Leasing mineral rights can create an upfront payment and the possibility of production-based income while leaving the underlying mineral interest with its owner, subject to the rights granted in the lease. The outcome, however, depends far more on the written terms than on the headline bonus or royalty percentage.

This guide explains how an oil and gas lease works, what to examine in a mineral rights lease agreement, how mineral rights royalties are calculated, and what to consider when comparing selling vs leasing mineral rights. Because property and oil and gas laws vary, every proposed transaction should be reviewed in light of the governing state, the chain of title, and the complete contract.

Key Takeaways

• Leasing mineral rights generally grants a company defined exploration and production rights without completing an outright sale of the mineral interest.
• A mineral rights lease agreement should be evaluated as one integrated contract. The bonus, royalty clause, term, pooling authority, deductions, release provisions, and surface terms can affect value and control.
• A lease bonus is usually tied to signing and satisfaction of payment conditions. Mineral rights royalties depend on production, sales, ownership, allocation, prices, and the lease language.
• Signing a lease does not guarantee that a well will be drilled or that commercial production will occur.
• The primary term may end on a stated date, but a lease can continue into a secondary term if production or another lease-saving condition applies.
• Selling vs leasing mineral rights is not simply a choice between a large payment and small checks. It is a comparison of liquidity, retained ownership, future uncertainty, taxes, contract burdens, and personal objectives.
• Title, acreage, and payment terms should be confirmed in writing before an executed lease is delivered or recorded.

What Does Leasing Mineral Rights Mean?

Mineral rights are interests in substances beneath the surface, which may include oil and natural gas. They can be owned together with the surface estate or separated from it. Ranger’s guides to what mineral rights are and surface and subsurface rights provide additional background on that distinction.

In a typical private oil and gas transaction, the party with authority to lease the mineral interest is the lessor, and the company receiving the development rights is the lessee. The legal character of an oil and gas lease is not identical in every state. Broadly stated, the document grants the lessee specified rights to explore, drill, produce, market, and sometimes pool the covered minerals. The lessor generally retains the interest not granted, including the right to receive the compensation reserved in the lease.

That is why describing a lease as merely “renting the land” is incomplete. The lease may create a valuable leasehold or working interest, authorize use of the surface, and remain effective for years if its continuation requirements are met. The exact rights come from the contract and applicable law—not from the document’s label alone.

Mineral ownership, surface ownership, and the executive right

The surface owner is not always the mineral owner, and a person who receives a royalty does not always hold the power to execute a lease. The authority to lease is commonly called the executive right. It may belong to one person, several co-owners, a trust, an estate, or another entity. Prior reservations, conveyances, probate proceedings, liens, and existing leases can all affect who has signing authority and what can be leased.

Before leasing mineral rights, gather deeds, probate documents, assignments, prior leases, division orders, and any title materials already available. Confirm the legal description, the ownership fraction, the minerals and depths owned, and whether another party shares or controls the executive right. A surface deed or tax statement alone may not establish mineral ownership.

If you want to discuss the documents you have and the possible paths available, you can contact the Ranger Land and Minerals team. Legal and tax professionals should separately advise you on the effect of a proposed transaction in your jurisdiction.

How Leasing Mineral Rights Works

Although transactions differ, leasing mineral rights often follows a recognizable sequence. Understanding that sequence helps distinguish an initial offer from a binding, funded agreement.

• Initial contact and acreage identification. A company, broker, or landman identifies acreage it may want to lease and contacts a person believed to own an interest. A landman may research title and negotiate for a company, but that role does not automatically make the person the lessor’s attorney or fiduciary.
• Ownership and title review. The proposed lessee reviews county records and other documents to estimate the interest that can be leased. Early acreage figures are often estimates and may change after formal title work.
• Offer and negotiation. The parties discuss the bonus, royalty, primary term, extension rights, pooling, deductions, development protections, surface provisions, and other terms. A one-page offer summary is not a substitute for the complete lease and every addendum.
• Execution, delivery, and payment. The lessor signs the documents, but payment may be immediate, held in escrow, or conditioned on title approval. The lease, payment order, draft, cover letter, and escrow instructions should be read together.
• Recording and possible assignment. The lessee may record the lease or a memorandum in the relevant county records. Recording requirements and practices vary. The original lessee may also assign the lease if the contract permits it.
• Exploration and development. The lessee may evaluate geology, obtain permits, form a unit, drill, complete a well, or decide not to develop. A signed lease does not promise a producing well unless the contract contains a specific development obligation.
• Revenue administration. If production is sold, the operator or purchaser may request tax forms and a division order before issuing payments. Title disputes, missing documents, or conflicting claims can place proceeds in suspense.
• Continuation, release, or expiration. The lease may expire at the end of its primary term, continue because a stated condition is satisfied, or terminate as to only certain acreage or depths under a release clause.

Each stage creates different questions. For example, a competitive bonus has little practical value if payment can be rejected indefinitely, while an attractive royalty rate may be weakened by broad deduction language or a lease that holds more acreage than necessary.

What a Mineral Rights Lease Agreement Should Address

A mineral rights lease agreement is a negotiated allocation of rights, risks, payments, and control. Standard forms commonly favor the party that prepared them, and two offers with similar financial terms can produce very different outcomes. The following provisions deserve coordinated review.

Granting clause and property description

The granting clause identifies the rights being conveyed to the lessee. It should be read with the legal description, acreage recital, mineral list, depth limitations, and any exclusions. Confirm whether the lease covers oil and gas only or uses broader language, whether it includes all formations, and whether it grants rights for roads, pipelines, water, disposal, storage, or other operations.

Descriptions such as “all land in the county” or broad Mother Hubbard clauses may capture more property than expected. A qualified title professional or attorney can help compare the lease description with the vesting deed and ownership records.

Primary term, secondary term, and the habendum clause

The habendum clause defines the lease duration. The primary term is the initial fixed period during which the lessee may hold the lease if it satisfies the agreement. The secondary term can extend the lease beyond that period when production, operations, or another stated condition exists.

A common phrase is “so long thereafter” as oil or gas is produced in paying quantities, but definitions and saving clauses matter. Shut-in payments, continuous operations, temporary cessation, pooling, force majeure, and other provisions may preserve the lease even when a well is not actively selling production. It is therefore inaccurate to assume that everything automatically returns to its pre-lease status on the primary-term end date.

Lease bonus and payment conditions

A signing or lease bonus is generally consideration for executing the lease. It may be quoted as a fixed amount or as dollars per net mineral acre. The basic estimate is:

Estimated lease bonus = confirmed net mineral acres × negotiated bonus per net mineral acre

Net mineral acres reflect the tract acreage multiplied by the ownership fraction. They are not the same as surface acres or net royalty acres. See Ranger’s explanation of net mineral acres and net royalty acres for examples.

The payment documents should state when funds are due, whether payment depends on title approval, whether the acreage or price may be adjusted, and what happens if payment is not made. There is no universal payment deadline for every private lease. The detailed guide to an oil and gas lease bonus payment explains bonus calculations, timing, and common tradeoffs.

Paid-up leases and delay rentals

Some older lease forms require periodic delay rentals during the primary term when drilling has not begun. Many modern forms are described as paid-up leases, meaning the consideration paid at signing also covers rentals that otherwise might have come due during the stated term. “Paid-up” does not mean that every future obligation is paid, and it does not guarantee drilling. Review the separate guide to a paid-up oil and gas lease for a fuller explanation.

Royalty rate, valuation, and deductions

The royalty clause should do more than state a fraction. It may define whether value is based on proceeds, market value, or another measure; where the product is valued; whether affiliate transactions are addressed; and which costs may reduce the payment. Gathering, compression, dehydration, treatment, processing, transportation, and marketing language can materially affect mineral rights royalties.

A phrase such as “cost-free royalty” may not answer every deduction question. State law and the complete wording matter. Compare the royalty fraction together with the valuation point, permissible deductions, taxes, product definitions, and the operator’s reporting obligations.

Pooling, unitization, and allocation

Pooling allows leased acreage or interests to be combined with other tracts for development or production allocation. The clause may establish unit-size limits, amendment rights, depth rules, and the way production is attributed to the leased tract. A well does not need to sit on a particular tract for that tract to receive allocated production if valid pooling or unitization applies.

Pooling can support efficient development, but broad authority may allow production from a small portion of a large lease to hold additional acreage or depths. Review how pooling interacts with Pugh clauses, depth severance, retained-acreage provisions, and continuous-development requirements.

Pugh clauses, depth clauses, and acreage releases

A Pugh clause may release land outside a producing unit after a specified event. A vertical or depth Pugh clause may release formations that are not producing. Retained-acreage and continuous-development provisions can also define how much property remains leased and what drilling cadence is required.

These clauses are not interchangeable, and their effectiveness depends on their wording. Definitions of a well, producing interval, operations, completion, unit, and elapsed time can determine whether substantial acreage or depths remain committed.

Shut-in, cessation, and force majeure provisions

A shut-in clause may allow a lease to continue when a well capable of production is not selling oil or gas under specified conditions. Temporary-cessation or operations clauses may address interruptions and additional drilling. Force majeure language may excuse or extend performance when defined events occur beyond a party’s control.

Check the required payment, deadline, notice, duration, frequency, and cumulative limits for each saving clause. An indefinite or loosely defined right can delay the release of acreage even without current revenue.

Assignment, warranty, indemnity, and audit rights

An assignment clause controls whether and how the lessee may transfer its interest. Consider notice requirements, partial assignments, responsibility after transfer, and where ownership changes will be recorded. The financial strength and operating history of the original company may offer limited protection if the lease can be freely assigned.

Warranty and proportionate-reduction clauses can shift title risk to the lessor or permit payments to be reduced when ownership is less than anticipated. Indemnity and insurance provisions may allocate operational liabilities. Audit, information, and payment-detail clauses can affect the ability to verify future royalty calculations.

If acreage figures, title conditions, deductions, or lease-saving clauses are difficult to reconcile, do not rely on an oral summary. Contact Ranger Land and Minerals to discuss the practical options, and have qualified legal and tax advisers review the provisions that affect your rights.

Surface use, water, access, and restoration

When the mineral and surface estates have different owners, the people signing the mineral lease may not control every surface issue. When the same party owns both estates, the lease or a separate surface-use agreement may address well pads, roads, pipelines, gates, fencing, livestock, water, noise, lighting, setbacks, damages, reclamation, and insurance.

Surface rights and mineral-development rights vary by state, and government permits do not necessarily replace private contractual protections. Identify homes, water sources, agricultural operations, environmentally sensitive areas, and planned improvements before negotiating location or access terms.

How Mineral Rights Royalties Work

Mineral rights royalties are production-based payments reserved under a lease. A royalty is different from the bonus paid for signing and from a delay rental that may maintain certain leases during the primary term. If no commercial production occurs, a properly earned bonus may be the only payment received.

A simplified royalty-decimal calculation often begins with:

Revenue decimal = (net mineral acres ÷ unit acres) × lease royalty rate × other applicable ownership or allocation factors

For illustration, suppose a person owns all minerals in 20 acres included in a 640-acre unit and the lease royalty is 20%. Before any additional allocation factors, the decimal would be (20 ÷ 640) × 0.20, or 0.00625. If the sales value allocated to the unit for a period were $1,000,000, that decimal would initially represent $6,250 before the effect of permitted deductions, production and severance taxes, prior burdens, adjustments, or title issues. This hypothetical example is not a valuation or payment prediction.

Ranger’s guides to oil and gas royalties and calculating royalty payments explain these components in more detail.

What makes a royalty payment change?

Factors that can change mineral royalty payments

Factor	Why it matters
Production volume	Wells may begin strongly, decline over time, experience downtime, or receive workovers that change output.
Commodity price	Oil and gas prices change with supply, demand, weather, storage, infrastructure, and geopolitical events. The U.S. Energy Information Administration’s oil price overview explains major market drivers.
Ownership decimal	Acreage, ownership fraction, unit size, royalty rate, allocation, and other burdens affect the decimal used for payment.
Product mix and quality	Oil, residue gas, natural gas liquids, and other products may have different volumes, prices, and contract terms.
Deductions and taxes	The lease, state law, post-production services, and applicable taxes influence the amount shown on a statement.
Timing and adjustments	Sales months, payment cycles, prior-period corrections, suspense releases, and purchaser changes can make checks uneven.

A division order commonly confirms the decimal and directs payment after production begins. It should be compared with the lease, title documents, unit information, and ownership calculation. Questions about deductions can also be explored in Ranger’s royalty deductions guide.

Pros and Cons of Leasing Mineral Rights

The potential benefits of leasing mineral rights should be considered alongside the uncertainties and contract burdens. None of the advantages is automatic, and none of the risks has the same importance in every transaction.

Potential advantages

• Retained interest. A lease is generally not the same as an outright mineral deed. The lessor retains the interest not granted, subject to the lease and applicable law.
• Upfront consideration. A bonus can provide current value if the title and payment conditions are satisfied.
• Possible production income. Successful development may generate mineral rights royalties for as long as the payment obligation and lease remain effective.
• No direct drilling capital in a typical lessor royalty position. The lessee or working-interest parties generally fund drilling and operations, while the lessor’s royalty is governed by the lease. Post-production costs and taxes require separate analysis.
• Opportunity to negotiate protections. The parties may negotiate limits on duration, acreage, depth, pooling, deductions, surface use, and assignment, although bargaining power varies.
• Future flexibility if rights are released. Acreage or depths that expire or are released may potentially be leased again, retained, transferred, or sold.

Potential disadvantages and uncertainties

• No development guarantee. The lessee may never drill, and a drilled well may not produce commercially.
• Long commitment. Production or a saving clause may extend a lease beyond the primary term, limiting the ability to negotiate a new lease.
• Variable revenue. Volumes, prices, deductions, ownership adjustments, and downtime can cause royalties to rise, fall, or stop.
• Complex title issues. Inherited fractions, old reservations, co-ownership, probate gaps, or liens can reduce payment or create suspense.
• Surface and operational effects. Development may affect access, land use, noise, traffic, water, and restoration, depending on ownership and the governing documents.
• Counterparty and assignment risk. The company that signs the lease may sell it, change its plans, encounter financial trouble, or transfer operating responsibility.
• Administrative burden. Owners may need to monitor division orders, statements, deductions, tax forms, operator changes, and estate-planning records for years.

Selling vs Leasing Mineral Rights

The central distinction in selling vs leasing mineral rights is not merely payment timing. A sale generally conveys the described mineral interest through a deed, while a lease grants defined development rights and reserves the lessor’s contractual benefits. Either transaction may cover all or only part of the acreage, depths, minerals, or ownership.

Comparison of leasing and selling mineral rights

Consideration	Lease	Sale
Ownership result	The lessor generally retains the interest not granted, subject to the lease.	The seller conveys the interest described in the deed.
Current payment	May include a bonus, subject to title and closing conditions.	Usually centers on purchase consideration paid at closing.
Future payments	May include royalties if commercial production and sales occur.	The seller generally gives up future income attributable to the interest sold unless another interest is expressly reserved.
Exposure to uncertainty	Retains upside and downside tied to drilling, production, prices, and lease administration.	Exchanges the conveyed interest’s future uncertainty for agreed current value.
Duration	Governed by the primary term, secondary term, and saving or release clauses.	Typically permanent for the interest conveyed unless the deed creates a limited or defeasible interest.
Tax questions	Bonus and royalty income can receive different treatment from sale proceeds.	Basis, holding period, character of gain, and transaction structure may matter.

A decision may also combine the two approaches. For example, a person might sell only a fraction of an interest, reserve selected depths, sell producing rights while retaining other acreage, or keep a royalty interest. These structures require precise drafting; informal descriptions such as “half my minerals” can be ambiguous when acreage, depths, royalties, and existing leases differ.

Useful decision questions include:

• Is immediate liquidity more important than uncertain future income?
• How concentrated is the mineral interest relative to other assets and income?
• Is the property producing, leased but undeveloped, or currently unleased?
• What development activity, infrastructure, permits, and nearby well results can be verified?
• What acreage, depths, and fractions would remain after the transaction?
• How do taxes, basis, estate planning, and co-ownership affect the alternatives?
• What risks would be retained, and which would be transferred?

Ranger’s overview of what happens after a mineral-rights sale and its minerals and royalties resource provide additional context. Neither leasing nor selling is inherently superior; the better fit depends on verified facts, complete documents, and individual objectives.

How to Evaluate and Compare Lease Offers

Comparing only the bonus per acre can obscure material differences. A disciplined review converts each proposal into a complete economic and legal package.

1. Confirm the interest being priced

Separate gross acres, net mineral acres, net royalty acres, and surface acres. Determine the ownership fraction and identify any prior royalty burdens, depth severances, or active leases. Ask whether the offer is a fixed total or can be proportionately reduced after title review.

2. Obtain every document before signing

Request the full lease, addenda, memorandum, payment order, draft, escrow terms, tax forms, and any side letter. Confirm which document controls if terms conflict. Material promises about payment, no-deduction treatment, acreage releases, or surface protection should appear in enforceable written language.

3. Compare the combined economics

Model the bonus and possible royalties under more than one production and price scenario. A higher bonus paired with a lower royalty may outperform if no well is drilled, while a higher royalty may be more valuable if substantial production occurs. Neither outcome can be known from the offer alone.

4. Evaluate time and control

Compare the primary term, extension option, unit size, pooling authority, saving clauses, assignment rights, and release provisions. Estimate how long each proposal could control the acreage with and without production. Pay special attention to clauses that permit one well or limited operations to hold broad acreage or multiple depths.

5. Investigate the counterparty and activity

Confirm the legal name of the lessee, its contact information, and who is authorized to sign. Research its operating or leasing role, assignments, nearby activity, and state regulatory records. For Texas properties, the Railroad Commission of Texas oil and gas resources can help users understand the regulator’s role and locate related information. Use the regulator serving the state where the property is located.

6. Protect the closing process

Define when signed documents may be delivered or recorded, when payment becomes firm, how title objections must be communicated, and what happens after nonpayment. Verify wire instructions through a trusted channel and consider whether a qualified escrow arrangement is appropriate. Keep complete copies of everything signed and proof of funds received.

Taxes and Records Associated With a Lease

Lease bonuses and production royalties can create federal, state, and local tax obligations. The Internal Revenue Service’s guidance on reporting natural-resource income distinguishes lease bonuses, royalties, and working interests and discusses Schedule E, Forms 1099-MISC, depletion, and estimated taxes. Tax forms and rules change, so use current instructions and individualized professional advice.

Depletion can be especially technical. Eligibility, cost versus percentage depletion, limitations, basis, prior deductions, and possible restoration depend on the facts. Do not assume that a commonly cited percentage applies automatically to every payment, taxpayer, entity, or property.

Maintain an organized file containing:

• Vesting deeds, reservations, probate documents, and title opinions;
• The executed lease, addenda, memorandum, and assignments;
• The offer, acreage calculations, payment order, and closing statement;
• Division orders, unit declarations, pooling documents, and ownership calculations;
• Royalty statements, check details, price and volume data, and suspense notices;
• Forms 1099, tax returns, basis records, and depletion schedules;
• Operator and purchaser correspondence; and
• Documents showing releases, expiration, or changes in ownership.

Good records support payment review, tax reporting, transfers, estate administration, and later negotiations. They are particularly important when an interest is divided among heirs or held through a trust or entity.

Common Mistakes to Avoid

• Assuming the surface deed proves mineral ownership. Mineral interests may have been severed or reserved in an earlier instrument.
• Treating the first offer as a market appraisal. An unsolicited offer reflects one party’s strategy and assumptions, not necessarily the interest’s full range of possible values.
• Negotiating only the bonus and royalty fraction. Duration, deductions, pooling, releases, and surface terms may have equal or greater importance.
• Signing before payment language is clear. A recorded lease and an unpaid bonus can create a difficult dispute.
• Relying on oral assurances. If a promise matters, it should be reflected in the final written documents.
• Assuming a lease will expire on one calendar date. Production, operations, shut-in, force majeure, or other clauses may extend it.
• Assuming every lease must remain private. Leases or memoranda are often recorded, while requirements and local practices vary.
• Using a division order as a substitute for lease review. The division order is part of payment administration; the lease and title instruments remain central.
• Ignoring future transfers. Assignment and estate-planning provisions can affect who administers or benefits from the interest later.

Frequently Asked Questions

What does leasing mineral rights mean?

It generally means that the party with leasing authority grants a company specified rights to explore for and produce covered minerals for a stated term and under stated conditions. The lessor generally retains the interest not granted and may receive a bonus and production royalties, but the legal character of the lease varies by state.

Does signing an oil and gas lease guarantee drilling?

No. Unless the mineral rights lease agreement creates a specific development obligation, the lessee may evaluate the acreage and decide not to drill. Even when a well is drilled, commercial production is not guaranteed.

What happens when a mineral lease expires?

If no clause extends the lease and its termination conditions are met, the leasehold rights generally end as to the affected acreage and depths. Production, operations, pooling, shut-in provisions, temporary-cessation language, or other saving clauses may continue all or part of the lease. The documents and state law control.

Can mineral rights be sold while they are leased?

They often can be transferred, but the buyer generally acquires the interest subject to the valid existing lease and the exact deed terms. The parties should confirm which royalties, accrued payments, future payments, acreage, and depths are included, and whether notice or assignment documents are required.

How are mineral rights royalties calculated?

A common starting point multiplies the owner’s share of the unit by the lease royalty rate and any other ownership or allocation factors. The payment then depends on production, product sales, price, deductions allowed by the lease and law, taxes, adjustments, and title status.

What is the difference between a lease bonus, delay rental, and royalty?

A lease bonus is generally consideration for signing the lease. A delay rental may maintain certain non-paid-up leases during the primary term without drilling. A royalty is tied to production and sales under the lease. The agreement determines whether and when each payment is due.

Is a higher lease bonus always the better offer?

No. A higher bonus may be paired with a lower royalty, longer term, broad extension right, wider pooling authority, more deductions, or weaker release language. Compare the complete economic and legal package rather than one number.

Who can sign a mineral lease?

The person or entity holding the executive right generally has authority to lease, subject to applicable law and governing documents. Co-ownership, trusts, estates, powers of attorney, marital interests, guardianships, and prior conveyances can complicate authority, so title should be confirmed before signing.

Conclusion: Make the Lease Match the Facts

Leasing mineral rights can preserve an underlying interest while providing a bonus and possible mineral rights royalties, but the transaction should never be reduced to a per-acre price and a royalty percentage. Ownership, payment conditions, duration, valuation language, deductions, pooling, releases, surface protections, assignment rights, and taxes work together.

The same discipline applies when weighing selling vs leasing mineral rights. Identify exactly what is owned, what would be granted or conveyed, what value is certain, what value remains uncertain, and how long the decision may affect the property. A carefully reviewed mineral rights lease agreement should express the actual bargain without depending on side conversations or assumptions.

Before signing, delivering, or recording documents that could control valuable property rights, contact Ranger Land and Minerals to discuss your mineral and royalty interests, and consult qualified legal, tax, and financial professionals who can evaluate the transaction for your circumstances and jurisdiction.

Authoritative Resources

• U.S. Energy Information Administration: Oil Prices and Outlook
• U.S. Energy Information Administration: Factors Affecting Natural Gas Prices
• Internal Revenue Service: Tips on Reporting Natural Resource Income
• Internal Revenue Service: Publication 525, Taxable and Nontaxable Income
• Railroad Commission of Texas: Oil and Gas FAQs

When negotiating an oil and gas lease, everything is on the table. In a sense, there is no real “standard” oil or gas lease agreement in the United States. Therefore, if you are considering signing a contract, it is important to become familiar with the best oil and gas lease negotiation tactics to maximize your financial opportunity.

Top 3 Tips for Oil and Gas Lease Negotiation

If you own your mineral rights, oil and gas companies may be interested in exploring your property. With the right contract and reserves, an oil and gas lease agreement can be a mutually beneficial financial arrangement. For this reason, we’ve put together the three most crucial steps you can take to leverage your stake in any oil or gas lease.

1. Start Off by Saying “No”

Generally, a good rule of thumb is, “never take your first offer.” If you just received a letter, email, or phone call from an oil company with an “unbeatable” contract, do not rush to sign on the dotted line. Chances are, if one company is interested, many more will be. This brings us to our second tip…

2. Take Your Time

Mineral rights are a valuable property, just like your home. Imagine that you are leasing out your subsurface to an oil and gas company just as if you were leasing your home to a renter. You will want to make sure that your co-signer is vetted and reputable. Watch out for companies trying to get you to sign offers that will disappear in less than a day.

3. Call an Expert for Oil and Gas Lease Negotiation

So long as you haven’t entered into an agreement before consulting a professional, there is still an opportunity to take the best step for oil and gas lease negotiation. Calling an expert is far and beyond the best way to leverage your buying power in any agreement. When it comes to oil and gas lease negotiations, industry experts are always going to be your most powerful resource.

Mineral rights are valuable. If you suspect that your land may have precious minerals below the surface, then you may be able to financially benefit. Do you have mineral rights ownership? Then you can sell or lease them to an oil and gas company to begin the extraction process.

If you’re not sure whether or not you have mineral rights ownership, then there are a few simple steps you can take. Below, we will outline the most common ways to determine your mineral rights ownership.

Fee Simple Estates – Know What You Purchased

If you purchased your land in a fee simple estate, then you’re golden! A fee simple estate infers that you own everything from your subsurface rights to the air above your property. In the case of a fee simple estate, it is very likely that you own 100% of your mineral rights.

Split Estates – How to Find Mineral Rights Owners?

If you did not purchase your land in a fee simple estate, then your mineral rights may be owned by another person or entity. Check your deed in order to see if the mineral rights ownership is defined in the contract.

In most cases, this information is accurate, however, occasionally those trying to make a quick buck may neglect mineral rights transactions that happened decades ago. If your deed does not define your property’s mineral rights ownership, then there are a few things you can do in order to trace back the title. This includes:

• Hiring a Title Company
• Hiring a Lawyer
• Going to your Town’s Deeds Office
• Conducting Independent Research

If you are able to successfully determine that there are no other owners of your mineral rights, then you can officially claim them as your own. In some states, you may find that your property was once a split estate, but that the mineral rights have expired and reverted back to the land owner.