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Category: Mineral Rights

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

Why $100 Oil Hasn’t Hit Your Royalty Check Yet — And When It Will

Posted on by Leonardo

As of mid-May 2026, oil prices have been elevated for weeks, with WTI recently trading above $100 amid continued Strait of Hormuz disruption. For mineral owners, that raises an obvious question: if the market has already moved, why hasn’t my royalty check caught up?

The answer depends on which production month your check is paying, your operator’s accounting cadence, whether your production is oil- or gas-weighted, and whether deductions, suspense, title issues, or division-order problems are delaying the pass-through.

This post walks through why higher oil prices may not have fully hit your statement yet, when they could begin showing up, and what to watch for when they do.

The Royalty Payment Cycle Runs Behind the Wellhead

Production happens in real time. Payment does not. For most operators in Texas and Oklahoma, oil produced in a given month is sold, gauged, run-ticketed, and reconciled over the following 30-45 days. The operator then cuts royalty checks another 30-45 days after that. The practical result: oil pulled out of the ground in month one typically lands in your bank account in month three.

That timing matters even more when prices have been elevated for weeks. If oil first moved higher in April, your May check may still be paying March production, or only beginning to reflect early-April production depending on your operator’s payment cycle. In other words, the market may have moved — but your statement may not have reached that production month yet.

It isn’t usually operator slow-walking. It’s the result of purchaser settlement, operator accounting cycles, title review, minimum-pay thresholds, and state-specific payment rules. Valor’s mineral management team tracks these cycles operator by operator, because the lag varies — and knowing your operator’s specific cadence is the difference between expecting upside and waiting for it.

Gas Owners May Wait Longer Than Oil Owners

If your production is weighted toward gas, the timing can be even less straightforward. Oil pricing is generally tied to a posted monthly average that settles relatively quickly. Gas pricing flows through marketing contracts indexed to hubs like Waha, Henry Hub, or Houston Ship Channel, often with a one-month settlement built in before the operator even calculates your share.

Layer that on top of the standard 60-90 day royalty cycle and gas owners can wait four months or longer for a price event to show up on a check. For owners with mixed production, expect oil-weighted upside first, then a second wave on the gas side.

This is also why a short-lived price move may barely register for some gas owners. The price increase has to last long enough to survive the averaging, indexing, and settlement mechanisms built into the applicable marketing arrangement.

What Will Actually Show Up — And What Won’t

When the higher prices do flow through, the upside is rarely a clean dollar-for-dollar pass-through. A few line items on your check detail are worth watching closely:

  • Realized price vs. benchmark. Your check should show the price the operator received, not the WTI or Henry Hub headline. Differentials, gravity adjustments, and gathering deductions all sit between the headline and your number.
  • Post-production deductions. Transportation, processing, and compression deductions often scale with revenue. A higher price can mean higher absolute deductions, even if the percentage holds.
  • Suspense. If your account is in suspense for any reason — title issue, address change, unsigned division order — the price increase accrues but doesn’t pay until suspense clears.
  • Severance and ad valorem taxes. These come off the top and rise with price.

The owners who capture the most upside during volatile markets are usually the ones who already have clean records, current division orders, accurate ownership decimals, and no unresolved suspense balances. The ones who do not may be leaving real money on the table — and the operator is not always going to flag it for them.

What to Watch on Your Next Three Statements

Treat the next three royalty statements as a sequence, not three isolated checks. Pull last month’s statement, this month’s, and next month’s side by side when they arrive. You’re looking for three things.

First, review the production month on each line. That tells you which check is paying for which barrels or MCFs, and whether the statement has actually reached the period when prices were elevated.

Second, review the realized price column. If WTI or regional gas indexes moved sharply and your realized price does not move at all, that is worth investigating. There may be a valid explanation — such as basis, contract timing, or averaging — but it should be explainable.

Third, review the deduction lines. If deductions jump faster than gross revenue, or if a new deduction category appears, dig in. The issue may be legitimate, but volatile markets are exactly when small statement changes can become meaningful.

The most common owner-side miss during a price move is not necessarily missing the price event entirely. It is failing to verify that the price event was fully and accurately reflected after the lag. That verification work is exactly what our team of CPAs, CPLs, and CMMs handles for clients every month.

Why the Audit Work Matters More During Volatile Markets

In the last 36 months, Valor has recovered more than $27 million for mineral owners — money that was owed, underpaid, or never paid at all. A meaningful share of recoveries in volatile markets can trace back to familiar issues: a price event, a payment lag, a deduction that does not line up, a suspense balance that quietly accrued, or an ownership correction that was never fully resolved. Our story page walks through how that recovery work happens.

The owners most exposed to underpayment during a price spike are the ones with the least visibility into their own data. Operators are not adversaries — but they are processing tens of thousands of owner accounts on tight cycles, and the burden of catching errors falls on the owner. Volatile prices amplify both the upside and the risk of error.

If you want a second set of eyes on your statements while prices are moving — or you’re not sure whether the upside is actually flowing through — our mineral management team reviews exactly this work for owners every day. A volatile market is the worst time to be guessing.

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.

Top 10 Texas Operators by Drilling Permit Volume: What Mineral Owners Should Watch

Posted on by Leonardo

If you own minerals in Texas, the operator filing permits near your tract today is the operator writing your royalty check 12-18 months from now. Across the last 90 days ending May 4, 2026, 308 distinct operators filed a combined 2,273 drilling permits in Texas — but the top filer alone accounts for 9% of that total. This post ranks the ten operators driving the bulk of new Texas drilling activity, flags where they’re concentrating, and explains what mineral owners should do with that information.

Diamondback and EOG Are Setting the Pace

Diamondback Operating, LP filed 200 permits over the last 90 days — roughly one in every eleven Texas drilling permits in the window. Their activity spans 6 counties, with their most recent permit filed April 27, 2026. EOG Resources came in second at 99 permits but spread that activity across 9 counties, the widest geographic footprint in the top 10.

The takeaway for mineral owners: Diamondback is drilling deep in a concentrated set of counties, while EOG is keeping optionality across a broader Texas footprint. If your tract sits in Diamondback’s core counties, expect heavier near-term activity. If you’re in EOG country, expect activity but at a slower per-county cadence.

You can review each operator’s filing history on the Diamondback Operating, LP profile and EOG Resources profile.

The Rest of the Top 10

Behind the two leaders, the next eight operators filed between 45 and 55 permits each — a tight cluster that combined for the bulk of remaining top-10 activity. The top 5 operators alone accounted for 461 permits, or about 20% of all Texas drilling permits filed in the window.

COG stands out for concentration — 55 permits in a single county is the most focused activity in the top 10. Apache, by contrast, is spreading 53 permits across 7 counties, which suggests a broader development plan and likely more pad-by-pad timing variation for owners under their leases. Browse any of these in the operator directory.

A Note on Apache and Permian: Same Filer, Different Names

Two pairs in the top 10 deserve a footnote. Apache Corporation and Apache Energy Resources Corp both filed exactly 53 permits across 7 counties with a latest filing date of April 8, 2026. Permian Corporation and Permian Resources Operating, LLC each filed 45 permits across 2 counties with a latest filing date of March 24, 2026.

These near-identical filing patterns strongly suggest the same parent operator filing under multiple legal entities — a common practice driven by joint venture structures, leasehold ownership, or post-acquisition entity cleanup. For a mineral owner, this matters: your division order, your suspense status, and your check stub may all reference one entity name while the permit on file with the RRC sits under a different one. Reconciling those names is part of basic mineral management hygiene.

What the Geographic Spread Tells You

Counties-active is the most underrated number in this dataset. EOG’s 9 counties and Apache’s 7 counties signal operators making bets across multiple plays. COG’s 1 county and the Permian-named entities’ 2 counties signal operators executing a focused, repeatable program — which usually means tighter spacing, faster pad cadence, and more predictable lease development for mineral owners in those specific areas.

If you’re a mineral owner trying to read the tea leaves on when your tract gets drilled, the operator with 1-2 active counties and 45-55 permits in 90 days is the one to watch hardest. That’s an operator working through a defined inventory.

The full filing feed updates as new permits hit the public record — see recent Texas drilling permits for the live view.

How Mineral Owners Should Use This Data

A leaderboard is a starting point, not an answer. The right next step depends on whether the operator on this list is already on your check stub, holds a lease on your tract, or is simply drilling near you.

If one of these top 10 operators is your lessee, their permit pace is a leading indicator of when (and how often) royalty income will arrive. If they’re a neighbor — say, Diamondback drilling next door but you’re leased to someone else — their activity still affects your offset wells, your formation pressure, and potentially your own operator’s drilling decisions. The active permits directory lets you cross-reference all current permit holders against your tract.

Tracking permit pace by operator is one of the simplest leading indicators a mineral owner has — but only if it’s connected to your specific tract, lease, and check stub. If you’d rather have someone monitor this for you and flag what’s relevant to your interests, learn more about Valor’s mineral management services.

Mineral Rights 101: What Every Owner Should Know About Ownership, Leasing, and Royalties

Posted on by Valor
Quick Answer: Mineral rights are the legal ownership of underground resources like oil, natural gas, coal, and other minerals beneath a property. These rights can be sold, leased, or inherited separately from surface rights. Mineral owners receive royalty payments when resources are extracted from their property.

What Are Mineral Rights?

Mineral rights are the legal rights to explore, extract, and sell minerals found beneath the surface of a property. In the United States, mineral rights can be owned separately from surface rights, meaning the person who owns the land surface may not own the minerals underneath. This concept of severed estates is fundamental to understanding mineral ownership and is unique to American property law.

When you own mineral rights, you own the oil, natural gas, coal, metals, and other subsurface resources beneath a defined tract of land. This ownership includes the right to lease those minerals to exploration and production companies, receive royalty payments from production, sell or transfer the mineral interest, and pass the minerals to heirs through inheritance.

How Mineral Rights Become Severed

Historically, when land was originally granted or sold, the owner typically held both surface and mineral rights together. Over time, these rights were often separated through various transactions. Common ways mineral rights become severed include:

  • Reservation in Deed – When a landowner sells property but reserves the mineral rights, creating two separate estates
  • Mineral Deed – When a landowner sells or conveys only the mineral rights while retaining the surface
  • Inheritance – When estates are divided among heirs, some may receive surface rights while others receive minerals
  • Corporate Transactions – When companies that owned both surface and minerals are split or sold in parts

Many severances occurred decades ago, sometimes in the early 1900s when oil was first discovered in various regions. This means current surface owners are often surprised to learn they do not own the minerals beneath their land.

Types of Mineral Interests

Fee Simple Mineral Interest

A fee simple mineral interest represents complete ownership of the minerals beneath a tract of land. The owner has the right to lease the minerals, develop them directly, sell them, or pass them to heirs. This is the most complete form of mineral ownership and continues in perpetuity unless sold or transferred.

Royalty Interest

A royalty interest entitles the owner to a share of production or revenue without the right to lease or develop the minerals. Royalty interests are typically created when a mineral owner leases to an operator and retains a royalty, or when a mineral owner carves out and sells a royalty interest while retaining the executive rights. Royalty owners receive their share free of production costs.

Non-Participating Royalty Interest (NPRI)

An NPRI is a royalty interest where the owner receives a share of production but has no right to participate in leasing decisions. The NPRI owner cannot negotiate lease terms or bonus payments—those rights remain with the mineral owner who holds the executive rights. NPRIs are often created in estate planning or when mineral interests are divided among family members.

Overriding Royalty Interest (ORRI)

An overriding royalty interest is carved from the working interest under a lease rather than from the mineral estate itself. ORRIs are commonly assigned to landmen, geologists, or other parties as compensation for their work in acquiring leases. Unlike mineral royalties, ORRIs terminate when the underlying lease expires or is released.

Working Interest

A working interest is the right to explore and produce minerals, along with the obligation to pay a share of drilling and operating costs. Working interest owners bear the financial risk of development but also receive the largest share of production revenue (after royalties are paid). Working interests can be operated or non-operated depending on who manages daily operations.

The Mineral Leasing Process

Lease Negotiation

When an oil and gas company wants to drill on land where you own minerals, they must first obtain a lease. The lease negotiation process typically involves a landman who contacts the mineral owner to propose terms. Key terms include the bonus payment (upfront payment per acre), royalty rate (percentage of production revenue), primary term (initial lease duration), and various clauses governing operations.

Lease Terms to Understand

Important lease provisions include:

  • Royalty Clause – Specifies the percentage of production the mineral owner will receive
  • Primary Term – The initial period during which the lessee must begin drilling or the lease expires
  • Habendum Clause – Governs how long the lease continues once production begins
  • Pooling Clause – Allows the lessee to combine your minerals with neighboring tracts to form drilling units
  • Depth Clause – May limit the lease to certain geological formations
  • Surface Use Provisions – Define how the surface may be used for drilling operations
  • Shut-In Clause – Allows the lease to be maintained by payment when a well is not producing

Lease Expiration and Extension

Leases have a primary term, typically three to five years, during which the operator must establish production or the lease expires. Once production begins, most leases continue as long as oil or gas is produced in paying quantities. Some leases include extension options or continuous drilling clauses that can maintain the lease even without production from the specific tract.

Royalty Payments Explained

How Royalties Are Calculated

Royalty payments are calculated based on your decimal interest in a well multiplied by the value of production. Your decimal interest depends on your mineral ownership (expressed as a fraction of the whole), your royalty rate under the lease, and how your minerals were pooled into the drilling unit. For example, if you own 50% of the minerals in a 640-acre unit with a 1/4 royalty, your decimal interest would be calculated as: 0.50 × 0.25 = 0.125 (or 12.5% of production revenue).

Understanding Deductions

Depending on your lease terms and state law, certain costs may be deducted from your royalty payments. Common deductions include post-production costs such as gathering, transportation, compression, and processing fees. Some leases specify that royalties are paid free of these costs, while others allow deductions. Understanding what deductions apply to your payments is important for verifying their accuracy.

Payment Timing

Most operators pay royalties monthly, though there is typically a lag between production and payment. This delay occurs because operators must receive payment from purchasers before distributing royalties, and they need time to calculate and process payments to all interest owners. State laws often specify the maximum time an operator has to make first and subsequent payments after production begins.

Researching Your Mineral Rights

County Records

Mineral ownership is established through recorded documents at the county clerk’s office where the property is located. These records include deeds, mineral conveyances, leases, and other instruments that create or transfer interests. Title research involves tracing the chain of ownership from the original grant through all subsequent transfers to establish current ownership.

State Oil and Gas Commission Records

State regulatory agencies maintain records of drilling permits, well completions, production reports, and operator information. In Texas, this is the Railroad Commission. In Oklahoma, it is the Corporation Commission. These agencies provide valuable information about wells drilled on or near your mineral interests and current production levels.

Division Orders and Check Stubs

If you are already receiving royalty payments, your division orders and check stubs contain important information about your ownership. Division orders state your decimal interest in each well, while check stubs show production volumes, prices, and any deductions. These documents help verify that payments match your understanding of your ownership.

Protecting Your Mineral Rights

Keep Records Current

Maintain copies of all documents related to your mineral ownership, including deeds, leases, division orders, and correspondence with operators. Keep your contact information current with all operators paying you royalties. If you move, notify operators promptly to ensure payments continue without interruption.

Respond to Correspondence

Operators and landmen send correspondence for various reasons—lease offers, division order updates, pooling notices, and more. Responding to this correspondence is important for protecting your interests. Ignoring communications can lead to missed opportunities or problems with your ownership records.

Monitor Production and Payments

Review your royalty statements regularly to verify that payments match production reports and lease terms. Compare payments across wells and over time to identify any unusual changes. If you notice discrepancies, contact the operator for clarification.

Understand Dormant Mineral Laws

Many states have dormant mineral statutes that can affect unused mineral rights. These laws vary significantly by state and may allow surface owners to claim abandoned minerals or require mineral owners to record their interests periodically. Understanding the laws in states where you own minerals helps ensure you do not inadvertently lose your rights.

Transferring Mineral Rights

Selling Mineral Rights

Mineral rights can be sold like any other real property interest. Sales are typically documented through a mineral deed that must be recorded in the county where the minerals are located. The value of mineral rights depends on factors including current and potential production, commodity prices, remaining reserves, and lease terms. There is an active market of mineral buyers who acquire interests from individual owners.

Gifting and Estate Planning

Mineral rights can be transferred to family members through gifts or included in estate plans. These transfers require proper documentation and recording. Many families choose to keep minerals together through entities like family limited partnerships or LLCs rather than dividing them among multiple heirs. Consulting with professionals who understand both mineral rights and estate planning is advisable for complex situations.

Inheritance

When a mineral owner passes away, their interests transfer according to their will or, if there is no will, according to state intestacy laws. Heirs must typically provide death certificates, probate documents, and affidavits of heirship to establish their ownership. Recording these documents in the county ensures clear title for the new owners.

Common Questions from Mineral Owners

How do I find out if I own mineral rights?

Review your deed carefully to see if minerals were conveyed or reserved. If the deed is unclear, research the county records to trace the mineral ownership through previous transactions. A title search can establish whether minerals were severed and who currently owns them.

Why am I not receiving royalty payments?

Several reasons could explain missing payments: there may be no active production on your minerals, your interest may be too small to generate significant revenue, payments may be held in suspense due to title issues, or the operator may not have your current contact information. Contact the operator to inquire about your status.

Should I lease my minerals?

The decision to lease depends on your individual circumstances, the terms offered, and activity in your area. Leasing provides upfront bonus payments and potential royalty income if production occurs. However, lease terms vary significantly, so understanding what you are agreeing to is important before signing.

What happens if I do not respond to a pooling order?

Pooling procedures vary by state. In some states, if you do not respond to a pooling application, you may be force-pooled into the unit at terms set by the state regulatory agency. These terms may be less favorable than what you could negotiate voluntarily. Responding to pooling notices allows you to participate in the process and potentially negotiate better terms.

Mineral rights represent a valuable asset class that requires understanding and attention to manage properly. Whether you have recently inherited minerals, are considering leasing, or want to better understand your existing interests, taking time to learn about mineral ownership fundamentals will help you make informed decisions about your assets.

Related Articles

Lease Management 101: What Every Mineral Owner Should Know

Posted on by Valor
Quick Answer: Lease management involves tracking lease terms, expiration dates, royalty obligations, and operator compliance. Key tasks include monitoring primary terms, verifying shut-in payments, ensuring timely drilling, and protecting your rights through proper documentation and correspondence.

A practical guide to understanding mineral leases, key terms, and how proactive management can protect and maximize your mineral rights.

If you own mineral rights, understanding lease management is essential. It’s not just about signing paperwork—it’s about making informed decisions that directly impact your revenue, your rights, and your long-term asset strategy. Poorly managed leases can result in lost income, missed opportunities, and legal headaches.

What is a Mineral Lease?

A mineral lease grants an operator the right to explore for and produce oil, gas, or other minerals from your property. In exchange, you can receive a bonus payment upfront and ongoing royalties from production. These leases are legally binding agreements and can span years or even decades, so getting them right from the start is crucial.

Key Terms to Understand

Before signing a lease, it’s important to understand the key components:

  • Bonus: A one-time upfront payment made when the lease is signed. This can vary widely based on location, market conditions, and the perceived value of your minerals.
  • Royalty Rate: The percentage of production revenue you’re entitled to. Even a small difference in this rate can have significant long-term financial impact.
  • Lease Term: The initial period granted to begin drilling, often with provisions for extension.
  • Shut-In Clause: A clause that allows an operator to maintain the lease during periods of non-production, typically with minimal royalty payments.
  • Pugh Clause: Ensures non-producing portions of your acreage are not indefinitely tied up under an active lease.
  • Depth Severance: Prevents operators from holding deeper rights they aren’t actively developing.

Risks of Poor Lease Management

Without proper oversight and knowledge, mineral owners may:

– Accept unfavorable terms that reduce income or limit future options

– Overlook critical deadlines, such as lease expirations or renewal windows

– Fail to audit payments, leading to underpaid royalties

– Lose opportunities to re-lease to more competitive operators

Additionally, many owners are unaware of clauses that could either protect or harm their interests, such as surface use agreements or pooling provisions. These details can significantly affect your control and earnings.

How Valor Supports You

Lease management is not just about negotiation—it’s about continual oversight. Our experienced land professionals:

– Review and negotiate lease terms on your behalf to ensure fairness and maximize revenue

– Track renewal dates, production obligations, and expiration timelines

– Ensure all royalty payments are made accurately and promptly

– Organize and maintain your lease portfolio digitally within mineral.tech® for full visibility

– Provide proactive guidance to avoid pitfalls and take advantage of market opportunities

We act as your advocate, bringing deep industry knowledge to each decision and helping you maintain control of your assets. Whether you’re approached with a new lease offer or need support managing multiple legacy leases, Valor ensures you have the information and insight you need to make the best decisions.

Lease management isn’t a one-time task. It’s an ongoing responsibility that requires attention to detail and knowledge of industry practices. With the right partner, mineral leasing can be a strategic asset rather than a source of uncertainty. At Valor, we’re committed to protecting your interests and optimizing your returns every step of the way.

Contact

Are you ready to transform your oil and gas assets? Contact Valor today to learn how our innovative solutions can elevate your business to new heights.

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 Changing Oil Prices Impact Mineral Rights and Royalties

Posted on by Valor

When oil prices shift, mineral owners may feel the effects—but not always immediately.

Mineral royalties are directly tied to the price at which oil and gas are sold, making commodity pricing one of the most important factors influencing a mineral owner’s income.

After oil is extracted, it is sold by the operator at the current market rate—typically tied to benchmarks like WTI (West Texas Intermediate). The total gross revenue from that sale becomes the foundation for calculating your mineral rights royalties.

1. Fixed Percentage: Owners are entitles to a set percentage (often 12.5% to 25%) of gross revenue.
2. Revenue vs. Profit: This percentage is based on revenue before expenses. If the price of oil drops from $80 to $65 per barrel, the revenue drops proportionally, even if production volume remains constant.
3. Post-Production Deductions: Operators may apply costs for transportation or processing, which can further decrease the net payment.

When prices are strong, owners benefit from higher revenues and increased activity. When prices decline, owners can expect a dip in income—though it may take a few months to appear due to payment lags.

How Quickly Do Mineral Owners Feel the Impact?

Royalty payments typically lag behind actual production and pricing by 60 to 90 days. This delay occurs because operators must report production, calculate revenue, and distribute payments.

For example:
1. Oil sold in January is often paid out in March or April.
2. A price drop in April might not show up in your royalty check until June or July.

This delay is due to the time it takes for operators to report production, calculate revenue, and distribute payments to royalty owners.

What About Gas Prices?

For mineral owners with natural gas-producing assets, the same principles apply—but with potentially more volatility. Gas prices are influenced by seasonal demand (like winter heating or summer electricity usage), storage levels, and export capacity, in addition to global market forces.

Do Lower Oil Prices Affect Operators?

Absolutely. Lower prices squeeze profit margins for operators, which can lead to:

• Slower Production: Marginal wells may be throttled back or shut-in.
• Delayed Projects: New drilling or oil and gas outsourcing projects may be postponed.
• Shut-ins: If a well becomes uneconomic to operate, income may cut off temporarily.

In short, sustained low prices can lead to reduced cash flow for both operators and mineral owners alike.

How Oil Prices Impact the General Public

Fluctuations don’t just affect mineral management; they influence the broader economy. Rising prices increase fuel and shipping costs, driving inflation. Falling prices offer relief at the pump but can result in job losses in oil-dependent regions. Oil prices remain a key economic indicator with wide-reaching impact.

What Drives Oil Price Changes?

Understanding the factors that influence oil prices helps mineral owners anticipate potential changes to their royalty income. Key drivers include:

Global Supply and Demand: When demand exceeds supply, prices rise. Economic growth in major consuming countries increases demand, while recessions reduce it. Supply disruptions from geopolitical events, natural disasters, or production cuts by major producers can cause rapid price increases.

OPEC+ Decisions: The Organization of the Petroleum Exporting Countries and its allies control a significant portion of global oil production. Their decisions to increase or decrease output quotas directly impact global supply and prices.

U.S. Production Levels: American shale production has become a major force in global oil markets. Increases in domestic drilling activity add supply and can moderate prices, while slowdowns can tighten markets.

Currency Fluctuations: Oil is priced in U.S. dollars. When the dollar strengthens against other currencies, oil becomes more expensive for foreign buyers, potentially reducing demand and prices.

Inventory Levels: Crude oil inventories reported by the U.S. Energy Information Administration serve as indicators of supply and demand balance. Rising inventories suggest oversupply, while declining inventories indicate tightening markets.

Strategies for Mineral Owners During Price Volatility

While mineral owners cannot control commodity prices, they can take steps to manage through periods of volatility:

Maintain Accurate Records: Keep detailed records of production volumes and prices received. This helps identify whether payment changes reflect price movements, production declines, or other factors that may need investigation.

Understand Your Lease Terms: Review your lease provisions regarding shut-in payments, minimum royalties, and how prices are calculated. Some leases tie payments to specific price indices while others use actual sales prices.

Monitor Production Reports: Track production from your wells through state regulatory filings. Production changes can compound price effects—declining production during low prices creates a double impact on royalty income.

Plan for Income Variability: Royalty income will fluctuate with commodity prices. Accounting for this variability in personal financial planning helps mineral owners weather downturns without distress.

Staying Prepared with a Long-Term View

Mineral ownership is a long game. Prices will always rise and fall, but informed owners can weather the volatility. At Valor, we help owners by:

1. Monitoring Revenue Trends: Identifying unexpected dips.
2. Audit Oversight: Ensuring assets are optimized through our oil and gas back-office expertise.
3. Digital Transparency: Using mineral.tech® to provide real-time insights into production data.

Regardless of market shifts, having the right team and technology in place ensures your interests are managed proactively and your documentation is always in order.

FAQ

• Which benchmark should I watch? If your minerals are in the U.S., track WTI (West Texas Intermediate).
• Why does my statement vary if prices are steady? Variations are usually due to production volume fluctuations or specific post-production deductions.

How Valor Helps Provide Clarity and Stability

In a constantly shifting market, mineral owners need more than just royalty checks—they need transparency, organization, and dependable support. At Valor, we bring clarity to your portfolio through powerful technology and dedicated expertise. With our proprietary software, mineral.tech®, and experienced in-house team, we provide real-time insights into your revenue trends, production data, and asset performance. This level of visibility allows you to feel confident in your income, regardless of changes in commodity pricing. Our role is to ensure your interests are managed proactively, your documentation is in order, and you always have a clear picture of what you own and what it’s earning. When markets move, you can count on Valor to be a steady, informed partner—helping you make sense of every statement and supporting long-term financial stability.

Contact

Are you ready to transform your oil and gas assets? Contact Valor today to learn how our innovative solutions can elevate your business to new heights.

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 Do I Find Out If I Own Mineral Rights?

Posted on by Valor
Quick Answer: To find out if you own mineral rights: (1) Review your property deed for mineral reservations or conveyances, (2) Search county deed records for the chain of title, (3) Look for any mineral deeds or lease agreements in your family records, (4) Check if you receive royalty payments or lease offers, (5) Hire a landman or title company to conduct a professional title search.

If you’re curious whether you own mineral rights to a property, the journey to discovery can feel overwhelming. Understanding and confirming mineral rights ownership involves research, legal documentation, and sometimes professional assistance. This guide will help you navigate the process step by step.

What Are Mineral Rights?

Mineral rights are the ownership rights related to natural resources beneath the surface of a property, such as oil, gas, coal, or other minerals. Ownership can be distinct from the surface rights of the property. This means it’s possible for someone else to hold mineral rights to a piece of land you own.

Steps to Determine Mineral Rights Ownership

  1. Review Your Property Deed– Check the title and deed to your property. These documents often indicate whether mineral rights were included or severed when the land was purchased. If you’re unsure how to interpret the language, a mineral management advisor can assist.
  2. Search County Records– Visit the county courthouse or use online databases to research historical deeds and transactions related to your property. A thorough search can reveal whether the mineral rights were transferred or retained by previous owners.
  3. Consult a Professional– Determining mineral ownership can be complex, especially if rights have changed hands multiple times. This is where a mineral management company such as Valor can be a trusted partner in mineral management. Our team offers personalized services to help clients uncover and understand their mineral rights. From conducting title research to assisting with legal documentation, we ensure you have clarity and confidence in your mineral ownership.

What If You Do Own Mineral Rights?

Owning mineral rights can be a valuable asset, but managing them effectively requires expertise. At Valor, we specialize in helping mineral owners maximize the value of their assets. Whether it’s through lease negotiation, royalty management, or division order processing, our trusted mineral managers are here to provide custom solutions tailored to your needs.

Using proprietary mineral management software like mineral.tech® and our deep expertise in oil and gas accounting, we simplify the complexities of mineral management. If you’re located in Texas or key oil and gas regions like the Permian Basin, Valor is positioned to deliver both local expertise and personalized service. Let us take the stress out of managing your mineral rights so you can focus on what matters most.

Ready to Take the Next Step?

Ready to uncover the full potential of your mineral rights? Contact Valor today to learn how we can support and simplify your mineral management needs.

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.

Non-Op vs. Operating Working Interest

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Quick Answer: An operating working interest owner manages daily well operations and makes operational decisions. A non-operated (non-op) working interest owner shares in costs and revenues but does not manage operations. Both pay their share of expenses and receive proportional production revenue.
Aspect Operating WI Non-Op WI
Operations Control Yes – makes decisions No – passive investor
Cost Responsibility Pays share + manages billing Pays share via JIB
Revenue Share Proportional to interest Proportional to interest
Administrative Burden High Low

The oil and gas industry offers various types of investment opportunities, but two of the most common forms of interest in mineral ownership are Operating Working Interest and Non-Operating Working Interest (Non-Op). Both involve a share in oil and gas production and revenue, yet they differ significantly in the roles, responsibilities, and financial implications for investors. This blog post will explore these two types of working interests, highlighting their differences, advantages, disadvantages, and tax implications.

Defining Operating Working Interest and Non-Operating Working Interest

Operating Working Interest is a form of ownership that gives the interest holder direct responsibility for managing operations. An operating working interest owner is involved in decision-making processes and oversees the exploration, drilling, and production activities associated with an oil or gas well. They take on a hands-on role in the day-to-day operations and bear the associated risks and expenses.

Non-Operating Working Interest (Non-Op) is an investment in the production of oil and gas assets without direct operational responsibilities. Non-Op owners contribute capital to the exploration and production process but do not control operational decisions. Instead, they rely on the operator to manage well activities, giving them a passive yet potentially lucrative ownership share.

Key Differences Between Operating and Non-Operating Working Interests

  1. Operational Control
    • Operating Working Interest: Owners have full control over operations, including hiring contractors, making budget decisions, and ensuring compliance with environmental and regulatory standards.
    • Non-Operating Working Interest: Owners have no control over operations and instead rely on the operator to handle all logistics and decisions related to the well.
  2. Risk and Responsibility
    • Operating Working Interest: Comes with higher risk, as owners are responsible for operating costs, liabilities, and any environmental or regulatory compliance issues. They are also responsible for covering cost overruns and managing accidents or issues arising from operations.
    • Non-Operating Working Interest: Bears fewer responsibilities in operations but still shares in production costs and risks tied to the success or failure of the well. Non-op owners typically have limited liability in operational mishaps.
  3. Revenue and Expense Structure
    • Operating Working Interest: Owners receive a larger share of production revenue but also assume a larger share of the associated costs.
    • Non-Operating Working Interest: Although they receive a smaller percentage of production revenue, non-op investors do not bear full operational expenses, making it a lower-risk, lower-involvement investment.

Advantages and Disadvantages of Each Type

CriteriaOperating Working InterestNon-Operating Working Interest (Non-Op)
AdvantagesDirect control over operations
Larger share of profits		Lower liability and operational responsibility
Lower risk
DisadvantagesHigher financial and operational risk
Time-intensive		Limited decision-making power
Relies on operator performance
Best ForExperienced industry professionals
Hands-on investors		Passive investors
Inheritors/generational

Tax Implications of Working Interest Income

Both operating and non-operating working interests generate taxable income. However, the tax structure for each type of interest can vary:

  1. Tax Treatment of Expenses
    • Operating Working Interest: Operational costs, including drilling, completion, and operational expenses, are generally deductible, providing tax savings for the owner.
    • Non-Operating Working Interest: Investors can deduct their share of expenses without the burden of ongoing operational costs, making it advantageous for tax efficiency.
  2. Depletion Allowance
    Both types of interests are eligible for a depletion allowance, a tax deduction on income from oil and gas production that offsets the diminishing value of the resource. The depletion allowance is typically 15% of gross income for oil and gas production, helping to reduce taxable income significantly for both non-op and op owners.
  3. Passive vs. Active Income
    • Operating Working Interest: Income earned through an operating working interest is usually classified as active income, which requires paying self-employment taxes and adhering to different IRS guidelines.
    • Non-Operating Working Interest: Income is often classified as passive income, meaning non-op owners may be able to offset losses against other passive income sources, subject to specific tax regulations.
  4. Tax-Advantaged Status
    Both types of working interests allow investors to benefit from tax advantages in the form of intangible drilling costs (IDCs) and tangible drilling costs (TDCs). IDCs are generally fully deductible in the year incurred, while TDCs are capitalized and depreciated over time, providing a tax-shielding effect for both non-op and op investors.

Why Understanding the Differences is Important

Choosing between an operating and non-operating working interest is a crucial decision for mineral owners/investors, as it directly impacts control, risk exposure, tax treatment, and potential returns.

  • For Active Involvement: An operating working interest offers higher control and potential revenue but demands a thorough understanding of the industry and the capacity to manage significant financial and operational risks.
  • For Passive Investment: Non-op interests offer a path to participate in the oil and gas industry without the demands of direct management. It’s a good fit for investors looking to diversify their portfolio while taking on less operational risk.

How Valor’s Mineral Management Services Benefit Non-Op Working Interests

For non-operating working interest (non-op) owners, maximizing income from their investment while minimizing the complexities of managing it can be challenging. Valor’s mineral management services are designed to support non-op owners by offering a comprehensive solution that includes everything from portfolio management to income tracking and regulatory compliance. With Valor’s proprietary mineral management software, mineral.tech®, and team expertise, non-op owners can enjoy full transparency into their assets, receive accurate and timely revenue disbursements, and benefit from detailed expense tracking without the hassle of overseeing daily operations. Valor’s services also cover essential areas like ownership verification, tax overview, and document management, which ensure that non-op owners maximize the value of their investment while staying compliant with industry and tax regulations. This hands-off, expertly managed approach allows non-op owners to enjoy the benefits of oil and gas investments with confidence and peace of mind.

Both non-operating and operating working interests provide unique advantages for investors in the oil and gas sector, from active control over projects to passive income streams. The choice between these options often depends on an investor’s risk tolerance, experience in the industry, and desire for control over operations. With the potential for tax advantages, understanding these structures can help investors optimize their financial strategies while capitalizing on opportunities in the energy market.

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Are you ready to transform your oil and gas assets? Contact Valor today to learn how our innovative solutions can elevate your business to new heights.

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.

Understanding Royalties – Interest Types

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Quick Answer: Common royalty interest types include: Mineral Interest (owns minerals and can lease), Royalty Interest (receives royalties but cannot lease), Overriding Royalty Interest (ORRI) (carved from working interest, expires with lease), and Net Profits Interest (share of profits after costs).

Navigating the complex landscape of oil and gas interests can be a daunting task for both newcomers and seasoned professionals in the industry. From mineral rights to royalty shares, the various types of interests represent different sets of rights, responsibilities, and financial benefits. In this blog, we will demystify these different categories, explaining each type of interest—such as Mineral Interest, Royalty Interest, Working Interest, Overriding Royalty Interest (ORRI), Non-Participating Royalty Interest (NPRI), and more. Understanding these distinctions is crucial for anyone involved in the oil and gas sector, whether you’re negotiating contracts, managing assets, or planning new explorations.

Mineral Interest

This interest pertains to the ownership of the underground minerals (such as oil and gas) beneath a tract of land. Owners of mineral interests have the right to lease, sell, or participate in the development of these minerals.

Royalty interest

A royalty interest is a share of the gross production from a well, usually expressed as a percentage. This percentage is known as the Decimal of Interest or DOI. Royalty interest owners receive a portion of the revenue generated from the sale of oil and gas, but they are not responsible for the operational costs associated with drilling, extraction, and production.

A Non-Participating Royalty Interest (NPRI) is a specific type of royalty interest in the oil and gas industry. It grants the holder the right to receive a fraction of the production revenue from the minerals extracted but does not confer any rights to participate in leasing or operational decisions regarding the mineral property. An NPRI is categorized under Royalty Interests because it is purely revenue-oriented and does not involve participating in the operational or leasing aspects of the mineral estate. However, it is distinct from other royalty interests because of its non-participatory nature, which limits the holder’s involvement beyond receiving revenue shares.

Working interest

Working interest represents both the right to a share of production and a financial responsibility for a proportionate share of the operating costs. Working interest owners have a more involved role, contributing to operational expenses but also reaping a proportionate share of the profits. The well operator divides funds among those with working interests after operating expenses have been covered. Often times this interest type is referred to as a “non-op working interest”.

Overriding Royalty Interest (ORRI):

This is similar to royalty interest but is carved out from the working interest. It does not affect the mineral ownership but grants a share of production revenue. Overriding royalties typically expire once the lease has produced or at the end of the lease term.

Net Profits Interest

An interest that provides the holder a share of the net profits from the production of oil and gas, after certain costs are deducted. It is a non-operating interest, meaning the holder is not responsible for operating expenses.

Leasehold Interest

This interest is held by a lessee under an oil and gas lease. The lessee (often an exploration company) acquires the right to explore and develop the property for oil and gas production. This interest combines elements of working interest and mineral rights but is contingent on the terms of the lease.

Carried Interest

In this arrangement, one party (often a smaller partner) agrees to carry another partner through the exploration and/or development phase. The carrying partner covers the expenses, and in return, they receive a larger share of the profits or a reimbursement from the carried partner once production starts or reaches a profitable stage.

Contact Valor Today

Contact us today if you need a mineral management company to help you manage your assets.

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.

Our mineral rights terminology guide

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Essential Mineral Rights Terms:
  • Mineral Rights: Ownership of underground resources
  • Royalty: Landowner share of production (typically 12.5-25%)
  • Working Interest: Ownership that pays operating costs
  • Division Order: Document confirming ownership percentage
  • Lease Bonus: Upfront payment for signing a lease

For those first diving into the world of mineral management, they may find themselves lost in a maze of jargon. But with the help of the right mineral management terminology guide, and with time and experience, you too can grow from a novice to an expert, capable of navigating this complex landscape. Now, as a leading mineral management company, we’ve crafted this terminology guide to pass on this knowledge.

The basics of mineral ownership

Mineral rights: Owning land doesn’t necessarily mean you own what’s beneath it. We have had several instances where prospective clients believed they owned the minerals beneath their property. However, upon closer inspection, it was discovered that they only had surface rights. Understanding the difference is crucial. Surface rights concern the surface of the land, while mineral rights pertain to the resources underneath.

Royalties: Royalties are like the golden ticket of mineral management. When clients receive their first royalty check, the excitement is palpable. Think of royalties as your share of the production revenue. They differ from rent or bonuses, which are often one-time payments or periodic incentives.

Working interest: We have had several clients dive headfirst into mineral management without consulting a mineral management company first. They were shocked when they had to contribute to the well’s operational costs. As a working interest owner, you share in the expenses but also the potential profits of oil and gas production.

The leasing process

Lease agreement: This binding contract determines how minerals are explored and produced. Just like when you rent an apartment or build space, terms and conditions apply. Always read it thoroughly!

Bonus payment: This is akin to a signing bonus. It’s a one-time upfront payment given when the lease is signed.

Primary term vs. secondary term: Think of these as the “lease life stages.” The primary term is the initial lease period, while the secondary term extends as long as there’s production.

Shut-in royalties: A client once referred to these as “rain checks.” If a well is temporarily non-producing, shut-in royalties help keep the lease alive.

Key terminologies in drilling and production

Spud date: The day drilling begins. It’s akin to the first step of a marathon, marking the beginning of a potentially fruitful journey.

Pooling: Imagine neighbors coming together for a community garden. Pooling combines small tracts for efficient production, ensuring everyone gets their fair share.

Unitization: This is pooling’s big brother. It involves combining large tracts, sometimes entire reservoirs, to maximize production. When our client’s land is unitized with others, they benefit from a much more efficient operation.

Net Revenue Interest (NRI): This percentage determines your share of the profits. This is something clients very quickly learn to recognize to be extremely important. The importance of accurate NRI calculations – even a small decimal point difference can amount to thousands over time!

Managing production revenues and costs

Division order: The division order is every mineral owner’s roadmap to understanding payments. It ensures everyone gets paid their rightful share.

Depletion: This is a tax perk, allowing mineral owners to account for the reduced quantity of minerals. Like depreciation for assets, it’s a way to offset production income.

Joint Operating Agreement (JOA): When several parties co-own a producing property, this agreement lays out responsibilities.

The environmental and safety lingo

Reclamation: After production, land can be in need of maintenance and enhancements. Reclamation ensures sites are restored. We have seen firsthand barren lands turned into green fields, all thanks to rigorous reclamation efforts.

Plugging and Abandonment (P&A): When a well’s life ends, it’s sealed and abandoned safely. It’s the final goodbye, ensuring no environmental hazards remain.

Environmental Impact Assessment (EIA): Before drilling, companies assess potential environmental impacts.

Navigating legal and compliance jargon

Held by Production (HBP): If a property produces minerals, the lease remains active. We often compare HBP to a light bulb – as long as it’s shining, the energy (or production) continues.

Severance taxes: These are state taxes on produced minerals. They are similar to that of paying dues – a little share to support state initiatives.

Force majeure: This clause in contracts accounts for unexpected disruptions, such as unforeseen drilling delays due to a natural disaster.

The mineral management journey, with its intricate jargon, can seem daunting. But with our mineral management terminology guide, and equipped with understanding, you’re not just an owner; you’re an informed stakeholder. Lean on experts, ask questions, and always stay curious.

Still have questions? Contact our team today!

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.

The difference in allocation vs vertical wells

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Understanding the differences and percentage variations

The energy industry has many complex aspects, and when it comes to drilling techniques, understanding the difference between an allocation well and a vertical well can be critical. These two types of wells represent different methodologies for extracting oil and gas, with specific applications, benefits, and drawbacks. The allocation percentages associated with these wells also differ, reflecting their distinct operational features.

Allocation Wells

An allocation well is a horizontal well that is drilled across multiple lease boundaries or units. These wells are designed to exploit a broader range of oil and gas deposits without the need to drill multiple vertical wells. Allocation wells are commonly used in unconventional reservoirs where a more complex approach is needed to tap into the resource efficiently.

Allocation Percentages in Allocation Wells

The percentages in allocation wells represent the division of production between different leases or units. These percentages are generally determined by the length of the horizontal well within each lease or unit boundary and might be negotiated by the involved parties. Allocation percentages must be carefully calculated and agreed upon to ensure fair distribution among the various leaseholders or interest owners.

Vertical Wells

A vertical well is drilled straight down into the earth, targeting a specific oil and gas reservoir. This traditional drilling method is typically used when the desired resource is located directly beneath the surface location of the well.

Allocation Percentages in Vertical Wells

In vertical wells, allocation percentages are typically straightforward, as the well is located within a single lease or unit. The revenue is then distributed according to the ownership interest in that specific lease or unit. The calculation here is usually more straightforward compared to an allocation well, where horizontal drilling may cross several boundaries.

Key Differences and Considerations

  1. Drilling Technique: While vertical wells go straight down, allocation wells use horizontal drilling to cross multiple boundaries.
  2. Efficiency: Allocation wells can cover larger areas and access reservoirs that might be challenging for vertical wells, often making them more efficient in unconventional plays.
  3. Complexity of Percentages: Allocation wells require careful calculation of percentages based on the well’s path through multiple leases or units. Vertical wells typically involve simpler percentage calculations.
  4. Regulatory Considerations: Allocation wells may involve more complex legal and regulatory requirements, as they cross different lease boundaries.
  5. Cost: Allocation wells are often more expensive to drill due to their complexity, but they may lead to increased production, justifying the additional investment.

Conclusion

Allocation and vertical wells are vital tools in the oil and gas industry, each with its own unique applications and complexities. The percentage calculations for these wells reflect their respective operational characteristics, with allocation wells necessitating more intricate distribution agreements.

Understanding these differences is essential for anyone involved in the energy industry, whether they’re an investor, operator, or mineral owner. Proper planning, collaboration, and adherence to regulatory guidelines are key to maximizing the benefits of both allocation and vertical wells while ensuring fair and transparent revenue distribution.

Contact Valor Today

Contact us today if you need support managing your oil and gas assets.

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.