Oil, Gas, and Mineral Rights: Ownership, Leases, Royalties, and the Rule of Capture

Summary. Under most American land, the minerals are a separate estate that can be owned, sold, leased, and inherited apart from the surface — and the mineral estate is generally dominant over the surface. This article explains that structure and what follows: the rule of capture and the conservation regulation limiting it, the oil and gas lease and the clauses determining what a landowner is actually paid, the post-production cost fight that drives most royalty litigation, pooling and unitization, the implied covenants filling the lease's silences, division orders, and the surface use and accommodation rules governing what an operator may do to land it does not own.

A woman inherits eighty acres from her grandfather. She has the deed. She pays the property taxes. She assumes she owns it.

A landman knocks and offers her $300 per acre to sign an oil and gas lease. She is delighted — until a title search reveals that her grandfather sold the minerals in 1954, reserving nothing, and that a company she has never heard of owns the right to drill under her house, to build a road across her pasture to get there, and to do so without her permission.

That is not a loophole. It is the ordinary structure of American property law, and it surprises nearly every landowner who encounters it for the first time.

Part I: The severed estate

At common law, ownership of land included everything above and below it. That has been substantially qualified above (aviation) and complicated below, and the below-ground complication is the subject of this article.

The mineral estate can be severed from the surface — sold, reserved, leased, devised, and divided — and once severed the two estates travel separately forever unless reunited by conveyance. In much of the United States, the surface and the minerals under it are owned by different people who have never met.

The mineral estate is generally the dominant estate. The mineral owner has an implied right to use so much of the surface as is reasonably necessary to explore for and produce the minerals — access, roads, well pads, tanks, pipelines, and water. The surface owner cannot prohibit that use, and receives no compensation for it as of right, though state statutes and negotiated surface use agreements now supply both in many places.

The mineral estate's five sticks, which can be separately owned and which title work must trace individually:

The right to develop — to enter and produce, the "executive" development right.
The right to lease — the executive right, which is what a landman is buying access to.
The right to receive bonus — the up-front payment for signing a lease.
The right to receive delay rentals — payments to defer drilling during the primary term.
The right to receive royalty — a share of production.

A royalty interest is a non-cost-bearing share of production, carved out of the mineral estate. A non-participating royalty interest carries the right to royalty without the right to lease or to receive bonus — which produces the recurring problem of a royalty owner whose income depends entirely on lease terms someone else negotiates. An overriding royalty is carved out of the leasehold rather than the mineral estate and ends when the lease does. A working interest bears the costs of drilling and operating and receives the revenue after royalties.

Fractional ownership compounds across generations. Eighty acres owned outright in 1930 may today be owned by ninety heirs holding fractions expressed in ten-thousandths, many of whom do not know they own anything. This is the central practical problem of mineral title work and the reason curative work and heirship determinations occupy so much of it.

Part II: The rule of capture, and what limits it

Oil and gas are fugacious — they migrate. That physical fact produced the rule of capture: a landowner who lawfully drills on their own land and produces oil or gas owns it, even though some of it drained from beneath a neighbor's land, and the neighbor has no cause of action.

The rule's corollary is that the neighbor's remedy is to drill their own well — the "self-help" remedy — which produced the historically disastrous incentive to drill as many wells as fast as possible, damaging reservoirs and wasting resources.

Conservation regulation is the response, and every producing state has it: well spacing rules limiting how close a well may be to a boundary or another well; allowables limiting production rates; pooling requirements; and the doctrine of correlative rights — each owner over a common reservoir is entitled to a fair opportunity to produce their share without waste.

Hydraulic fracturing put the rule of capture back in contention. When a fracture propagates across a property line and drains gas from beneath a neighbor's land, is that capture (no liability) or trespass (liability)? In Coastal Oil & Gas Corp. v. Garza Energy Trust, 268 S.W.3d 1 (Tex. 2008), the Texas Supreme Court held that the rule of capture barred a claim for damages caused by drainage resulting from hydraulic fracturing across a boundary, reasoning that the aggrieved party's remedy was to drill its own well. Other jurisdictions have not uniformly followed, and the question of subsurface trespass from fracturing remains genuinely unsettled outside Texas.

Related and equally unsettled: liability for injecting waste water or gas storage into pore space beneath another's land, and who owns the pore space itself — the surface owner or the mineral owner. Several states have legislated an answer; many have not.

Part III: The oil and gas lease

The lease is the operative document, and a handful of clauses determine everything.

It is not a lease in the ordinary sense. In many states it conveys a determinable fee interest in the minerals — a real property interest that terminates automatically when the conditions supporting it fail. In others it is a profit à prendre or a license. The characterization matters for recording, taxation, and what happens on termination.

The granting clause describes the land and the substances covered. Watch for: whether it covers "oil, gas, and other minerals" (and what "other minerals" has been held to include in that state), whether it covers coalbed methane or helium, and whether it includes the right to inject, store, or dispose.

The habendum clause — the term. "For a term of three years and so long thereafter as oil or gas is produced." Two periods:

The primary term, a fixed number of years during which the lessee may but need not drill.
The secondary term, which continues the lease "so long as" the condition is met.

The condition is where the litigation is. "Produced" versus "produced in paying quantities" is a meaningful difference — the latter generally requires that revenues exceed operating expenses over a reasonable period, and a marginal well can terminate a lease. "Capable of producing" is broader still and favors the lessee.

Savings clauses keep the lease alive when production stops:

Shut-in royalty — a payment that maintains the lease when a well is capable of production but shut in for lack of a market. Watch the amount, the frequency, and how many consecutive years it may be used.
Continuous operations / continuous drilling — the lease continues while operations proceed without a gap longer than a stated number of days.
Cessation of production — a window to restore production or commence reworking.
Force majeure — and note that these clauses are construed narrowly; see Force Majeure, Impracticability, and Frustration of Purpose.

The Pugh clause is the landowner's most valuable negotiated term. Without it, production anywhere on the leased premises — or in a pooled unit including any part of it — holds the entire lease indefinitely. A horizontal Pugh clause releases acreage outside a producing unit at the end of the primary term; a vertical Pugh clause releases depths below the producing formation. Its absence is how a landowner ends up with eighty acres held for forty years by one well on a corner of it.

The depth clause, the retained acreage clause, and the continuous development clause perform similar functions and should be negotiated together.

Part IV: Royalty, and the post-production cost fight

The royalty clause determines what the landowner is paid, and its drafting produces more litigation than any other provision in the lease.

The fraction. Historically one-eighth; now commonly one-fifth to one-fourth in competitive areas. Negotiable, and the single most economically significant number in the lease.

The valuation point and method — this is the fight.

Gas at the wellhead is not marketable. It must be gathered, compressed, dehydrated, treated, processed to remove liquids, and transported to a market. Those are post-production costs, and they can consume a substantial fraction of the sale price.

The question is who bears them. Two doctrinal camps:

The "at the well" camp holds that royalty is calculated on the value of gas at the wellhead, and post-production costs incurred downstream may be deducted proportionately from the royalty. Texas is the leading exponent.

The "marketable product" camp holds that the lessee has an implied duty to make the product marketable at its own expense, and may deduct only costs incurred after the product is marketable — and in some formulations, only costs that enhance value, with the burden on the lessee to show it. Colorado, Oklahoma, Kansas, and West Virginia have adopted versions of this.

The practical consequence is enormous. On the same well, the same gross sale price, and the same one-fifth royalty, a landowner in an "at the well" state and one in a "marketable product" state can receive materially different checks — and the difference is entirely the deduction line.

Which is why the clause should say so expressly. A negotiated royalty clause providing that royalty is paid on gross proceeds received by lessee or its affiliate at the point of sale, without deduction for any cost of gathering, compression, dehydration, treating, processing, or transportation, resolves the question by contract rather than by doctrine. Courts have enforced such clauses, and they have also read some of them narrowly — so the language must be comprehensive and must address affiliate sales, which is the other recurring problem: gas sold to an affiliate at a low intercompany price, with the profit taken downstream where royalty does not reach.

Other royalty provisions worth negotiating: payment timing and interest on late payments (many states have statutory prompt-payment provisions); the right to take royalty in kind; a minimum royalty; audit rights with a defined scope and period; and the treatment of gas used on the lease.

Part V: Pooling, unitization, and the modern well

Pooling combines separately owned tracts into a single unit so that production anywhere in the unit is treated as production from every tract, with royalties allocated by surface acreage. It is essential to horizontal development, where a single lateral crosses many ownerships.

Voluntary pooling requires lease authority — the pooling clause — and the clause's terms matter: the maximum unit size, whether the lessee may pool without consent, whether it may create non-conforming units, and whether it may amend a unit after formation.

Compulsory or forced pooling allows a state agency to include an unleased or non-consenting owner in a unit on statutory terms. The non-consenting owner typically chooses between participating (bearing a share of costs) and being carried subject to a risk penalty — an additional share of costs, frequently several hundred percent, recovered from the owner's revenue before it begins to flow. The penalty's size is a major state-by-state variable and a major point of controversy.

Unitization is broader — combining an entire field or reservoir for coordinated operation, typically for secondary recovery — and generally requires a high percentage of owner consent plus agency approval.

Horizontal drilling changed the practical stakes. A single well may have a two-mile lateral crossing a dozen tracts and a hundred royalty owners, held by a unit designation filed of record. For a landowner, this makes the allocation method, the unit size limits, and the Pugh clause far more consequential than they were in the vertical era — because a small tract's share of a large unit can be a very small number, and because production anywhere in a large unit may hold acreage far from the wellbore.

Part VI: The implied covenants

Oil and gas leases are famously short and famously silent, and courts fill the silences with implied covenants running from lessee to lessor. The traditional list:

To test and develop — to drill an initial well and, thereafter, to develop the leased premises as a reasonably prudent operator would.
To protect against drainage — to drill an offset well where a neighboring well is draining the leased premises and a reasonably prudent operator would drill.
To market — to find a market and to sell at a reasonable price. This covenant is the doctrinal root of the "marketable product" rule on post-production costs.
To operate diligently and prudently.
To manage the lease — administrative obligations including pooling decisions made in good faith.

The governing standard is the reasonably prudent operator, measured objectively and with regard to the interests of both lessor and lessee. The remedy is generally damages, and in some circumstances conditional cancellation of the lease as to undeveloped acreage.

Lessees contract around them. A lease providing that "the covenants set forth herein are in lieu of all implied covenants" will be enforced in most states, which is why a landowner should resist that clause and, failing that, negotiate express development obligations.

Part VII: Division orders and getting paid

After a well produces, the operator sends each interest owner a division order — a statement of the decimal interest the operator has calculated, which the owner signs to authorize payment.

Two things every royalty owner should know:

First, verify the decimal. It should equal: (net mineral acres owned ÷ total unit acres) × royalty fraction. Errors happen constantly, and an error compounds for the life of the well. Ask for the calculation, and check it against the title.

Second, do not sign a division order that changes the lease. Historically, division orders were drafted to alter royalty valuation terms, add deduction authority, or add warranties. Many states now provide by statute that a division order may not amend the lease and that an owner may not be denied payment for refusing to sign a nonconforming one. Read it, strike language that alters the lease, and know the state's rule.

Prompt payment statutes in most producing states require payment within a set period after first sale and monthly thereafter, with statutory interest on late payments. Suspended funds — held for title questions, unlocatable owners, or disputes — accrue interest in many states, and unclaimed royalties are subject to escheat.

Check stubs should show, at a minimum: the property and well, the production month, the volume, the price, the owner's decimal, the gross value, each deduction by category, taxes, and the net. Several states mandate specified check-stub information. A stub that shows only a net number is not enough to audit, and an owner is entitled to more.

Part VIII: The surface

The mineral estate's dominance is the source of the sharpest conflicts in this field.

The implied right of reasonable surface use permits the operator to use as much of the surface as is reasonably necessary — roads, pads, pits, tanks, pipelines, water — without the surface owner's consent and without payment as of right.

The accommodation doctrine limits it. Where the mineral owner's use would preclude or substantially impair an existing surface use, and reasonable alternatives are available to the mineral owner on the leased premises, the mineral owner must accommodate the existing use. The doctrine originated in Texas and has been adopted in various forms elsewhere. Its limits matter: it protects existing uses rather than planned ones, and it requires an alternative on the lease rather than merely a preference.

Surface damage statutes in a number of states require notice before entry, negotiation, and compensation for actual damages to the surface, crops, and improvements, with an appraisal or arbitration process. These are meaningful protections and they vary a great deal.

The surface use agreement is where a landowner actually gets protection, and it should address: location of the pad, roads, and pipelines, by survey; the size of the disturbed area; access routes and gates; setbacks from homes, wells, and structures; water sourcing and disposal; dust, noise, lighting, and hours; fencing and cattle guards; damages payable per acre and per structure; reclamation standards and a timeline, with security; indemnity and insurance; and the right to review and approve plans before construction.

Split estate on federal minerals adds a layer: where the United States owns the minerals under private surface, the operator's rights come from the federal lease, and the surface owner's protections come from statute and from the surface owner protection provisions of the applicable program. See Zoning, Land Use, and Entitlements for the local regulatory layer, which in many states is preempted as to oil and gas operations by state conservation law.

Part IX: Federal and state leasing, and the regulatory layer

Federal onshore leasing runs through the Mineral Leasing Act, 30 U.S.C. § 181 and following, with leasing of oil and gas lands governed by 30 U.S.C. § 226 and the regulations at 43 C.F.R. Part 3100. Federal leases are issued by competitive auction, carry statutory royalty rates and terms, and are subject to NEPA review of leasing and permitting decisions. Royalty administration and reporting run under the Federal Oil and Gas Royalty Management Act, 30 U.S.C. § 1701.

Offshore leasing runs under the Outer Continental Shelf Lands Act, 43 U.S.C. § 1331 and following, with operational regulation at 30 C.F.R. Part 250.

State lands are leased under each state's own program, frequently with different royalty rates and terms than private leases.

The environmental and safety layer:

Underground injection control under the Safe Drinking Water Act, 42 U.S.C. § 300h, governing disposal and enhanced recovery wells — the regime most directly implicated by produced water disposal and, in some regions, by induced seismicity.
Clean Water Act permitting for discharges and stormwater; Clean Air Act requirements for emissions and, increasingly, methane; RCRA, with a longstanding exemption for certain exploration and production wastes; and CERCLA liability with a petroleum exclusion that is narrower than operators sometimes assume. See Environmental Liability for Businesses and Property Owners and Environmental Permitting and Compliance.
Surface mining of coal and certain minerals under 30 U.S.C. § 1201 and following.
Plugging and abandonment obligations, with bonding requirements that in many states have proven inadequate to the actual cost — producing the orphan well problem that is now a significant public liability.

Taxation. Royalty income is ordinary income; the depletion allowance under 26 U.S.C. § 611 permits a deduction, with percentage depletion under 26 U.S.C. § 613 available to independent producers and royalty owners within statutory limits. Severance taxes, ad valorem taxes on producing minerals, and the estate and gift treatment of mineral interests all follow their own rules. See The Federal Estate and Gift Tax.

Part X: A worked example

The facts. Delia inherits a one-half mineral interest in 160 acres. A landman offers a five-year lease, one-eighth royalty, $200 per acre bonus.

What the title search shows. Her grandfather severed the minerals in 1961 and conveyed one-half to a neighbor's family, whose interest has fragmented among eleven heirs. Delia owns an undivided one-half of the mineral estate: 80 net mineral acres.

What she negotiates.

Royalty from one-eighth to three-sixteenths. On a well producing $4 million gross over its life allocated to her tract, that difference alone is worth roughly $250,000.
A gross proceeds royalty clause with no deduction for gathering, compression, dehydration, treating, processing, or transportation, and an express provision that royalty on affiliate sales is calculated on the price received by the affiliate in an arm's-length sale to a third party.
A horizontal Pugh clause releasing acreage outside any producing unit at the end of the primary term, and a vertical Pugh clause releasing depths more than 100 feet below the deepest producing formation.
A three-year primary term rather than five.
Shut-in royalty limited to two consecutive years and a total of four, at a meaningful amount.
No warranty of title, converting the lease to a quitclaim of whatever she owns.
A depth-severed pooling limit capping unit size, and a requirement that pooling be exercised in good faith.
Audit rights with a four-year lookback and the operator bearing the cost if an underpayment above a threshold is found.
A surface use agreement, negotiated separately, with pad and road locations by survey, setbacks from the house and the stock pond, water sourcing restrictions, per-acre damages, and reclamation standards secured by a bond.
Bonus increased to $450 per acre after two operators competed.

What she gets. Bonus of $36,000 (80 net acres × $450). Then, when a two-mile lateral is drilled across a 640-acre unit including her 160-acre tract:

Her decimal = (80 net mineral acres ÷ 640 unit acres) × 3/16 royalty = 0.0234375.

On $18 million of gross production allocated to the unit over the well's life, her royalty is approximately $422,000 — before severance and ad valorem taxes, and without the post-production deductions that, under a standard lease in an "at the well" jurisdiction, could have reduced it by a substantial fraction.

What the negotiation was worth. The royalty increase, the gross proceeds clause, and the Pugh clause together are worth several times the bonus — and none of them appears in the lease form the landman first presented.

Part XI: Mineral title — the work nobody sees

Every transaction in this field rests on a title determination, and mineral title is genuinely harder than surface title.

Why it is harder. Surface title runs through a chain of deeds. Mineral title runs through the same chain plus every severance, reservation, and conveyance of any of the five sticks, across every generation, with fractional interests that compound. A single eighty-acre tract can have a title opinion running two hundred pages.

The recurring defects:

Ambiguous reservations. "Reserving one-half of the minerals" — one-half of what? Of the whole mineral estate, or of the grantor's interest, which may itself have been a fraction? The "double fraction" problem — a reservation of "one-sixteenth" drafted when one-eighth royalty was universal, intended to mean one-half of royalty — has produced decades of litigation, resolved differently in different states.
Royalty versus mineral confusion. A conveyance of "one-eighth of the oil and gas" may be a mineral interest (with leasing and bonus rights) or a royalty interest (without them), and the instrument frequently does not say.
Missing heirs and unprobated estates. An owner dies intestate, the estate is never administered, and the interest passes to heirs nobody has identified.
Life estates and remainders, with the open-mine doctrine determining whether a life tenant may lease and who receives the proceeds.
Adverse possession of minerals, which in most states requires actual production rather than surface possession — meaning a surface adverse possessor does not acquire severed minerals.
Marketable title acts and dormant mineral statutes in a number of states, which extinguish or reunite severed mineral interests that have gone unused and unclaimed for a statutory period, subject to notice and preservation filings. These have moved a great deal of mineral ownership and are frequently unknown to the interests they affect.
Tax sales and foreclosures that may or may not have reached the severed minerals.

Curative work is the practice of fixing these: affidavits of heirship, quiet title actions, correction deeds, stipulations of interest, ratifications, and probate proceedings. It is unglamorous, it is a substantial share of what oil and gas lawyers actually do, and it is the reason a lease bonus is frequently paid only after title is approved.

For a landowner, the practical takeaways are: do not assume you own the minerals because you own the surface; get a title opinion or a competent runsheet before signing anything, and know that the operator will do its own; check whether a dormant mineral act applies in your state if the interest has been unused for decades; and fix your own title before you die, because heirship problems are far cheaper to solve while the owner is alive to sign an affidavit. See Probate and Estate Administration and Wills, Trusts, and Estate Planning Basics.

Part XII: Buying and selling mineral interests

An active market exists in mineral and royalty interests, and landowners are solicited constantly.

What a buyer is actually buying is a stream of future production from a depleting asset, discounted for risk. What a seller is giving up is optionality — the possibility of a new well, a new formation, a higher price, or a better lease.

The offer letter that arrives in the mail deserves the same skepticism as any unsolicited offer for an asset the sender knows more about than you do. Before responding:

Determine what you own — net mineral acres, whether leased, the royalty fraction, and whether any interest is non-participating.
Determine what is producing, from the state agency's public production database, and what has been permitted nearby.
Get a second offer. The market is competitive and unsolicited first offers are frequently well below it.
Understand what the deed conveys. A "mineral deed" conveys the mineral estate including leasing and bonus rights; a "royalty deed" conveys only royalty. A deed reciting a specific fraction of "royalty" when the parties meant an interest in minerals creates exactly the ambiguity described above.
Watch for a deed that conveys more than intended — all depths, all formations, all tracts owned in the county, or "all interest owned by grantor" language that sweeps in interests the seller did not know about.
Consider tax consequences. A sale is generally capital gain; retaining the interest produces ordinary royalty income with a depletion allowance. Run both.
Consider whether a lease bonus is pending, because sellers occasionally convey shortly before a bonus that the buyer then collects.

And a warning about the letter that includes a check. Cashing a check attached to an offer has, in some instances, been treated as acceptance of a conveyance printed on the reverse. Do not deposit anything from a mineral buyer without reading every word on both sides of every document.

For estate planning purposes, mineral interests present distinctive problems: they are difficult to value, they fragment across generations, they generate income that must be reported, and they require someone to receive division orders and cash checks for decades. A trust or an entity holding the family's minerals — with a single manager, a single tax identification number, and a defined succession — solves most of it. See Estate Planning for Business Owners and Estate Planning and Wealth Transfer Toolkit.

Part XIII: Frequently asked questions

"I own the land. Don't I own what's under it?" Only if the minerals were never severed. Check the deed chain — a reservation in a 1948 deed governs today, and it does not appear on your tax bill or your survey.

"Can they drill on my land without my permission?" If the mineral estate is severed and leased, generally yes. The mineral estate is dominant and carries an implied right to use the surface as reasonably necessary. Your protections are the accommodation doctrine, any surface damage statute in your state, and — most usefully — a negotiated surface use agreement, which you have leverage to obtain before operations begin and almost none after.

"Is the lease form negotiable?" Entirely. The form the landman presents is the operator's opening position, and every consequential term in it — royalty fraction, deductions, primary term, Pugh clause, pooling limits, shut-in provisions, warranty — is routinely negotiated. Landowners who do not negotiate are not getting a standard deal; they are getting the operator's best case.

"How much royalty should I get?" It depends on the play, the competition, and the timing. What matters at least as much as the fraction is whether post-production costs are deducted, which can change the effective rate substantially. Negotiate both.

"My checks stopped." Possible causes: the well was shut in (check for shut-in royalty payments); production fell below the payment threshold and is being accumulated; a title question put your interest in suspense; the operator changed and your address did not transfer; or the well ceased production and the lease may have terminated. Ask in writing, and ask specifically which of these it is.

"Can I make them plug the well?" Plugging obligations run to the state agency, not usually to the landowner directly, and bonding requirements in many states are well below actual plugging costs. Where a well is orphaned, the state's plugging program is the practical route. A surface use agreement with reclamation standards and security is the way to have contractual rights rather than only regulatory ones.

"They pooled my land into a unit with a well two miles away." If the lease contains a pooling clause authorizing it, that is generally permitted — and it is why the pooling clause's limits and the Pugh clause matter so much. Check whether the unit exceeds the size the clause allows, and whether the unit designation was properly filed of record.

"What is a 'landman'?" Someone who acquires leases and researches title, often as an independent contractor for an operator or a broker. They are not your representative, they have no duty to you, and the terms they present are their client's. Many are knowledgeable and straightforward; none of them works for you.

"Should I hire a lawyer for a lease?" For anything beyond a nominal acreage, yes — and the economics are not close. A few hours of review on a lease that may run for decades, against a royalty stream measured in hundreds of thousands of dollars, is among the highest-return legal expenditures available to an ordinary landowner.

Part XIV: Beyond oil and gas

The same estate structure governs other subsurface resources, with important variations.

Hard rock minerals on federal land run under the General Mining Law of 1872 rather than the leasing acts — a location-and-claim system rather than a lease system, with patenting long suspended and royalty on production notably absent. Reform proposals have circulated for decades.

Coal is leased federally under the Mineral Leasing Act and is subject to the surface mining and reclamation regime at 30 U.S.C. § 1201 and following, with permitting, bonding, and reclamation obligations far more prescriptive than in oil and gas.

Coalbed methane produced the recurring question of whether it belongs to the coal owner or the gas owner where the estates are separately held — resolved differently in different states, and by statute in several.

Sand, gravel, limestone, and other construction materials are frequently held not to be "minerals" within a general mineral reservation, on the theory that removing them would destroy the surface. The tests differ: some states ask whether the substance is exceptional in character or value; others ask whether extraction would destroy the surface. This matters enormously to a surface owner facing a quarry.

Geothermal, helium, lithium brine, and pore space for carbon sequestration are the modern additions, and each raises the same first question: which estate owns it under a conveyance drafted before anyone valued it? Several states have legislated answers for pore space and for geothermal; many have not, and the litigation is developing.

Water is a separate system entirely — riparian in the East, prior appropriation in the West, with distinct groundwater doctrines — and it intersects with oil and gas through water sourcing for completions and produced water disposal. See Agricultural Law.

Wind and solar are surface rather than mineral resources, and a wind or solar lease on land with a severed mineral estate creates a direct conflict: the mineral estate is dominant, and a turbine or an array occupying the surface can be displaced by a well pad. The accommodation doctrine may help, and the practical answer is a negotiated agreement among the surface owner, the renewable developer, and the mineral owner or lessee — increasingly a standard element of renewable project diligence.

The general lesson for anyone conveying or reserving mineral rights today: name the substances. A reservation of "all oil, gas, and other minerals" drafted in 1955 has been litigated for seventy years over what "other minerals" includes, and a reservation drafted now will be read against resources nobody has yet found a use for.

Primary authority

30 U.S.C. § 181 and § 226 — the Mineral Leasing Act; 43 C.F.R. Part 3100.
30 U.S.C. § 1701 — federal royalty management.
43 U.S.C. § 1331 — the Outer Continental Shelf Lands Act; 30 C.F.R. Part 250.
42 U.S.C. § 300h — underground injection control.
30 U.S.C. § 1201 — surface mining control and reclamation.
26 U.S.C. § 611 and § 613 — depletion.
Coastal Oil & Gas Corp. v. Garza Energy Trust, 268 S.W.3d 1 (Tex. 2008) — the rule of capture and hydraulic fracturing.
State conservation statutes and commission rules governing spacing, allowables, pooling, unitization, and correlative rights; state prompt-payment, division order, surface damage, and check-stub statutes; and state common law on lease construction, implied covenants, and post-production costs — which differ materially and which control.