Checklist · Energy

Oil and Gas Leasing: A Practical Checklist

30 U.S.C. § 181

Type: Checklist
Jurisdiction: National
Date: 2024-06-06
Topic: Energy

An oil and gas lease is not really a lease — in most producing states it is a conveyance of an interest in real property that can last for decades and bind land the signer's grandchildren will inherit. This checklist walks both the mineral owner and the operator through the deal in fourteen phases, from confirming who actually owns the minerals under a severed estate, through title curative, the granting clause, the habendum clause and "held by production," delay rentals, the royalty clause and the enormous state-by-state divide over post-production cost deductions, shut-in royalties, pooling authority, the implied covenants, surface use and the accommodation doctrine, Pugh clauses, division orders, and release. It flags the traps that quietly cost mineral owners the largest sums — chiefly a royalty clause that measures value "at the well" — and the traps that quietly cost operators their leasehold, chiefly a lapsed shut-in payment or a busted continuous-development obligation. Oil and gas law is overwhelmingly state property and contract law, and this document teaches the framework and the majority positions rather than a nationwide rule that does not exist. Every clause discussed here is negotiable, and the mineral owner's leverage is highest before signature and effectively zero afterward.

Oil and Gas Leasing: A Practical Checklist

Energy > Oil and Gas | Published 6 June 2024 - Updated 24 January 2026 | UpLaw - uplaw.us

An oil and gas lease is the only "lease" that can convey a determinable fee, run for forty years, and bind land you have never seen. It is usually signed at a kitchen table, on the landman's form, in an afternoon. The clauses you do not read are the ones that will be litigated.

Keywords: oil and gas lease, mineral rights, severed mineral estate, habendum clause, held by production, paying quantities, royalty clause, post-production costs, at-the-well rule, marketable product rule, shut-in royalty, pooling, implied covenants, accommodation doctrine, Pugh clause

How to use this checklist

This is a working document for the two people on opposite sides of a lease negotiation: the mineral owner (the lessor) who has been handed a form and a bonus check, and the operator (the lessee) who needs a leasehold that will survive title review, financing, and a decade of production.

Two structural warnings before you start.

First: oil and gas law is state law. It is property law and contract law, made by state legislatures, state conservation commissions, and state supreme courts. Texas, Oklahoma, Pennsylvania, Colorado, North Dakota, West Virginia, Louisiana, and New Mexico each resolve the central questions differently — sometimes to the tune of thirty percent of a royalty check. There is no national rule, and any source that gives you one is wrong. Where this checklist states a majority or representative position, verify it against your own state's law before you rely on it.

Second: an oil and gas lease is not a landlord-tenant document. In most producing states it operates as a conveyance of an interest in real property — in Texas, a fee simple determinable in the minerals (Stephens County v. Mid-Kansas Oil & Gas Co. (Tex. 1923)); in others, a profit à prendre or an irrevocable license. It must satisfy the statute of frauds, it should be recorded, and it does not simply "expire" like the commercial tenancies covered in Commercial Leases: A Comprehensive Guide to Negotiating and Drafting. Reading it with a real-property lawyer's eye — not a tenancy lawyer's — is the single best habit you can bring to the table.

Our running example. Sagebrush Hollow Minerals, LLC is a family entity holding the minerals under 160 acres in a producing basin. Cottonwood Bend Energy Operating, LLC wants a lease. The landman offers $3,000 per acre bonus, a three-year primary term, and a "one-fifth royalty." Sagebrush's manager, Marisol Vance, thinks she is negotiating over the bonus. She is not. She is negotiating over the royalty clause, and she does not yet know it.

Phase 1 — Who owns the minerals? Severed estates and the wrong lessor

[ ] Determine whether the mineral estate has been severed from the surface estate. If so, the surface owner cannot lease the minerals and the mineral owner is your counterparty.
[ ] Identify the executive right — the power to lease. It can be severed from the royalty interest and held by someone who receives nothing from the lease.
[ ] Distinguish the four interests that may be outstanding: mineral interest, royalty interest (non-participating royalty, or NPRI), executive right, and leasehold working interest.
[ ] Confirm what "minerals" means in the severing deed under your state's rule. Pennsylvania's Dunham rule presumes a grant or reservation of "minerals" does not include oil and gas absent contrary intent — reaffirmed in Butler v. Charles Powers Estate (Pa. 2013). Other states presume the opposite.
[ ] Check for a dormant minerals act or marketable title act that may have already extinguished or reunited a stale severed interest (e.g., Ohio Rev. Code § 5301.56).
[ ] Ask whether the tract is private (fee), federal, state, or Indian/tribal. Federal onshore leasing runs through the Mineral Leasing Act of 1920, 30 U.S.C. § 181 et seq., and BLM regulations at 43 C.F.R. part 3100 — an entirely different animal from a private lease. State-owned lands run through a state land board or land office on that state's own form.
[ ] If the minerals are tribal or allotted Indian minerals, stop and get specialist counsel. Tribes are separate sovereigns — not political subdivisions of a state, and tribal law is not a subset of state law. Leasing of tribal and allotted minerals generally proceeds under federal statutes and Department of the Interior/BIA approval (the Indian Mineral Leasing Act of 1938, 25 U.S.C. § 396a et seq.; the Indian Mineral Development Act of 1982, 25 U.S.C. § 2101 et seq.), together with the tribe's own law, its constitution, its business or minerals code, and often its own courts and taxing authority. Do not assume the state form, the state conservation commission, or state-court remedies apply.

Why it matters, and the traps. The severed mineral estate is the original sin of American oil and gas practice. A grantor in 1918 sold the farm "reserving unto himself all oil, gas and other minerals," and a century later the family living on the land has no power to lease it and no right to a dollar of the royalty. Operators who lease from the wrong person get a worthless instrument and a trespass claim. Mineral owners who assume they own what is under their feet find out otherwise when the check does not come.

The subtler trap is the executive right. Because the power to lease can be severed from the economic interest, a holder of the executive right can sign a lease that binds a non-participating royalty owner who was never consulted. Most states impose a duty — variously described as fiduciary or as one of utmost good faith — on the executive-right holder toward the non-executive. Do not assume the executive can do as he pleases.

Sagebrush Hollow runs its own chain and discovers that a 1962 deed conveyed a 1/16 non-participating royalty to a since-deceased great-uncle, whose interest passed through an intestate estate to eleven cousins. That interest does not stop the lease — but it does reduce Sagebrush's royalty, and it must be identified before the division order is signed. Where heirship is unresolved, the fix runs through probate; see Administering an Estate: A Probate Checklist and Wills, Trusts, and Probate: A Comprehensive Estate Planning Guide.

Phase 2 — Run title, identify outstanding interests, and cure defects

[ ] Order or prepare a mineral title opinion (drilling title opinion before spud; division order title opinion before first payment). Operators should never rely on a landman's runsheet alone.
[ ] Chart the cotenancy. Undivided mineral cotenants each own the whole; state law then diverges sharply on whether one cotenant can drill without the others (Texas: yes, subject to accounting for net profits; several Appalachian states: no, or only under a partition or statutory scheme).
[ ] Identify life estates and remainders. A life tenant generally cannot consume the corpus; the open-mine doctrine and state-specific rules govern how bonus and royalty are apportioned between life tenant and remainderman.
[ ] Locate existing leases, top leases, mortgages, judgment liens, and tax liens, and obtain subordinations where a mortgage predates the lease.
[ ] Confirm whether the tract is subject to an existing pooled unit or a prior lease still held by production.
[ ] Build a curative punch list: affidavits of heirship, corrective deeds, releases of expired leases, ratifications by NPRI owners.

Why it matters, and the traps. Title is where oil and gas deals actually die. A lease with a title defect is not a bad lease; it is often no lease. Operators underwrite by title opinion because a $12 million horizontal well drilled on a leasehold that turns out to be 60% unleased is a catastrophe that no insurance policy fixes.

The recurring trap for mineral owners is the top lease — a lease taken on land already under an existing lease, effective when the existing lease terminates. Top leases are lawful in most states but they are a trap for the unwary lessor who signs a second lease while the first is still alive, potentially triggering a warranty claim. They can also raise rule-against-perpetuities questions in states that treat the top lessee's interest as a springing executory interest; several states have modified the rule for this purpose.

The discipline here is ordinary transactional diligence, run against a mineral chain instead of a surface chain. The methodology in Conducting Merger and Acquisition Due Diligence: A Practical Checklist transfers directly, and the recording and priority concepts are the same ones covered in Buying and Selling a Home: A Comprehensive Legal Guide from Contract to Closing and The Real Estate Transactions Toolkit.

Phase 3 — The granting clause: substances, depths, and lands

[ ] Read the granting clause word by word. It defines what you are conveying: which substances, which depths, which lands, and which incidental rights.
[ ] Narrow "and other minerals" and boilerplate that sweeps in coal, lignite, uranium, helium, geothermal, and — increasingly — pore space for carbon sequestration. Pore space ownership is now separately legislated in several states.
[ ] Cap the depths granted. A lease "from the surface to the base of the deepest formation drilled" protects the lessor's deep rights; a lease with no depth limit gives them away forever.
[ ] Delete or limit granted surface rights for operations "on adjacent or nearby lands" — a common clause that lets the operator use your surface to serve someone else's well.
[ ] Confirm the land description is a legal description (metes and bounds, or section-township-range), not a street address, and address any Mother Hubbard clause purporting to cover strips, gores, and adjoining lands.
[ ] Decide the treatment of water: an operator's right to use fresh water for fracturing is enormously valuable and is often taken for free in the granting clause.

Why it matters, and the traps. The granting clause is the widest funnel in the document, and it is the one lessors skim. Once "all oil, gas, and other minerals in and under and that may be produced from the lands," with unlimited depths, is granted for the life of production, the lessor has no deep rights left to lease to anyone in the next thirty years — even if the operator only ever develops one shallow zone.

Marisol Vance's form grants "oil, gas and other liquid or gaseous hydrocarbons, and all other minerals, whether similar or dissimilar," to all depths, plus "the right to use, free of cost, water from the leased premises." She strikes "and all other minerals," adds a depth limitation to 200 feet below the deepest producing formation, converts free water to purchased water at a stated price, and expressly reserves pore space and geothermal. None of these edits cost Cottonwood Bend anything it intends to use. All of them cost it something later.

Phase 4 — The habendum clause: primary term and "held by production"

[ ] Fix the primary term — the fixed period during which the lessee may drill. Three years is common; five is a lessor's concession; two with an option to extend is a compromise.
[ ] Read the secondary term language: "and so long thereafter as oil or gas is produced [in paying quantities] from said land."
[ ] Insert "in paying quantities" if the form omits it, and require production from the leased premises or lands pooled therewith.
[ ] Add or price an extension option (e.g., lessee may extend two years by paying a second bonus at the same per-acre rate). Make the option payment a bonus, not a rental.
[ ] Confirm that operations, and not merely a capable well, are what perpetuate the lease if that is your state's rule — and read the operations/continuous-drilling savings clause that sits alongside the habendum clause.

Why it matters, and the traps. The habendum clause is the engine of the lease. In the primary term the lessee has an option: drill or walk. In the secondary term the lease continues automatically, indefinitely, and without further payment so long as the production condition is met. A single marginal well can hold hundreds of acres and every formation beneath them for decades. That is the deal the industry is built on, and the mineral owner who does not understand it is signing a document whose duration she cannot describe.

The trap for operators is the mirror image: because the lease in states like Texas creates a determinable fee, the estate ends automatically when the condition fails. There is no notice, no cure period, no forfeiture proceeding — the leasehold simply reverts. Operators who let production lapse can lose a producing asset without anyone doing anything at all. That is why sophisticated operators negotiate for savings clauses and, wherever possible, for a notice-and-cure provision converting automatic termination into a covenant enforceable by suit.

Phase 5 — Production in paying quantities and the cessation problem

[ ] Define "paying quantities" or accept the common-law definition: revenue exceeding operating and marketing costs, without regard to drilling and completion costs already sunk.
[ ] Understand the two-part test associated with Clifton v. Koontz, 325 S.W.2d 684 (Tex. 1959): (1) over a reasonable period, do receipts exceed operating expenses; and (2) if not, would a reasonably prudent operator continue to operate the well for profit and not merely for speculation?
[ ] Read the temporary cessation of production clause. Common law tolerates temporary cessation; a lease clause usually gives a fixed window (60, 90, or 180 days) to restore production or commence reworking.
[ ] Distinguish "production" from "capable of production" — some states hold a well merely capable of producing does not hold a lease absent lease language saying it does.
[ ] For the lessor: add a release obligation requiring the lessee to execute a recordable release within a stated number of days after termination.

Why it matters, and the traps. "In paying quantities" is the phrase that decides whether a fifty-year-old stripper well is still holding 640 acres of Wolfcamp or Marcellus rights hostage. The math is deceptively hostile to lessors: the test looks at operating expenses only, so a well can be catastrophically unprofitable in a lifetime-of-the-well sense and still hold the lease, because the drilling capital is ignored. And the "reasonably prudent operator" prong gives the lessee room to argue that continued operation makes sense.

The lessor's realistic lever is not litigation but drafting: a minimum-royalty or minimum-production clause ("if royalties paid in any twelve-month period are less than $X per net mineral acre, lessee shall pay the difference or release") converts an ambiguous common-law fight into an arithmetic one. When it does come to a fight over what production was worth and what it cost, the proof problems are those of any accounting dispute — see Contract Damages: How Courts Make the Injured Party Whole.

Phase 6 — Delay rentals versus paid-up leases

[ ] Determine whether the form is a paid-up lease (bonus covers the entire primary term; no further payment required to keep it alive) or a delay rental lease (annual rental required, or the lease terminates or the lessee must drill).
[ ] If a delay rental lease: verify the rental amount, due date, depository bank, and payee, and understand that in most states an "unless" clause causes automatic termination for late or short payment.
[ ] Note the difference between an "unless" clause (automatic termination) and an "or" clause (covenant; lessor must sue).
[ ] For lessors, prefer a paid-up lease with a real bonus over a low bonus plus rentals; rentals are usually nominal and exist to help the lessee, not you.
[ ] Confirm the tax treatment: lease bonus is generally ordinary income to the lessor in the year received, and delay rentals are ordinary income as rent. Coordinate with Business Taxation: A Comprehensive Guide to Entity Choice and Federal Income Tax.

Why it matters, and the traps. Most modern leases are paid-up, and the delay rental clause is a historical artifact — but it is still on some forms, and it is still a landmine. Under an "unless" delay rental clause, a lessee who mails the rental to the wrong bank branch, or who pays $1,600 when the correct figure was $1,600.02, may have terminated its own lease by operation of law. Courts in the classic cases enforced this ruthlessly. Modern forms therefore contain "rental savings" and "mistaken payment" clauses; operators should confirm they are there, and lessors should understand that those clauses exist precisely to defeat the automatic-termination remedy.

Phase 7 — THE ROYALTY CLAUSE: "at the well" versus "proceeds," and post-production costs

This is the most consequential phase in the checklist. Read it twice.

[ ] Fix the fraction (1/8 is historical; 3/16, 1/5, and 1/4 are common in competitive basins). Understand that on federal onshore leases Congress set a statutory minimum royalty rate — raised by the Inflation Reduction Act of 2022 to 16 2/3% (30 U.S.C. § 226 as amended). Verify the current federal rate; it has changed recently and may change again.
[ ] Identify the valuation point: is royalty computed on the value "at the well", or on the gross proceeds received at the point of sale downstream?
[ ] Identify which costs the lessee proposes to deduct: gathering, compression, dehydration, treating, processing, fractionation, transportation, and marketing fees — collectively, post-production costs.
[ ] Insert an express, state-appropriate "no deductions" / gross proceeds clause if you are the lessor — and understand that in Texas, boilerplate that contradicts an "at the well" valuation may be treated as surplusage (Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996)).
[ ] Add an affiliate-sales provision: royalty is computed on the price received in an arm's-length sale to an unaffiliated third party, or on an index price, whichever is greater.
[ ] Add audit rights, a minimum-price/index floor, and interest on late payments.
[ ] Confirm your state's default rule before drafting. It varies enormously — see below.

Why it matters, and the traps. Gas is rarely sold at the wellhead. It is gathered, compressed, dehydrated, treated for CO2 and H2S, processed to strip natural gas liquids, and transported to a downstream market. All of that costs money. The question that decides the value of the mineral owner's estate is: who pays for it?

The split is genuine, deep, and state-specific:

Approach	Effect on royalty	Representative authority
"At the well" / net-back	Lessee may deduct post-production costs to work back from the downstream sales price to a wellhead value	Texas — Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996); Pennsylvania — Kilmer v. Elexco Land Services (Pa. 2010) (net-back permissible under the state's minimum-royalty act)
"Marketable product" rule	Lessee bears the cost of making the gas into a marketable product; only costs incurred after marketability may be shared, and only if reasonable and if they enhance value	Colorado — Rogers v. Westerman Farm Co., 29 P.3d 887 (Colo. 2001); Oklahoma — Mittelstaedt v. Santa Fe Minerals, Inc., 954 P.2d 1203 (Okla. 1998); West Virginia — Tawney v. Columbia Natural Resources, L.L.C., 633 S.E.2d 22 (W. Va. 2006) (requiring express, specific language to shift costs)

Even within the "at the well" camp, precise drafting can move the needle: Texas courts have enforced royalty clauses that expressly tie value to the amount realized at a downstream point (see Chesapeake Exploration, L.L.C. v. Hyder (Tex. 2015), and the later refinement in Burlington Resources Oil & Gas Co. v. Texas Crude Energy, LLC (Tex. 2019)). The lesson is not "there is a magic phrase." The lesson is that the valuation point, not the label, controls, and that a lessor who wants gross-proceeds economics must say so in language that fixes the valuation point downstream and survives her state's construction rules.

The worked example — where the 30% goes. Sagebrush Hollow signs Cottonwood Bend's form: a 1/5 (20%) royalty, "at the mouth of the well." The unit is 640 acres; Sagebrush's 160 net mineral acres give it a 25% tract participation. The first well produces 4.0 Bcf over its life. Sagebrush's royalty gas is therefore 4,000,000 Mcf × 25% × 20% = 200,000 Mcf.

Cottonwood Bend sells the residue gas at the tailgate of the processing plant for $3.20/Mcf. It deducts gathering ($0.35), compression ($0.20), treating and dehydration ($0.15), and processing and transportation ($0.25) — $0.95/Mcf, or 29.7% of the sales price — to net back to a wellhead value of $2.25/Mcf.

Royalty as written ("at the well"): 200,000 Mcf × $2.25 = $450,000.
Royalty on gross proceeds (no deductions): 200,000 Mcf × $3.20 = $640,000.

The clause Marisol did not negotiate cost her $190,000 on one well — a 29.7% haircut on every royalty dollar. The unit is ultimately developed with six wells. The cumulative cost of that single unstruck phrase runs to roughly $1.1 million, on a lease whose entire bonus was $480,000. She spent her negotiating energy trying to move the bonus from $2,900 to $3,000 an acre — a fight worth $16,000.

That is the central lesson of oil and gas leasing: the bonus is the number you can see; the royalty clause is the number that matters.

Phase 8 — Shut-in royalty clauses and their strict conditions

[ ] Read the shut-in royalty clause: it deems a well "capable of producing" to be a producing well, holding the lease, when the lessee shuts it in for lack of a market or pipeline connection.
[ ] Check the preconditions: the clause typically requires a well capable of producing in paying quantities, physically on the leased premises or a pooled unit.
[ ] Check the amount, the due date, and the payee — and, for lessors, insist on a time limit (e.g., shut-in payments may hold the lease for no more than 2 consecutive years and 4 years in the aggregate).
[ ] For lessors, set the shut-in royalty at a real number ($10–$50+ per net mineral acre per year), not the traditional $1.00/acre.
[ ] For operators, calendar the payment, name a backup payee, and confirm the depository still exists.

Why it matters, and the traps. The shut-in clause is where operators lose leases. It is a special limitation in many states: if the payment is late, short, or made when the preconditions were never met, the lease may terminate automatically, and no amount of good faith saves it. A dry hole is not a well capable of production. A well that has never been completed is not a well capable of production. Operators lose leases every year by shutting in a well that could not have produced and mailing a $160 check as though that fixed it.

For lessors, the mirror danger is a shut-in clause with no cap: an operator can hold a valuable leasehold for a decade for a nominal annual payment while it waits for better prices, and the mineral owner has no remedy short of proving a breach of the implied covenant to market. Cap it.

Phase 9 — Pooling and unitization authority, and its limits

[ ] Read the pooling clause: it lets the lessee combine your tract with others into a unit, so that production anywhere in the unit holds all the leases in it, and royalty is paid on a surface-acreage participation basis.
[ ] Cap the unit size (e.g., 80 acres for oil, 640 acres plus a tolerance for gas, larger for horizontal units), and require conformity to state spacing rules.
[ ] Require that the unit be filed of record and that a unit designation be delivered to the lessor.
[ ] Prohibit "production sharing"/allocation wells that cross your tract without pooling it, unless expressly agreed and paid for.
[ ] Add an anti-dilution requirement: the lessee may not include unleased or non-productive acreage solely to dilute your participation, and must pool in good faith.
[ ] Understand compulsory/forced pooling: state conservation agencies can pool an unwilling owner into a unit by order (e.g., 52 Okla. Stat. § 87.1 in Oklahoma; the Railroad Commission's statewide spacing and density rules at 16 Tex. Admin. Code ch. 3; N.D. Cent. Code ch. 38-08).

Why it matters, and the traps. Pooling is the clause that converts your 160 acres into a fraction. If Sagebrush's 160 acres go into a 640-acre unit, its royalty is paid on 25% of unit production — even if the well bottoms directly beneath its tract and drains it disproportionately. That is the deal, and it is generally a fair one: it prevents the waste and the racing that the rule of capture would otherwise produce, and it implements the correlative rights of all owners in the common reservoir.

The rule of capture is the foundation. It holds that oil and gas migrate, and an owner who drills a lawful well and produces from a common reservoir owns what he produces even if it drained the neighbor (Coastal Oil & Gas Corp. v. Garza Energy Trust, 268 S.W.3d 1 (Tex. 2008), applying the rule to drainage caused by hydraulic fracturing). Its counterweight is correlative rights and the state's power to regulate to prevent waste (Ohio Oil Co. v. Indiana, 177 U.S. 190 (1900); Elliff v. Texon Drilling Co., 210 S.W.2d 558 (Tex. 1948) (rule of capture does not license negligent waste of a neighbor's gas)).

The trap: an uncapped pooling clause is a blank check. Operators have pooled small tracts into vast units to hold acreage they had no intention of developing. Good-faith pooling is a real limit in most states, but proving bad faith is expensive. Capping unit size in the lease is cheap.

Phase 10 — The implied covenants

[ ] Confirm whether your state recognizes implied covenants and whether the lease disclaims them. Many operator forms contain: "There shall be no implied covenants in this lease." Strike it.
[ ] The core covenants, measured by the reasonably prudent operator standard:
- [ ] to test and develop the leasehold reasonably;
- [ ] to market the production diligently and at a reasonable price;
- [ ] to protect against drainage by offsetting wells (Amoco Production Co. v. Alexander, 622 S.W.2d 563 (Tex. 1981), including the duty not to drain from one's own adjacent leasehold);
- [ ] to operate with reasonable care and to manage the lease administratively.
[ ] Add an express offset obligation: if a well is completed within X feet of the lease line, lessee shall drill an offset, pay compensatory royalty, or release.
[ ] Add an express continuous development obligation (see Phase 12) — the implied covenant to develop is a weak reed; the express clause is not.

Why it matters, and the traps. The implied covenants are the mineral owner's only protection against an operator who leases the acreage, drills one well to hold it, and then does nothing for twenty years while the field is depleted from neighboring tracts. They are real, but they are hard to enforce: the lessor bears the burden of proving that a reasonably prudent operator would have acted differently and that the failure caused damages — a profits-based showing that is expensive to prove and easy to attack. The remedy is usually damages rather than cancellation, and cancellation is granted sparingly.

The practical conclusion, again, is drafting. Every implied covenant has an express analogue that is cheaper to enforce. Convert them. And note that the breadth of the implied covenants varies by state — Louisiana codifies obligations of a reasonably prudent operator; other states leave them entirely to common law; and a few enforce a broad disclaimer.

Phase 11 — Surface use, damages, and the accommodation doctrine

[ ] Determine whether the mineral estate is the dominant estate in your state — in most producing states it is, meaning the mineral owner and its lessee have an implied right to use as much of the surface as is reasonably necessary to produce the minerals, without paying for it.
[ ] Confirm whether your state applies the accommodation doctrine: where the surface owner has an existing use and the lessee has a reasonable alternative on the leased premises, the lessee must accommodate the existing use (Getty Oil Co. v. Jones, 470 S.W.2d 618 (Tex. 1971); narrowed and clarified in Merriman v. XTO Energy, Inc., 407 S.W.3d 244 (Tex. 2013), which places a heavy burden on the surface owner).
[ ] Negotiate a separate Surface Use and Damage Agreement (SUA) — this is the single most important document for a surface owner who does not own the minerals. It is a contract, and it can give what the common law will not.
[ ] SUA terms to fix: well pad and road locations, setbacks from homes and water wells, pit and pipeline routing, water sourcing and disposal, dust and noise, fencing and cattle guards, restoration and reclamation standards, damage payments per pad/road/rod of pipeline, indemnity, insurance, and security for reclamation.
[ ] Check for a statutory surface damages act (Oklahoma Surface Damages Act, 52 Okla. Stat. §§ 318.2–318.9; North Dakota's surface owner protection provisions, N.D. Cent. Code ch. 38-11.1; New Mexico's Surface Owners Protection Act). These override the common-law "free use" baseline in those states.
[ ] Address environmental liability: spills, produced water, historical contamination, and the operator's obligation to plug and abandon. Baseline the surface with a Phase I where the acreage may later be sold or financed — see Phase I Environmental Site Assessment and All Appropriate Inquiries: A Practical Checklist.

Why it matters, and the traps. The surface owner's shock is a permanent feature of this practice: they can put a road through my pasture, drill a pad on my hayfield, take my water, and pay me nothing? In a dominant-mineral-estate state, and absent a contract or a surface damages act — largely, yes. The accommodation doctrine is narrower than surface owners hope; Merriman required the surface owner to show he had no reasonable alternative method of continuing his existing use anywhere on the tract, which is a demanding burden.

The cure is contractual, and it must be obtained before the operator has what it needs. If your client owns both surface and minerals, the surface use terms belong in the lease. If your client owns only the surface, the SUA is a standalone negotiation that must happen before the drilling permit issues and the leverage evaporates. The zoning, setback, and permitting overlays are also live in many jurisdictions — see Land Use and Zoning Law: A Comprehensive Guide and, on the environmental statutes that attach to operations and to any later CERCLA exposure, Environmental Law: A Comprehensive Guide to CERCLA, RCRA, the Clean Air Act, and the Clean Water Act and Responding to a CERCLA Potentially Responsible Party Notice: A Practical Checklist.

Phase 12 — Pugh clauses, depth severance, and continuous development

[ ] Add a horizontal Pugh clause: at the end of the primary term (or of continuous operations), the lease terminates as to all acreage not included in a producing or pooled unit.
[ ] Add a vertical (depth) Pugh clause: the lease terminates as to all depths below the deepest formation from which there is production (or, more aggressively, 100 feet below the deepest perforation).
[ ] Add a continuous development clause: after the primary term, lessee must commence a new well every 120/180 days, or the undeveloped acreage is released. Set a maximum days between wells and an acreage-retention formula.
[ ] Coordinate the Pugh clause with the pooling clause — a poorly drafted Pugh clause is neutered by a broad pooling clause that sweeps the whole tract into a unit.
[ ] For operators: negotiate a buy-back option (extend the retained acreage by paying an additional bonus) rather than an outright release.

Why it matters, and the traps. Without a Pugh clause, one well holds everything: every acre and every formation, forever. With one, the operator must keep drilling or hand back what it is not using. This is, after the royalty clause, the second-most valuable set of edits a mineral owner can make — and it is the one operators resist most, because "held by production" acreage is a free option on future technology. The Marcellus and the Permian both delivered enormous windfalls to lessees holding decades-old leases with no depth severance, on tracts leased when the deep formations were worthless.

Sagebrush Hollow adds a horizontal and vertical Pugh clause and a 180-day continuous development obligation. Two years into the secondary term, Cottonwood Bend has drilled three wells in one unit and nothing on the western 60 acres. Those 60 acres — and every formation below the producing zone under the entire tract — revert to Sagebrush, which promptly leases them again for a second bonus. That single clause is worth more than the original deal.

Phase 13 — Assignment, division orders, and payment mechanics

[ ] Read the assignment clause. Most leases allow the lessee to assign freely. Require written notice of assignment, and — where you can get it — that the assignee assume the lease obligations and that liability be several, not joint, as to the assigned portion.
[ ] For lessors: consider a change-of-control or financial-responsibility condition; a leasehold assigned to a thinly capitalized operator is a plugging liability waiting to happen.
[ ] Understand the division order: it is a payment instruction confirming the decimal interest. In many states, including Texas by statute, a division order may not amend the lease, and a lessor who signs one does not thereby accept new deduction terms — but do not rely on that in every state. Never sign a division order that purports to modify the lease; strike the offending language.
[ ] Verify the decimal interest yourself: (net mineral acres ÷ unit acres) × royalty fraction × ownership share.
[ ] Confirm the statutory payment deadlines and interest for late payment (e.g., Tex. Nat. Res. Code ch. 91, subch. J; Oklahoma's Production Revenue Standards Act, 52 Okla. Stat. § 570.1 et seq.). Deadlines and interest rates are set by state statute and vary.
[ ] Negotiate audit rights (with a reasonable lookback, e.g., 24–36 months) and a statement-detail requirement: volumes, price, deductions itemized by category, and taxes.
[ ] Add a dispute-resolution clause deliberately rather than by default; see Drafting an Arbitration Clause: A Practical Checklist.
[ ] Track operator insolvency risk. Royalty owners are creditors when the operator files; see When a Customer Files Bankruptcy: A Creditor's Checklist and Filing a Proof of Claim in a Bankruptcy Case: A Practical Checklist.

Why it matters, and the traps. The lease is signed with a company the lessor met. It will be performed by a company the lessor has never heard of. Leaseholds trade constantly, and the operator who drills is frequently the third or fourth assignee. If the lease permits free assignment with full release, the original lessee's balance sheet — the one you relied on — walks away.

The division order is the quiet trap. It arrives looking like paperwork, it is signed by the office manager, and buried in it is a clause defining "market value at the well" in a way that authorizes deductions the lease did not. Read it as an amendment attempt, because that is often what it is.

Phase 14 — Release, termination, and recording

[ ] Record the lease (or a memorandum of lease) promptly; recording protects the lessee's priority and puts the world on notice.
[ ] Include an express release obligation: within 30 days of termination or partial termination, lessee shall record a release in recordable form, with liquidated damages for failure.
[ ] Track the statutory release remedy in your state — many provide a demand procedure and damages/attorney's fees against a lessee who fails to release an expired lease of record.
[ ] On termination, confirm plugging and abandonment, surface restoration, and removal of equipment, with a deadline.
[ ] Confirm bonding/financial assurance with the state regulator — orphaned wells are a growing liability and states have been raising bond amounts. Verify current requirements.
[ ] If the lessee refuses to release, send a demand before you sue: Writing an Effective Demand Letter: A Practical Checklist.

Why it matters, and the traps. A dead lease that is still of record is a cloud on title, and it will stop the next deal cold. Operators sit on expired leases because a recorded lease is free optionality and a release is an admission. The express release covenant with liquidated damages is what turns that from a two-year quiet-title suit into a letter.

Common mistakes to avoid

Negotiating the bonus and ignoring the royalty clause. The bonus is paid once. The royalty clause runs for the life of the field. In our example the royalty language was worth roughly five times the bonus concession Marisol was chasing.
Assuming there is a national rule on post-production costs. There is not. Texas and Pennsylvania are not Colorado, Oklahoma, and West Virginia. Confirm your state's rule before you draft, and re-confirm it — this is an area of active litigation.
Relying on a "no deductions" sentence bolted onto an "at the well" royalty clause. In Texas that combination has been treated as surplusage (Heritage Resources). Fix the valuation point, not the adjectives.
Signing a division order that changes the lease. It is a payment instruction, not an amendment. Strike anything that reads like a redefinition of value.
Leaving the pooling clause uncapped. An unlimited pooling clause can dilute your interest and hold your acreage with a well you will never see.
Omitting the Pugh clause. One well holding 640 acres and every formation to the basement is not a hypothetical; it is the default.
Letting the lessee disclaim the implied covenants without demanding express development, offset, and marketing obligations in exchange.
For operators: treating the shut-in payment as clerical. In a special-limitation state, a late shut-in check terminates a determinable fee. Calendar it, double it, and send it early.
For operators: leasing from the record surface owner when the minerals are severed. Run title. Every time.
Ignoring the surface. In a dominant-estate state, the surface owner who does not sign a surface use agreement before the permit issues has, in practice, no leverage and few remedies.
Forgetting that the counterparty can be assigned away. Notice, assumption, and several liability cost nothing to ask for at signature.
Treating this as a form deal. Everything on the landman's form is negotiable, and the form is written by the other side. The equivalent discipline is exactly the one applied in Reviewing a Commercial Lease: A Practical Checklist — read it as an adversary drafted it, because one did.

The consolidated lease checklist

Ownership and title

[ ] Mineral estate severed? Executive right located? NPRIs identified?
[ ] "Minerals" defined per state rule (Dunham in Pennsylvania)?
[ ] Title opinion obtained; cotenants, life estates, heirs, liens, prior leases charted?
[ ] Curative punch list closed?

The grant

[ ] Substances limited; "other minerals," pore space, geothermal, helium reserved?
[ ] Depths capped?
[ ] Water use priced?
[ ] Legal description correct; Mother Hubbard clause addressed?

Term

[ ] Primary term and extension option priced?
[ ] "In paying quantities" present?
[ ] Temporary cessation window defined?
[ ] Minimum royalty / minimum production floor added?

Money

[ ] Royalty fraction set?
[ ] Valuation point fixed downstream (gross proceeds) if lessor, or at the well if lessee?
[ ] Affiliate-sale and index-price protection?
[ ] Shut-in royalty amount raised and capped in duration?
[ ] Payment deadlines, interest, audit rights, statement detail?
[ ] Division order reviewed and lease-amending language struck?

Development

[ ] Pooling clause capped; good-faith and anti-dilution language added?
[ ] Horizontal and vertical Pugh clauses?
[ ] Continuous development obligation with a maximum interval?
[ ] Express offset-well/compensatory-royalty obligation?
[ ] Implied covenants preserved (disclaimer struck)?

Surface and environment

[ ] Surface use and damage agreement negotiated?
[ ] Setbacks, restoration, water, indemnity, insurance, reclamation security?
[ ] Statutory surface damages act checked?
[ ] Environmental baseline and plugging/bonding confirmed?

Exit

[ ] Assignment notice, assumption, and several liability?
[ ] Express release covenant with damages?
[ ] Lease or memorandum recorded?

Primary authority

Federal

Mineral Leasing Act of 1920, 30 U.S.C. § 181 et seq. (federal onshore leasing); BLM regulations, 43 C.F.R. part 3100. The statutory minimum onshore royalty rate was raised by the Inflation Reduction Act of 2022 (30 U.S.C. § 226, as amended); verify the current rate.
Outer Continental Shelf Lands Act, 43 U.S.C. § 1331 et seq. (offshore leasing).
Federal Oil and Gas Royalty Management Act, 30 U.S.C. § 1701 et seq. (royalty accounting and audit; administered by ONRR).
Indian minerals (separate sovereigns; federal approval regime): Indian Mineral Leasing Act of 1938, 25 U.S.C. § 396a et seq.; Indian Mineral Development Act of 1982, 25 U.S.C. § 2101 et seq.; Department of the Interior regulations at 25 C.F.R. parts 211, 212, and 225. Tribal law — the tribe's own constitution, minerals code, courts, and taxes — applies alongside federal law and is not state law. Federal onshore royalty rates, bonding and financial-assurance minimums, and leasing regulations have all changed within recent years and remain subject to change: verify the current rule before relying on any figure in this checklist.

State conservation and payment statutes (representative; confirm your state's)

Texas: Tex. Nat. Res. Code ch. 91 (payment of proceeds, division orders); Railroad Commission statewide rules, 16 Tex. Admin. Code ch. 3 (spacing, density, permitting).
Oklahoma: 52 Okla. Stat. § 87.1 (forced pooling); Production Revenue Standards Act, 52 Okla. Stat. § 570.1 et seq.; Surface Damages Act, 52 Okla. Stat. §§ 318.2–318.9.
North Dakota: N.D. Cent. Code ch. 38-08 (control of oil and gas resources); ch. 38-11.1 (surface owner protection).
Ohio: Ohio Rev. Code § 5301.56 (Dormant Mineral Act).

Cases

Ohio Oil Co. v. Indiana, 177 U.S. 190 (1900) — state power to regulate a common reservoir to prevent waste and protect correlative rights.
Stephens County v. Mid-Kansas Oil & Gas Co. (Tex. 1923) — an oil and gas lease conveys a determinable fee in the minerals.
Elliff v. Texon Drilling Co., 210 S.W.2d 558 (Tex. 1948) — the rule of capture does not immunize negligent waste of a neighbor's gas.
Clifton v. Koontz, 325 S.W.2d 684 (Tex. 1959) — "production in paying quantities" and the reasonably prudent operator prong.
Getty Oil Co. v. Jones, 470 S.W.2d 618 (Tex. 1971) — the accommodation doctrine.
Amoco Production Co. v. Alexander, 622 S.W.2d 563 (Tex. 1981) — implied covenant to protect against drainage, including fieldwide drainage by the lessee.
Sternberger v. Marathon Oil Co., 894 P.2d 788 (Kan. 1995) — Kansas's approach to post-production transportation costs.
Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996) — "no deductions" language treated as surplusage against an "at the well" valuation point.
Mittelstaedt v. Santa Fe Minerals, Inc., 954 P.2d 1203 (Okla. 1998) — Oklahoma's marketable-product framework and the reasonableness/value-enhancement conditions on deductions.
Rogers v. Westerman Farm Co., 29 P.3d 887 (Colo. 2001) — Colorado's marketable-product rule.
Tawney v. Columbia Natural Resources, L.L.C., 633 S.E.2d 22 (W. Va. 2006) — West Virginia requires express, specific language to shift post-production costs to the royalty owner.
Coastal Oil & Gas Corp. v. Garza Energy Trust, 268 S.W.3d 1 (Tex. 2008) — rule of capture bars a drainage-by-fracturing trespass damages claim.
Kilmer v. Elexco Land Services (Pa. 2010) — net-back method permissible under Pennsylvania's minimum royalty act.
Butler v. Charles Powers Estate (Pa. 2013) — the Dunham rule: "minerals" presumptively excludes oil and gas in Pennsylvania.
Merriman v. XTO Energy, Inc., 407 S.W.3d 244 (Tex. 2013) — the surface owner's heavy burden under the accommodation doctrine.
Chesapeake Exploration, L.L.C. v. Hyder (Tex. 2015) and Burlington Resources Oil & Gas Co. v. Texas Crude Energy, LLC (Tex. 2019) — how a downstream valuation point, precisely drafted, changes the deduction analysis in Texas.

Secondary sources

Williams & Meyers, Oil and Gas Law (the standard treatise) and the accompanying Manual of Oil and Gas Terms.
Kuntz, A Treatise on the Law of Oil and Gas.
Powell on Real Property (severance, cotenancy, life estates and remainders).
Corbin on Contracts (construction of the royalty clause and of special limitations).
Model form operating agreements (A.A.P.L. Form 610) for the working-interest side of the deal.

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This checklist is general legal information from UpLaw (uplaw.us), not legal advice, and does not create an attorney-client relationship. Oil and gas law is overwhelmingly state property and contract law and varies enormously from state to state; royalty, pooling, surface damage, and post-production cost rules differ by jurisdiction and change over time. Verify current requirements and consult qualified counsel in the state where the minerals lie before signing, amending, or relying on any lease.