By The Eldorado Mineral Partners team · Last reviewed June 2026
Bonus: the money at signing
The bonus is a one-time, upfront payment for signing the lease, quoted per net mineral acre — so 40 net acres at $1,000 an acre is a $40,000 bonus. It’s yours whether or not a single well is ever drilled, which makes it the most concrete number in the whole deal. Bonus rates swing enormously with the play, the moment, and how badly the operator wants your specific tract.
Royalty: your share of what the wells sell
The royalty is your fractional share of production revenue, paid free of drilling and completion costs, for as long as the wells produce. The old standard was one-eighth (12.5%); in active plays today owners often see three-sixteenths (18.75%), one-fifth (20%), or one-quarter (25%). The gap between an eighth and a quarter is the gap between two very different paychecks over a well’s life — this is the single most valuable number in the lease.
Bonus is a bird in the hand; royalty is the flock that might follow. A slightly smaller bonus with a higher royalty is often the better long-run trade — if the wells come in.
Primary term & “held by production”
The primary term is the window — commonly three or five years — in which the operator must drill or lose the lease. Once a well produces in paying quantities, the lease is “held by production” (HBP) and can stay alive for decades, long past that original term, as long as production continues.
The catch is what HBP can hold. Without protection, a single well in one corner can keep your entire leased acreage tied up at the original terms — even parts the operator never develops. That’s the problem the next term solves.
Pugh clause: don’t let one well tie up everything
A Pugh clause releases the acreage (and sometimes the depths) the operator doesn’t actually develop within the primary term. Without one, drilling a single well can hold all your acres indefinitely; with one, the undrilled portion frees up so you can re-lease it — often for a fresh bonus. For owners with acreage spread across a tract, it’s one of the most valuable clauses to ask for.
The fine print that quietly shrinks checks
Several smaller terms decide how much of that royalty actually survives to your mailbox. The biggest is post-production deductions — costs for gathering, processing, compression, and transportation that some leases let the operator subtract from your royalty (a “net” lease) and others don’t (a cost-free or “enhanced” royalty). The same headline royalty fraction can pay very differently depending on this one point.
- Shut-in royalty — a small payment that keeps a lease alive when a well can produce but isn’t selling (no pipeline, low prices). Watch how long it can hold the lease idle.
- Delay rental — an annual payment in older leases to postpone drilling; most modern leases are “paid-up,” folding this into the bonus.
- Post-production deductions — whether gathering, processing, and transport costs come out of your royalty. A “no deductions / cost-free royalty” clause protects you.
- Depth (horizontal) clause — limits the lease to the formations actually developed, so you keep the deeper or shallower zones.
- Continuous drilling / retained-acreage — defines how much acreage the operator keeps by keeping a rig running.
Educational content, not legal, tax, or investment advice — your facts are specific, so involve your attorney and CPA before deciding anything. We’ll gladly work with them.