Reference · Mineral glossary
If you buy, lease, or own oil and gas interests, the language gets in the way before the deal does. A "3/16 lease on 40 net acres in a 640 unit" is a sentence that decides what a check is worth, but only if every word lands. This glossary covers the 25 terms that show up most in mineral and royalty acquisition: the interests you can own, the lease clauses that make or break a position, and the documents that move title from one party to the next. Definitions are written for working professionals, not first-day trainees: short, accurate, and tied to how the term actually gets used at the negotiating table and in a runsheet. Where two terms are easy to confuse (NRI vs. royalty, pooling vs. unitization, BPO vs. APO), we say so and point you to the related entry.
The portion of the gross acreage in a tract that a single party actually owns the minerals under. You calculate it as gross acres multiplied by your fractional (decimal) mineral interest: own 1/4 of the minerals under a 640-acre section and you hold 160 net mineral acres. NMA is the unit most mineral deals are priced and quoted in, because gross acreage alone tells you nothing about how much of it is yours.
A way to compare mineral and royalty positions that carry different lease royalties on equal footing, by standardizing them to a 1/8 (0.125) royalty basis. NRA equals your royalty interest divided by 0.125, multiplied by your net mineral acres, which is the same as net mineral acres multiplied by the royalty rate, multiplied by eight. Where net mineral acres measures how much of the mineral estate you own, NRA measures the royalty income that ownership throws off: the figure mineral buyers actually price a deal on.
The share of production revenue you actually receive after all royalties and other burdens are paid off the top. For a working-interest owner, NRI equals the working interest minus the royalties and overrides carved out of it; for a leased mineral owner, NRI is the royalty fraction itself. A common tract-level formula is NMA divided by the drilling-unit acreage, multiplied by the lease royalty rate. NRI is the number that determines the check. Working interest determines who pays the bills.
A royalty interest in production that carries no right to lease the minerals, collect bonus or delay rentals, or participate in lease negotiations. An NPRI owner shares in revenue when there is production but has no say in whether or how the tract gets leased. Those executive and bonus rights stay with the mineral owner. It is created by reservation in a deed or by a separate royalty conveyance, and it survives changes in the underlying lease.
A royalty carved out of the working interest, not the mineral estate. It entitles the holder to a share of production free of drilling and operating costs, but only for the life of the lease it is tied to: when that lease expires, the ORRI expires with it. ORRIs are often reserved by a landman or geologist who assembled a lease and assigned it on, or granted as compensation in a deal.
The operating interest in a lease that carries the obligation to pay a proportionate share of the costs of drilling, completing, and producing a well. Working-interest owners receive revenue only after royalties and overrides are paid, but they bear the risk and the expenses. A 100% working interest in a tract leased at a 3/16 royalty yields roughly an 81.25% net revenue interest before any other burdens.
The right to a share of production, or its value, free of the costs of drilling and operating. It is the interest a mineral owner retains when leasing (the lease royalty fraction), and it is the most common interest a mineral owner holds once a tract is under lease. Royalty owners get paid off the top; they take none of the operating risk and none of the operating cost.
Ownership of the oil, gas, and other minerals beneath a tract, separate from the surface. A full mineral interest carries five rights: to develop, to lease (the executive right), to receive bonus, to receive delay rentals, and to receive royalty. Mineral interests can be severed from the surface and conveyed independently, which is why a tract's mineral and surface estates often have entirely different owners.
Ownership of the land's surface, as distinct from the minerals below it. When the mineral estate has been severed, it is dominant: the mineral owner (or its lessee) has the implied right to use as much of the surface as reasonably necessary to develop the minerals. Surface owners and operators frequently negotiate surface-use agreements to set terms for roads, pads, and damages.
An ownership share expressed as a decimal of total unit production, the figure that appears on a division order and drives every revenue check. It rolls together your net mineral acres, the unit size, and your royalty rate into one number; for example, 10 net acres in a 640-acre unit at a 3/16 royalty works out to about 0.00292969. Confirming this decimal against your own math is the single most important check before signing a division order.
The net revenue interest a tract actually delivers in a specific drilling unit after adjusting for how much of the owner's acreage falls inside that unit. When a tract is only partially within a DSU, the straight NRI calculation overstates the real share, so the result is multiplied by the percentage of acreage inside the unit. This effective figure is what should be modeled when valuing an offer, not the nominal NRI of the full tract.
The condition that keeps an oil and gas lease alive past its primary term as long as the leased land produces in paying quantities. Once a lease is HBP, it continues indefinitely without further bonus or rental payments, which is why operators race to establish production before the primary term runs. For a mineral buyer, HBP status is a key diligence question: a tract held by an old, marginal well may be locked under a low-royalty lease for decades.
A lease provision that prevents production on one part of the leased acreage from holding the entire lease. A vertical (surface) Pugh clause releases the non-producing, non-pooled acreage back to the lessor; a horizontal (depth) Pugh clause releases the formations below the producing zone. There is no standard wording. It is drafted deal by deal and is almost always inserted at the lessor's insistence to force the operator to develop or release.
The up-front, per-net-mineral-acre payment a mineral owner receives for signing an oil and gas lease. It is paid once at execution, independent of whether a well is ever drilled, and is quoted alongside the royalty fraction and primary term as the three headline lease terms. Bonus is the cash a mineral owner sees first. Royalty is the income that may come later.
The fixed initial period of a lease (commonly three to five years) during which the lessee must establish production or otherwise keep the lease alive, or it expires. If a well producing in paying quantities is brought online before the primary term ends, the lease continues into its secondary term and is held by production. Delay-rental or paid-up provisions govern whether the lessee owes additional payments during the primary term.
A well that is capable of producing in paying quantities but is temporarily closed off, typically for lack of a market, pipeline access, or low prices. A shut-in royalty clause lets the lessee make a substitute payment to treat the well as producing, holding the lease even though nothing is flowing. Owners should track shut-in payments closely, since a lapse can be grounds for arguing the lease has terminated.
An instrument from the operator or purchaser stating each owner's decimal interest in a well's production and directing how proceeds are distributed. Signing it confirms your decimal and authorizes payment, but in most states it does not amend the lease or alter your underlying interest. Owners should verify the stated decimal against their own NRI calculation before signing, and watch for added language that tries to change lease terms.
The binding contract that governs the sale of mineral, royalty, or working interests: setting price, the interests conveyed, representations, diligence period, closing conditions, and effective date. The PSA is signed before closing; the deed or assignment is the instrument that actually transfers title at closing. It is the central document in any mineral acquisition and the one most worth getting precisely right.
A defined geographic boundary (by county, section, survey, or map outline) within which a buyer is actively acquiring or a partnership agrees to share interests acquired. In a joint deal, an AOI clause obligates a party who picks up acreage inside the boundary to offer the others their share. As an acquisition concept, your AOI is simply the footprint you are working: the area your prospecting, runsheets, and offers are focused on.
The two phases of a well's economics relative to payout, the point at which production revenue has recovered the agreed drilling, completion, and operating costs. Interests often shift at payout: a party may hold one working interest or override before payout (BPO) and a different, usually larger, interest after payout (APO) through a back-in. Common in farmouts and JOAs, where a back-in interest converts at payout, so always confirm which phase a quoted interest refers to.
A state-ordered combination of separately owned tracts or interests into a single drilling unit when the owners will not pool voluntarily. It lets an operator drill and develop a unit over the objection of, or without locating, a holdout owner, under terms a regulator sets. Texas follows an anti-forced-pooling tradition and treats it as a last resort under the Mineral Interest Pooling Act; other states use it far more routinely.
Combining multiple leases or tracts (often an entire reservoir or field) into one operating unit so production can be managed efficiently and proceeds allocated by formula. Pooling typically joins enough acreage for a single well or drilling unit; unitization operates at the scale of a whole field, frequently for enhanced-recovery operations. For an owner, being unitized means revenue is shared across the unit rather than tied to a single well on their tract.
The state agency that regulates oil and gas activity in Texas: issuing drilling permits, assigning well and lease identifiers, setting field and spacing rules, and ruling on pooling matters. Its public records, especially daily drilling permits, are a primary signal of where operators are moving and which tracts are about to see activity. Despite the name, it has regulated energy far longer than it has had anything to do with railroads.
A chronological summary of every recorded instrument affecting title to a tract (deeds, leases, assignments, probates, liens) abstracted from the county records. A landman builds the runsheet first, then uses it to construct the chain of title and identify the current owners and their interests. It is the working backbone of mineral title work and the source document a title opinion is built from.
The unbroken sequence of conveyances tracing ownership of a tract or interest from the original patent to the present owner. Each link (every deed, lease, and assignment) must connect cleanly for title to be marketable; a missing heir, an unprobated estate, or a gap creates a title defect that has to be cured. Reconstructing the chain from the runsheet is what tells you who actually owns what before you make an offer.
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