fears of global shortages. Meanwhile, Asian LNG buying set a July record of 23 million tonnes due to extreme heat, driving Asia’s benchmark JKM price to $19.5 per MMBtu while European imports dropped to 6.90 million tonnes. Oil market data also revealed that China’s June crude imports fell 41% year-over-year to 7.12 million b/d, while Nigerian production surged to 1.56 million b/d.
  • Read more
  • US energy firms boost rig count to highest since April 2025, Baker Hughes says
  • Summary: U.S. energy firms increased the total rig count by seven to 588 for the week ending July 17, marking a fifth consecutive weekly gain and placing the count 44 rigs or 8% above last year’s level. Baker Hughes reported that oil rigs rose by seven to 452, gas rigs held at 126, and miscellaneous rigs stayed at 10. Statewide counts rose by two to 50 in Oklahoma and by two to 274 in Texas, as the EIA projected crude output will reach 13.8 million bpd and gas output will reach 111.3 bcfd in 2026.
  • Read more
  • U.S. crude oil, gasoline inventories still falling
  • Summary: The American Petroleum Institute reported that U.S. crude oil inventories fell by 564,000 barrels for the week ending July 10, while gasoline stocks dropped by 1.664 million barrels. Another 2.99 million barrels left the Strategic Petroleum Reserve to reach 316.5 million barrels, leaving the reserve 415 million barrels below maximum capacity. U.S. crude production rose to 13.860 million bpd, up 475,000 bpd from last year, as Brent crude rose 2.24% to $85.17 and WTI gained 1.92% to hit $79.64.
  • Read more

    USA LNG growth exceeding all expectations, Yergin says
  • Summary: U.S. LNG exports are poised to become the nation’s second largest net export by 2031, with feedgas demand projected to double to 36 billion cubic feet per day over the next five years. An S&P Global study projects that the sector will support 555,000 annual jobs, contribute $1.4 trillion to GDP, and raise household gas costs by just 1.6 percent. Concurrently, the EIA forecasts U.S. LNG gross exports to rise from 15.1 billion cubic feet per day in 2025 to 17.4 billion in 2026 and 18.6 billion in 2027.
  • Read more

    NOG maintains 2026 production outlook as Permian volumes recover
  • Summary: NOG reaffirmed its 2026 guidance despite Q2 curtailments of roughly 7,000 boed due to negative Waha gas pricing and the deferral of three net wells. Stronger basin performance helped NOG project Q2 oil production between 67.5 Mboed and 68.25 Mboed, with Williston exceeding forecasts by 4% and Uinta by 11.5%. Capital spending for Q2 reached $190 million to $200 million, while NOG deployed $45 million into 30 acquisitions and completed its Duvernay deal for CA$237 million and 3.7 million shares.
  • Read more

    Why gasoline prices don’t always move in lockstep with crude oil prices
  • Summary: Crude oil usually accounts for over half the cost of gasoline, with the remainder determined by refining, transportation, distribution, and taxes. Gasoline markets face tighter global conditions as Russian refinery processing rates hit 21-year lows, Middle Eastern refining facilities face disruptions, and Asian exports remain constrained. To help meet fuel demand, U.S. refineries operated at 95.8% of capacity for the week ending July 3, producing 9.7 million barrels per day of finished gasoline.
  • Read more


Contact Valor Today

Contact us today if you need help outsourcing your oil and gas operations.

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. The blog/website should not be used as a substitute for competent legal advice from a licensed professional attorney in your state.

Valor | Energy Connection – July 13, 2026

Posted on by Valor

July 13, 2026 Edition

At Valor, our goal is to keep you informed of the latest news and updates from the oil and gas industry. We are committed to sharing the insights and knowledge that our team gathers to help you stay ahead in this dynamic sector. From mergers and acquisitions to regulatory changes and technological advancements, we cover all the key developments that impact the industry. Stay tuned for weekly updates to keep you well-informed.


  • EIA: Crude oil inventories in U.S. see rare build
  • Summary: According to the EIA, U.S. crude oil inventories increased by 3.0 million barrels to 411.4 million barrels for the week ending July 3, placing commercial stockpiles 6% below the five-year average. Meanwhile, gasoline inventories decreased by 1.9 million barrels with daily production at 9.7 million barrels, and distillate stocks fell by 5.0 million barrels to leave them 12% below the five-year average. On Wednesday morning, Brent crude futures rose 4.33% to $77.37 per barrel, while WTI gained 4.22% to settle at $73.41.
  • Read more

    U.S. oil, gas drillers hang back in volatile market
  • Summary: The total active U.S. drilling rig count rose to 581, up 44 from last year, as oil rigs held at 445, gas rigs remained at 126, and miscellaneous rigs grew to 10. Meanwhile, weekly U.S. crude oil production rose to an average of 13.860 million bpd, up from 13.810 million bpd the prior week, while the frac spread count rose by 5 to 205 crews. Regionally, the Permian Basin rig count dropped by 5 to 256 while Eagle Ford rose by 3 to 47, as Brent oil fell to $75.72 per barrel and WTI dropped to $71.26.
  • Read more
  • Marubeni acquires Barnett shale operator EagleRidge Energy​​
  • Summary: Marubeni Corporation has completed its acquisition of EagleRidge Energy to expand its North American natural gas portfolio. As the third-largest producer in the Barnett Shale, the Dallas-based company operates more than 3,500 wells across around 450,000 gross acres in North Texas and produces around 300 MMcfe/d. This transaction expanded the position through a series of acquisitions completed since September 2024, appointing Tom Ashton and Sam Miller as co-presidents alongside vice chairman Michael Ronca.
  • Read more
  • Permian growth leads U.S. to record oil production​​​​​
  • Summary: U.S. crude oil production reached a record 13.6 million barrels a day in 2025, breaking the 2024 record of 13.2 million barrels a day. Driven by the Permian Basin, which grew 4% to 6.6 million barrels a day, domestic output was roughly 40% higher than Russia’s 9.9 million barrels and Saudi Arabia’s 9.6 million barrels. These 2025 gains occurred despite a 5% drop in active rigs and a decline in WTI prices to $65 a barrel, though the EIA forecasts production will hit 14.2 million barrels a day by 2027.
  • Read more

    U.S. Strategic Petroleum Reserve is 56 percent empty
  • Summary: U.S. Strategic Petroleum Reserve stocks fell to 319.48 million barrels for the week ending July 3, leaving the authorized 714 million barrel capacity about 44 percent full and 56 percent empty. This volume dropped by 6.2 million barrels, or 1.9 percent, week on week and 83.5 million barrels, or 20.7 percent, year on year. The drawdown is a 172 million barrel domestic contribution to a broader 400 million barrel international release, which will be replaced with 200 million barrels very soon.
  • Read more

    U.S. natural gas futures held back by adequate supply
  • Summary: U.S. natural gas futures are lower as ample supply and above-average storage keep weather-driven rally attempts at bay, leaving Nymex natural gas off 2.3% at $3.139/mmBtu. Bank of America Global Research raised its Henry Hub price forecast for the second half of the year to $3.80/mmBtu from $3.60/mmBtu while keeping its 2027 price estimate at $4/mmBtu. While production continues to grow, it has been offset by LNG feedgas demand, power sector factors, and Canadian imports since the April lows.
  • Read more

    Texas oil and gas exploration and production jobs rise for third straight month
  • Summary: Texas upstream oil and natural gas employment grew by 4,100 jobs in May, marking the third consecutive month of gains for the sector. The upstream oil and natural gas industry currently sustains over 850,000 total positions, supporting an additional 232,000 indirect supply chain jobs and 421,000 induced jobs across the economy. From a longer-term perspective, employment has expanded by 40,500 jobs since the pandemic-era low point in September 2020, representing an increase of nearly 26 percent.
  • Read more


Contact Valor Today

Contact us today if you need help outsourcing your oil and gas operations.

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. The blog/website should not be used as a substitute for competent legal advice from a licensed professional attorney in your state.

How to Negotiate an Oil and Gas Lease: Bonus, Pugh Clause, and Cost-Free Royalty

Posted on by Leonardo

Most lease offers are designed to be signed quickly. The bonus is front and center. The royalty looks standard. The deadline is five days out. And the stack of exhibits at the back sits unread.

In the past 36 months, Valor has recovered more than $27 million for mineral owners across 32 states, and a meaningful portion of that came from lease terms that were negotiable at the table but were never negotiated. The landman who delivered that offer has seen hundreds of these. Most mineral owners see one or two in a lifetime. This post closes that gap. Here are the four levers that matter most in a 2026 lease negotiation.

Bonus Per Acre Is the Headline — Royalty and Term Are the Substance

Bonus consideration is what most owners focus on because it’s the number that hits the bank first. But across a productive well’s multi-decade life, the royalty rate and primary term structure will move far more dollars than the bonus ever will. A meaningful bump in royalty on a strong horizontal well can outpace the entire signing bonus in a short window of production.

When you evaluate a bonus offer, the right comparison isn’t the neighbor’s lease from three years ago. It’s what comparable acreage in your section, township, and formation is trading for right now. Valor manages roughly 500,000 wells across 13 major basins, and the range of bonus-per-acre in an active play can vary widely within a single county depending on drilling proximity, formation quality, and how many operators are competing for the same acreage.

The primary term is the second lever. A short primary term with an option to extend is common in Texas and Oklahoma leases, but the option period is where operators buy cheap time on your acreage. If you’re going to grant an option, the option bonus should meaningfully exceed the initial bonus — not match it. And the royalty rate under the option period should ratchet up, not stay flat. Our mineral management team reviews lease offers regularly and can benchmark yours against recent comparable transactions.

Pugh Clauses: Vertical and Horizontal Both Matter

A Pugh clause is the single most under-negotiated provision in the average mineral lease. Without one, an operator can hold your entire tract — across every depth and every undrilled acre — by producing a single well anywhere on the leased premises. That is the default outcome under most standard lease forms.

A horizontal Pugh clause releases the acreage outside of producing or drilling units at the end of the primary term. If you leased a large tract and the operator drilled one unit that captures only a portion of your acres, a horizontal Pugh releases the balance back to you at term end. Without it, all of it stays held indefinitely.

A vertical Pugh clause (sometimes called a depth clause) releases depths below the deepest producing formation. If your operator drills a shallower target and holds the lease by production, a vertical Pugh returns everything below that formation to you at term end — free to lease to someone else or negotiate a new bonus on the same acreage. In stacked plays like the Midland Basin and the SCOOP/STACK, depth rights below the target zone can be worth as much as the original lease. If the landman resists both, that resistance itself tells you something about the operator’s intentions for the acreage.

Cost-Free Royalty: Where the Money Quietly Leaks

The royalty rate on the front page of your lease means very little if the operator can deduct post-production costs against it. Gathering, compression, dehydration, treating, transportation, and marketing costs can compound to meaningfully reduce your effective royalty depending on the basin, the operator’s midstream arrangements, and how the marketing chain is structured.

Texas courts have consistently upheld operator deductions when the lease language is silent or ambiguous — meaning the default legal outcome favors the operator, not the mineral owner. Oklahoma’s implied-covenant framework is friendlier to owners, but ‘friendlier’ is not ‘protective.’

The fix is explicit lease language. A properly drafted cost-free (or ‘gross proceeds’) royalty clause states that royalty is calculated on the gross proceeds received at the first arms-length sale, with no deductions for any post-production cost of any kind, including affiliate transactions. A generic ‘no deductions’ clause has been narrowed by courts. The clause needs to list the specific categories of costs that cannot be deducted and address affiliate sales explicitly.

Owners who don’t catch this at the lease stage often don’t discover the leak for years. When Valor audits royalty statements for new clients, post-production deductions are one of the most common recovery categories — and a meaningful share of the $27 million recovered in the last 36 months traces back to lease language that could have been written more tightly at signing.

Handling Deadline Pressure and Ancillary Clauses

Almost every lease offer arrives with a stated deadline. That pressure is a negotiating tactic, not a legal reality. A serious lessee that wants your acreage will grant a reasonable extension if you ask in writing. If they refuse a short extension for review, that itself is diagnostic — either the offer isn’t real, or the operator is counting on you not reading it carefully.

A few ancillary clauses that get overlooked under deadline pressure:

  • Shut-in royalty: Should be capped in duration and paid at a meaningful per-acre rate — not the token figures that show up in old lease forms.
  • Continuous drilling obligation: After primary term, the operator should be required to continuously drill on a defined cadence to maintain the entire lease.
  • Assignment and notice provisions: Require written notice of any assignment. Operators change hands, and you need to know who’s actually holding your lease.
  • Warranty of title: Limit or strike warranty language — you shouldn’t be guaranteeing title against defects you don’t know about.

Read every exhibit. Exhibit language routinely modifies or overrides the main body of the lease, and it’s where the operator’s standard-form protections live. If you’re not comfortable reading lease language line by line, that’s the moment to bring in help. Valor’s team of CPAs, CPLs, and CMMs reviews leases as part of our standard mineral management engagements.

How to Structure Your Counter-Offer

When you counter, counter on multiple terms at once — not just the bonus. Landmen expect a bonus counter and often have room built in. What they don’t expect, and what they have less authority to concede, is a well-structured redline that touches royalty rate, Pugh clauses, cost-free language, term length, and shut-in provisions in a single response.

A useful framework: identify the two or three terms you care about most, and the two or three you’re willing to trade. If cost-free royalty is non-negotiable, be prepared to accept a slightly lower bonus. If depth rights matter because you’re in a stacked play, prioritize the vertical Pugh over the horizontal one. Document everything in writing — verbal assurances that ‘we always pay on gross proceeds’ are worth nothing when the lease says otherwise and the operator sells to a successor two years later.

A well-negotiated lease is the difference between decades of clean, defensible royalty income and decades of chasing deductions you agreed to without realizing it. If you have an open offer on your acreage and want a second set of eyes before you sign, contact Valor — our team reviews lease offers as part of our mineral management engagements.

Contact Valor Today

Negotiating your own lease terms is one thing — knowing whether they hold up against what’s actually closing in your area is another. Contact Valor today for a free, no-obligation review — our mineral management team will compare your bonus offer and royalty rate against recent deals in your unit, check your lease for a Pugh clause and cost-free royalty language, and flag any terms that could cost you down the road. We handle lease negotiations 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.

Division Order, Lease Offer, or Buyout? How to Read the Letter About Your Mineral Rights

Posted on by Leonardo

In the past 36 months, Valor has recovered more than $27 million for mineral owners, and a meaningful share of that money traces back to a single moment: a letter arrived, and the owner wasn’t sure what it was. Division order, lease offer, and purchase offer all show up on similar letterhead, all reference your tract, and all ask for a signature. They are not the same document, and confusing them can cost you decades of royalty income. This post walks through how to tell the three apart, what each one actually does to your ownership, and the questions to ask before you sign.

First, Identify Which Letter You Received

Every letter about your minerals falls into one of three buckets:

  • • a division order (a well has been drilled and the operator wants you to confirm your decimal interest),
  • • a lease offer (a company wants the right to drill for a set term),
  • • or a purchase offer (someone wants to buy your minerals outright).

The document title is your first clue, but the title alone is not reliable — some purchase offers are dressed up as “lease amendments,” and some aggressive lease offers contain language that functions like a partial sale.

Read the operative verb. A division order asks you to confirm or acknowledge an ownership decimal. A lease asks you to grant or demise rights for a stated primary term, usually three to five years. A purchase offer asks you to convey, sell, or assign your mineral interest — often “together with all rights, title, and interest.” That verb tells you what is actually happening.

The second clue is what accompanies the letter. Division orders come with a decimal (something like 0.00234567) and a well or lease name. Lease offers come with a bonus-per-net-mineral-acre number and a royalty fraction (three-sixteenths, one-fifth, one-fourth). Purchase offers come with a lump-sum dollar figure and, almost always, a hard deadline. If you are still unsure, our mineral management team reviews these documents every day across the 32 states and 13 major basins we cover.

Division Orders: What They Are and What They Are Not

A division order is a statement from the operator that says, in effect, “we drilled a well, you own a piece of it, and here is the decimal we will pay you on.” It is a payment instruction — not a sale, not a lease, and not a modification of your underlying ownership.

The number to focus on is the decimal interest. It is calculated from your net mineral acres, the unit size, and your royalty fraction from the lease. If any of those inputs are wrong, the decimal will be wrong for the life of the well — and small decimal errors compound into large dollar errors quickly. Across the 500,000 wells we manage, decimal verification is one of the most common places we find money owners were leaving on the table.

Watch for language that goes beyond payment instructions. Some division orders include clauses that attempt to change lease terms — expanding the operator’s right to deduct post-production costs, or ratifying a pooling declaration you never agreed to. In most states, including Texas, you are not required to sign anything beyond a simple confirmation of your decimal and payment address. If a division order asks you to “ratify,” “amend,” or “agree to” anything about the lease itself, that is not a standard division order and deserves review by someone who reads them for a living.

Lease Offers: The Fine Print That Runs for Decades

A lease offer is the document with the most long-term financial consequence — and, ironically, the one owners most often sign in a hurry. A lease conveys the right to explore for and produce oil and gas from your minerals for a stated primary term. In exchange, you receive an upfront bonus payment and a royalty percentage of production. You keep ownership of the minerals; you rent out the drilling right.

Three numbers matter more than the bonus check that grabs your attention:

  • The royalty fraction. One-eighth (12.5%) was standard a generation ago. Today, three-sixteenths (18.75%) and one-fourth (25%) are common in active plays. The difference between one-eighth and one-fourth is literally double the royalty for the life of every well drilled under that lease.
  • The post-production cost language. A “cost-free” or “gross proceeds” royalty is paid on the sales price before deductions. A “net proceeds” royalty allows the operator to deduct gathering, compression, treating, and transportation. Those deductions can quietly consume 15-30% of a gas royalty check.
  • The primary term and continuous-development language. A three-year lease with no extension is very different from a five-year lease with a two-year option and a continuous-drilling clause. The latter can effectively lock up your minerals for a decade or more.

Bonus per net mineral acre is what gets talked about at the kitchen table, but royalty and cost language is what shows up on every check for the next 30 years. Once the lease is signed and filed of record, those terms are extremely difficult to renegotiate.

Purchase Offers: A One-Time Check for a Lifetime Asset

A purchase offer, sometimes called a buyout or a “top-dollar” offer, is a proposal to buy your mineral rights outright. If you sign a mineral deed and it gets recorded, your ownership is gone. Every future royalty check on every future well drilled from that tract belongs to the buyer. There is no take-back.

Purchase offers typically arrive with urgency built in: a check enclosed, a 14-day or 30-day deadline, and language framing the offer as a favor. The buyer is a professional running a valuation model against public data, and the offer price is the number that works for their return threshold — not necessarily the number that reflects the long-term value of your minerals. If your tract sits in a play with future drilling potential, or if you already have wells producing and paying, the buyer is almost certainly offering a fraction of what the asset is worth over time.

That does not mean you should never sell. There are legitimate reasons to monetize minerals — estate simplification, immediate liquidity, exiting a non-core small interest. But you should know what the asset is worth first. Between our portfolio of 500,000 managed wells and roughly $650 million in annual client revenue, we see purchase offers benchmarked against actual value every week. Before you respond to any purchase offer, read Got an Offer to Buy Your Mineral Rights? How to Tell If It’s Actually Fair.

What to Do Before You Sign Anything

The right first move on any of these three letters is the same: do not sign it today. None of them require a same-day response, regardless of what the cover letter says. Take these steps in order:

  • Identify the document type using the operative verb — confirm, grant, or convey.
  • Locate the parcel in your records. Know the county, survey, abstract or section-township-range, and net mineral acres before you evaluate the terms.
  • Pull your prior lease if this is a division order or a new lease offer. Existing terms drive what the new document should say.
  • Get an independent valuation before responding to any purchase offer.
  • Do not ratify pooling, amendments, or cost deductions inside a division order without review.

Valor is SOC 1 Type II certified, and every one of these documents flows through a controlled review process staffed by land and accounting professionals. That process is why the $27 million recovered figure exists — most of that money came from documents that were mis-signed or under-negotiated years before we were involved.

If a letter arrived this week and you are not sure which of the three it is, that is exactly the moment to get a second set of eyes on it. Contact Valor and we will walk through the document with you before you sign, file, or cash anything.

Contact Valor Today

Not sure which of the three you’re holding — and whether it’s actually a good deal? Contact Valor today for a free, no-obligation review — our mineral management team will help you identify exactly what you’ve received, confirm the numbers are accurate, and tell you whether the offer on the table (or the royalty you’re already receiving) lines up with what similar mineral owners are seeing in your area. We handle division orders, lease offers, and buyout evaluations 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.

Valor | Energy Connection – July 6, 2026

Posted on by Valor

July 6, 2026 Edition

At Valor, our goal is to keep you informed of the latest news and updates from the oil and gas industry. We are committed to sharing the insights and knowledge that our team gathers to help you stay ahead in this dynamic sector. From mergers and acquisitions to regulatory changes and technological advancements, we cover all the key developments that impact the industry. Stay tuned for weekly updates to keep you well-informed.

  • OPEC+ approves further oil output increase as Hormuz exports start to recover
  • Summary: OPEC+ agreed to raise production quotas by 188,000 barrels per day from August, adding to prior hikes that increased targets by nearly 800,000 bpd from April through July. Total group output had fallen from 42.77 million bpd in February to 33.13 million bpd in May before beginning a partial recovery in June. Meanwhile, Brent crude traded near $72 per barrel, down from peaks over $120, as the seven core members work to unwind the remaining 379,000 bpd of a 1.65 million bpd cut enacted in 2023.
  • Read more

    Citi: Oil could sink to $60 as Hormuz traffic normalizes
  • Summary: Citigroup projects Brent crude prices could plunge to $60 or $65 a barrel by the end of the year as shipping through the Strait of Hormuz normalizes. Other Wall Street firms have also adjusted their forecasts downward following the signing of the U.S.-Iran memorandum of understanding. Goldman Sachs predicts a global oil surplus of roughly 3 million barrels per day next year, noting that a projected global SPR rebuilding of just over 1 million barrels per day would still leave a 2 million barrel surplus.
  • Read more
  • Execs predict where Henry Hub price will land in future
  • Summary: In the second quarter Dallas Fed Energy Survey, executives from 97 firms projected mean Henry Hub gas prices of $3.35 per MMBtu in six months, $3.45 in one year, $3.75 in two years, and $4.14 in five years. For the end of 2026, 123 executives forecasted an average price of $3.36 per MMBtu, within a range of $2.00 to $4.65, while the average spot price during the survey period was $3.15. Meanwhile, reports noted the August contract closed at $3.275 on Tuesday, up 9.4 cents or 3.0 percent.
  • Read more
  • U.S. energy firms add rigs for third week in a row, says Baker Hughes
  • Summary: The total U.S. oil and gas rig count increased by seven to 580 for the week ending July 2, a figure that is 41 rigs or 7.6% higher than last year’s level. Baker Hughes reported that oil rigs climbed by five to 445, gas rigs rose by one to 126, and miscellaneous rigs grew by one to nine. This activity follows consecutive annual rig count declines of 20% in 2023, 5% in 2024, and 7% in 2025, though the EIA projects 2026 crude output will reach 13.7 million bpd and gas output will hit 111.0 bcfd.
  • Read more

    OPEC oil production jumps, but Gulf supply is still far from normal
  • Summary: OPEC oil production rebounded sharply in June as 11 member nations produced 19.43 million barrels per day, marking a monthly increase of 3.3 million bpd. This rise followed the lifting of a naval blockade under a 60-day agreement, though output remained well below quotas and pre-war tanker traffic levels. Meanwhile, global supply pressures persist as the United States posted record crude production of nearly 14 million barrels per day, and the UAE exported record volumes from its own storage.
  • Read more

    Shell offloads stake in U.S. Gulf production hub
  • Summary: Shell is selling its 50 percent ownership in the Na Kika platform and 100 percent in the Coulomb tieback to Ridgewood Energy and Talos Energy for $1.7 billion. In 2025, the Na Kika platform contributed 37,000 boe a day to Shell’s production and accounted for 4.3 million boe of proven reserves, while Coulomb accounted for 7.2 million boe. In a separate U.S. divestment, Shell completed the transfer of Jiffy Lube International, which comprised 6.5 percent of its regional footprint, for $1.3 billion.
  • Read more

    XRG expands rio Grande LNG stake, now invested across all five trains
  • Summary: XRG acquired an additional 7.6% equity interest in Trains 4 and 5 of the Rio Grande LNG project in Texas from Global Infrastructure Partners. This expands on its prior purchase of an indirect 11.7% stake in Phase 1, which includes Trains 1 through 3. The NextDecade-operated facility has roughly 30 MMtpa of liquefaction capacity under construction, with Trains 4 and 5 adding 12 MMtpa, and it is expected to receive first gas in the second half of 2026 before production begins in 2027.
  • Read more


Contact Valor Today

Contact us today if you need help outsourcing your oil and gas operations.

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. The blog/website should not be used as a substitute for competent legal advice from a licensed professional attorney in your state.

Valor | Energy Connection – June 29, 2026

Posted on by Valor

June 29, 2026 Edition

At Valor, our goal is to keep you informed of the latest news and updates from the oil and gas industry. We are committed to sharing the insights and knowledge that our team gathers to help you stay ahead in this dynamic sector. From mergers and acquisitions to regulatory changes and technological advancements, we cover all the key developments that impact the industry. Stay tuned for weekly updates to keep you well-informed.

  • Magnolia eyes $4 billion WildFire acquisition to expand Eagle Ford position
  • Summary: Magnolia Oil & Gas Corp. has emerged as the front-runner to acquire closely held WildFire Energy for more than $4 billion to boost its presence in the Eagle Ford shale basin. Following this development, Magnolia shares fell 1.5% to $26.78 in New York trading Friday, giving the company an overall market value of around $5.1 billion. WildFire operates more than 2,000 wells with an equivalent output of over 50,000 net barrels of oil per day, and its management sold a previous firm for $1.9 billion.
  • Read more
  • Hormuz oil exodus sets stage for chaotic rebalancing act: Bousso
  • Summary: Brent crude fell to around $73 a barrel after a conflict of over 100 days, while Gulf shut-in production declined to 9.6 million bpd by mid-June from 11.7 million bpd. Iran’s output could reach 3.3 million bpd by year-end, and oil flows briefly exceeded 20 million bpd despite incoming traffic showing only one tanker entering for every four that left. Additionally, global supply is forecast to fall by 3.9 million bpd in 2026 before rebounding by about 8 million bpd to 110.3 million bpd in 2027.
  • Read more
  • U.S. pipeline giant eyes $5.5 billion deal to expand LNG reach
  • Summary: Natural gas giant Williams is in late-stage talks to acquire pipeline operator Momentum Midstream from EnCap Flatrock Midstream for an estimated $5.5 billion. Momentum Midstream operates about 4,000 miles of pipelines with 6 Bcf/d of system capacity, which includes the 250-mile NG3 pipeline that has a total capacity of 2.3 Bcf/d. The acquisition would expand Williams’ reach, which currently handles about one-third of U.S. natural gas and achieved a 25% year-over-year net income increase.
  • Read more
  • U.S. natural gas drops on cooler outlooks as July contract expires
  • Summary: U.S. natural gas futures for July delivery settled 11.2 cents, or 3.3% lower, at $3.231/mmbtu on Nymex as the contract expired amid cooler weather forecasts. The more-actively-traded August delivery contract also ended lower, settling 1.6 cents, or 0.5% down, at $3.279/mmbtu at the Henry Hub. Daily BNEF data showed Lower-48 dry gas production on Friday at 112.6 bcf/day, an increase of 4.9% year-over-year, while total gas demand dropped 6.9% year-over-year to approximately 71.3 bcf/day.
  • Read more

    U.S. energy firms add most rigs in a week since June 2022, Baker Hughes says
  • Summary: The total U.S. oil and gas rig count rose by 10 to 573 in the week to June 26, up 26 rigs or 5% above last year’s level. Baker Hughes reported that oil rigs climbed by seven to 440, gas rigs increased by three to 125, and miscellaneous rigs held at eight. After past rig count declines of 20% in 2023, 5% in 2024, and 7% in 2025, the U.S. Energy Information Administration projected that the total domestic crude output will expand to 13.7 million bpd while gas production jumps to 111.0 bcfd in 2026.
  • Read more

    ExxonMobil announces planned effective date for move to Texas
  • Summary: ExxonMobil announced that its planned move from New Jersey to Texas is expected to take effect on July 1, 2026. The company’s new publicly traded parent entity, ExxonMobil Holdings Corporation, will be incorporated in Texas, marking another major corporate relocation tied to the state’s growing role as a headquarters hub for the energy sector.
  • Read more

    Oil prices climb as U.S.-Iran flare-up shakes market complacency
  • Summary: Oil prices moved higher early Monday as renewed geopolitical uncertainty brought global supply risks back into focus, with Brent and WTI both posting gains. The shift reflected concern that disruptions to shipping routes, infrastructure, or export flows could tighten an already sensitive market. Analysts noted that low inventories and limited spare capacity may leave crude prices exposed to volatility as markets assess whether recent tensions will affect broader supply and demand expectations.
  • Read more


Contact Valor Today

Contact us today if you need help outsourcing your oil and gas operations.

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. The blog/website should not be used as a substitute for competent legal advice from a licensed professional attorney in your state.

Forced Pooling in Oklahoma vs. Texas: What Happens If You Don’t Sign a Lease

Posted on by Leonardo

This post explains what forced pooling means in Oklahoma, the election decision that drives the economics, how Texas handles the same situation, and what to do if a pooling order names your tract. (If you got here after spotting drilling activity nearby, it pairs with our guide on how to read oil and gas activity on your acreage.)

What happens if you don’t sign a lease in Oklahoma?

Your minerals can still be developed — and you can still get paid — without a signed lease. When an operator can’t reach a voluntary lease agreement with every owner in a drilling and spacing unit, Oklahoma law (52 O.S. § 87.1) lets the operator file a pooling application with the OCC. The Commission can then “pool” the uncommitted interests and issue an order that brings those owners into the unit. Not signing a lease does not keep you out of the unit; it simply shifts you from a negotiated lease to a Commission-ordered election.

How does forced pooling work in Oklahoma?

The OCC pooling process runs in three stages: application, hearing, and order. The operator must show a good-faith effort to lease, and the evidence often centers on recent comparable bonus and royalty offers in the area. The Commission then sets the election options in the order. The operator is required to mail a copy of the order to each affected owner within three days, and cash payments to electing owners are generally due within about 30–35 days of the order.

The order gives each unleased owner a set of options — usually a cash bonus paired with a stated royalty (often matching the highest offer made in the unit), one or more alternatives with a lower bonus but a higher royalty (commonly 1/8, 3/16, or 1/5, sometimes a no-cash 1/4 option), or the choice to participate as a working-interest owner. The pooling order also limits how long the operator has to begin drilling — commonly six months to a year — after which the obligation can lapse if no well is commenced.

How long do you have to respond to an OCC pooling order?

Typically 20 days from the date the order is issued — not the date you receive it. This is the detail that costs owners the most. The clock starts when the Commission enters the order, so if the certified-mail notice sat in your box for a week, you’ve already lost part of the window. If you don’t make a written election in time, the order’s default election takes over — often one of the lower-royalty options — which is rarely the best long-term outcome on a productive well. Owners with a stale address at the county courthouse are the ones who most often miss the notice entirely and get defaulted. Once made (or defaulted), your election is binding for that well.

That’s why a current notice address and clean ownership records matter so much in Oklahoma. Verifying your county records before an operator files is far easier than untangling them on a 20-day clock.

Bonus and royalty vs. working interest: which election should you consider?

This is the core economic decision, and the two paths carry very different risk.

Cash bonus plus royalty is the conservative path. You take a one-time bonus per net mineral acre and a stated royalty, you bear no drilling cost, and you carry no dry-hole risk. If the well produces, you’re paid through your royalty; if it’s a bust, you’ve lost nothing beyond opportunity cost. This is what most individual owners elect.

Participating as a working-interest owner means you agree to pay your proportionate share of drilling and completion costs — and a modern horizontal well can cost $5–10 million or more, so even a small owner’s share can run well into five or six figures. In exchange you receive your full share of revenue net of expenses, not just a royalty. The upside on a strong well is real; so is the downside on a weak one. Owners who don’t pay in can also face a risk (non-consent) penalty, where the operator recovers a multiple of your share of costs out of production before you see any money — the exact penalty is set in the order.

Most individual owners aren’t positioned to write a large cost check on short notice, and the bonus-and-royalty path is the common choice. But the right answer depends on the well’s projected economics, your tax position, your liquidity, and the rest of your portfolio — which is exactly the analysis worth doing before the deadline, not after.

Does Texas have forced pooling?

Largely, no — not the way Oklahoma does. Texas has no general compulsory-pooling statute for private mineral interests. If a Texas operator can’t get a holdout to lease, it generally has to lease around the tract, drill so as not to drain the holdout’s minerals, or leave that owner unleased and unbound. The narrow exception is the Mineral Interest Pooling Act (MIPA), passed in 1965 and codified in Chapter 102 of the Texas Natural Resources Code. MIPA lets an operator apply to the Railroad Commission to force-pool a tract, but only after a fair and reasonable voluntary offer has been made and refused, and only under specific conditions — and it’s used rarely because the procedural hurdles are high.

The practical effect: a Texas owner who declines to sign keeps more leverage than an Oklahoma owner does. In Texas, the bigger risks usually live inside the lease — pooling-clause language, depth limits, missing Pugh clauses, and post-production cost deductions. In Oklahoma, the bigger risk is often what happens if you don’t sign at all.

Forced pooling: Oklahoma vs. Texas at a glance

OklahomaTexas
Governing lawForced pooling, 52 O.S. § 87.1Mineral Interest Pooling Act (MIPA), Ch. 102 Natural Resources Code
Administered byOklahoma Corporation Commission (OCC)Railroad Commission of Texas (limited)
Can an unleased owner be brought in?Yes — routinelyRarely — MIPA only, after a refused fair offer
Your deadline to act~20 days from the orderNo general statutory clock
If you do nothingDefault election (usually smallest royalty)You generally remain unleased and unbound
Owner’s negotiating leverageLowerHigher

What should you do if a pooling application names your tract?

Treat it as time-critical and work the steps in order:

First, read the application and note every date — the 20-day election window runs from the order, but the application references earlier hearing dates where you can appear or object. Second, confirm the net mineral acreage the operator has attributed to you by checking it against your title chain. Third, compare the bonus and royalty options against recent leases and pooling orders for the same formation in your unit and county — a number that looks fine in isolation may lag what others nearby received. (A royalty estimate under each option helps you compare apples to apples.) Fourth, weigh working-interest participation only against the well’s projected economics and your own finances. Fifth, file your election in writing before the deadline and keep proof of delivery.

After the well comes online, audit your check detail to confirm the operator is paying on the exact terms the OCC ordered. Pooling orders that aren’t checked against the operator’s actual payments are a recurring source of underpayment.

If a pooling notice is on your desk now, talk to Valor about your unleased-minerals options — we handle OCC notices, election analysis, and royalty audits for owners across Oklahoma, Texas, and 30 other states.

Frequently asked questions

What is forced pooling in Oklahoma? It’s a process administered by the Oklahoma Corporation Commission under 52 O.S. § 87.1 that lets an operator bring unleased mineral owners into a drilling unit when a voluntary lease agreement can’t be reached. The owner is given election options instead of negotiated lease terms.

What happens if I don’t respond to an OCC pooling order? You’re assigned the order’s default election, typically the smallest-royalty option. On a productive well that usually leaves money on the table, and the election is binding once the deadline passes.

How long do I have to make my election? Usually 20 days from the date the order is issued — not the date you receive it. Because the operator only has to mail the order within three days of issuance, mail delays eat into your window.

What are my options under a pooling order? Generally a cash bonus plus a stated royalty (often 1/8, 3/16, or 1/5, sometimes a no-cash 1/4), or electing to participate as a working-interest owner and pay your share of well costs in exchange for a larger share of revenue.

Does Texas have forced pooling like Oklahoma? Not generally. Texas has no broad compulsory-pooling statute for private minerals; the narrow Mineral Interest Pooling Act applies only in limited circumstances and is rarely used, so unleased Texas owners keep more leverage.

Can I sell my minerals after a pooling order is issued? Yes — a pooling order doesn’t prevent a sale before, during, or after the process. Operators usually only pursue pooling when they intend to drill, which is information worth weighing in any decision.

Contact Valor Today

If an OCC pooling order is already on your desk, the 20 days before your election are when it matters most to have someone in your corner. Contact Valor today for a free, no-obligation review — our mineral management team will confirm the net acreage attributed to you, compare your bonus and royalty options against recent deals in your unit, and flag anything the order isn’t telling you before the clock runs out. We handle unleased-minerals and pooling situations 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.

How to Read Oil and Gas Activity on Your Acreage

Posted on by Leonardo

If you own mineral rights, knowing how to read oil and gas activity on your acreage is one of the most valuable skills you can develop. Permit filings, test wells, and new drilling units don’t always come with an explanation — but they do tell a story. Understanding what’s happening nearby can help you evaluate a lease offer, anticipate contact from an operator, and make more informed decisions about your minerals.

Here’s how to interpret the most common signals.

Step 1: Start With Permit Filings

A drilling permit is the first public signal that an operator intends to drill. In Texas, permits are filed with the Railroad Commission of Texas (RRC) and are searchable by county, operator, and lease name at rrc.texas.gov.

When you see a permit filed near your acreage, note:

  • The operator name — who is actively leasing and drilling in your area
  • The well type — oil, gas, injection, or disposal
  • The target formation — which zone they’re drilling into (Wolfcamp, Spraberry, Cotton Valley, etc.)
  • The surface location and direction — this matters more than most mineral owners realize (see Step 3)

A permit doesn’t guarantee a well gets drilled, but a cluster of permits in your county is a strong signal of operator interest and is often followed by lease activity.

Step 2: Understand What a Test Well Means

A test well — sometimes called an exploratory or wildcat well — is drilled to evaluate whether a formation is commercially productive in a new area. If you’re seeing updates about a test well near your acreage (like the Expand Lavinski 1 referenced in Stephens County discussions), pay attention to the completion report.

What to watch for:

  • Initial production (IP) rates — reported in barrels of oil per day (BOPD) or Mcf of gas per day. A strong IP rate signals a productive formation.
  • Formation tested — confirms which zone the operator is targeting and whether your acreage may be in the same play
  • Whether the well was completed or plugged — a plugged test well isn’t necessarily bad news; it may mean the operator is narrowing their target zone

Test well results often precede a wave of leasing activity in the surrounding area. If a test well near you reports strong production, expect lease offers to follow.

Step 3: Slant and Horizontal Drilling — What It Means for Your Minerals

This is where mineral owners get confused most often — and where the stakes are highest.

Horizontal drilling means the wellbore turns and travels laterally through a formation, sometimes for a mile or more. A well with a surface location on a neighbor’s property can be drilled horizontally under your acreage and produce from your minerals. If you’re not leased when that happens, you may be force-pooled — included in the drilling unit at terms set by the operator or the state, rather than terms you negotiated.

Slant drilling is a variation where the wellbore is intentionally deviated at an angle. It’s used to reach a target that’s offset from the surface location, or to drill under obstacles. In areas like Upshur County, slant drilling has been a point of confusion for mineral owners who see surface activity nearby but don’t understand why their acreage is involved.

What to do: If you see horizontal drilling permits in your county, check whether your acreage falls within the proposed unit. In Texas, proposed pooling units are filed with the RRC. A landman or mineral manager can run this check for you quickly.

Step 4: How to Read Production Numbers

Once a well is producing, production data is publicly reported. In Texas, operators report monthly production to the RRC, and the data is accessible through the RRC’s online portal or third-party platforms.

Key numbers to understand:

  • Gross production — total oil or gas produced from the well
  • Your net revenue interest (NRI) — your royalty fraction of gross production. A 1/5 (20%) royalty on a well producing 10,000 barrels means 2,000 barrels attributed to all interest owners in your unit
  • Decline curve — production typically peaks at first and declines over time. A well in early production is worth more than one that’s been producing for five years

Production data also helps you verify your royalty statements. If an operator reports significantly more production than what your check reflects, it may indicate an error — or a suspense issue worth investigating.

Step 5: What Activity Near You Means for Value and Offers

Operator activity is the single biggest driver of near-term mineral value. Here’s how to connect the dots:

  • New permits filed nearby → operators are actively developing the area; lease offers likely incoming
  • Strong test well results → formation is proven; your acreage has increased value
  • Horizontal units being formed → you may be included; act before force pooling locks in your terms
  • Active production on offset acreage → your minerals are in a productive zone; bonus and royalty negotiations have more leverage

If you’ve received a lease offer and there’s active drilling nearby, that offer price reflects what the operator thinks your acreage is worth — which may be considerably less than what you could negotiate with the right information.

Contact Valor Today

If an offer is sitting on your kitchen table right now, the days before you respond are when it matters most to have someone in your corner. Contact us today for a free, no-obligation review — our mineral management team will verify what you own, evaluate what the developer is really paying for, and flag what the offer isn’t telling you before you sign anything you can’t take back.

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.