Mineral Rights 101
How to Value a Texas Mineral Package: A Working Framework
Written by the OGLandman team — landmen who’ve run mineral-acquisition desks across the Permian and Eagle Ford. We write from the deals we’ve worked, not a content brief.
Pricing Is a Range, Not a Number
Every mineral package you look at has a number that makes sense and a number the seller wants. The gap between them is where the deal lives or dies. What follows is how to actually price a package of mineral or royalty interests in Texas — the framework, the comps, and the handful of questions that can move the number by half before you open a spreadsheet.
Set expectations on what this is. None of this is an appraisal. A formal mineral appraisal weighs reserves, decline curves, and a discounted cash-flow model built off a third-party reserve report. What a landman runs in the field is an estimate — a defensible price band you can underwrite to and negotiate against. Treat every figure here as an estimate range, not a stamped value.
The whole point of working in ranges is that two tracts a mile apart in Midland County can trade at a 3x ratio to each other depending on operator activity, HBP status, and the chain of title. Anyone quoting a single per-acre number for a county is selling you a number, not a value. Price to the envelope.
Start With What You're Actually Buying
Before any math, name the asset. The interest type sets the entire pricing regime, and the four common ones in Texas do not trade alike. A mineral interest is the full bundle — it participates in lease bonus, delay rentals, and royalty, and it lasts in perpetuity. A royalty interest (RI) is the cost-free share of production carved out by a lease. A non-participating royalty interest (NPRI) gets the royalty check but has no say in leasing and collects no bonus. An overriding royalty interest (ORRI) is carved out of the working interest and, critically, expires when the underlying lease expires.
That termination feature is why ORRIs trade at lower multiples than equivalent minerals or NPRIs — you are buying a stream with a built-in off switch tied to a lease you do not control. A working interest (WI) is a different animal entirely: it carries a share of drilling and operating costs, so you are underwriting expense exposure, not just a revenue stream. Do not price a WI off royalty comps.
Then nail the net mineral acres. The acreage a seller quotes is often gross or undivided. NMA is what they own after fractionalization, and you should always re-derive it from the deed and tract description rather than trust the cover number. A '40-acre' interest that is a 1/8 undivided share of a 320-acre tract is 40 NMA, not 320. Getting this wrong is the single most common way packages get mispriced — see the section on NMA math below.
Three Regimes: Producing, Leased Non-Producing, Non-Producing
A tract's production status decides which valuation method even applies. Producing minerals — cutting a monthly royalty check — are priced off cash flow. The field rule of thumb in 2026 is roughly 4 to 6 times annual net royalty (often quoted as 4 to 6 years of income paid upfront), with mature, flat producers at the low end and tracts with visible drilling upside near or above the top. For Permian producing royalty in the core, the range runs higher than peripheral plays; Eagle Ford producing typically sits a notch below Permian.
Leased non-producing tracts — under lease but no well yet — are priced off the lease economics and development odds. A common heuristic is 2 to 3 times the last bonus per acre, adjusted up hard when an active operator has permits down. The lease bonus tells you what the market paid for the right to drill; the permit and operator quality tell you how likely that right gets exercised before the primary term runs.
Non-producing, unleased minerals are the widest range and the easiest to overpay for. In most of Texas, raw non-producing acreage trades for under $1,000/NMA and frequently far less. The exception is core Permian acreage with strong operator interest, where speculative value is real because development is plausible. Be honest with yourself about which one you are looking at — operator density and recent permitting are what separate a $500/NMA tract from a $15,000/NMA one.
2026 Permian Comps and What Moves Them
As of mid-2026, Permian net mineral acres broadly trade in a $10,000 to $30,000+ per NMA band, with the Midland and Delaware sub-basins carrying the highest values because of stacked, repeatable pay. Non-producing core Midland acreage runs roughly $3,000 to $8,000/NMA; hot Delaware zip codes — southern Lea County, central Reeves — can bring $5,000 to $15,000 or more. These are estimate ranges; where a specific tract lands depends on the questions below, not on the county average.
Commodity price moves the whole grid. WTI has traded in the low-to-mid $90s through early June 2026, with Brent in the same ~$96 to $98 spot range, carrying a geopolitical risk premium tied to the ongoing US-Iran and broader Middle East supply situation. That premium has been reinforced by sustained US crude inventory drawdowns — EIA data showed commercial crude stocks falling again last week, part of a multi-week run of draws — and the EIA's Short-Term Energy Outlook has its 2Q26 Brent forecast nearer $106 on those tightening balances. Higher strip pulls multiples up and pulls forward operator drilling decisions; a softening price does the reverse. Underwrite to a price deck you can defend, not to the headline of the day.
Operator quality and consolidation matter as much as the commodity. After the wave of Permian consolidation — Diamondback's $26 billion Endeavor combination, and acquirers like Permian Resources pursuing a steady cadence of bolt-on deals — the operator on your tract tells you a lot about development pace and capital discipline. A tract under a well-capitalized operator that is actively permitting is a fundamentally different asset than one under a name that has not moved a rig in years.
NMA Math, Done Right
Most mispriced packages trace back to NMA and NRI errors, and two mistakes bite hardest. The first is fractionalization stacking. If a seller owns a 1/2 mineral interest in a tract already under a 1/5-royalty lease, their net revenue interest is 1/2 multiplied by 1/5 — a 1/10 royalty — not 1/2. The interest fraction and the royalty fraction compound; walk the title chain and do the multiplication every time.
The second is unrecorded or messy partial conveyances. Older tracts carry decades of partial-interest deeds, mineral reservations, and NPRI carve-outs that never made it into clean title. Price against the conservative NMA you can document, and adjust upward only after you have seen the backing instruments. Paying on the quoted acreage and discovering the gap after close is how a 'good' deal becomes a loss.
This is also where the field work lives. The arithmetic is not hard — a multiplication and a check against the deed. The time sink is assembling the ownership picture: every tract the seller touches, the lease on each, the royalty fraction, and what is actually recorded. That gathering is what eats days in a spreadsheet workflow.
The Questions That Move the Number by Half
Before committing to a price, make sure you can answer each of these, because any one can swing the value 50% or more. What is the current lease, and when does it terminate if the well stops producing? HBP for another 30 years versus expiring next year is the single biggest swing in package price — a tract about to fall out of HBP carries re-lease and new-bonus upside that a deeply held tract does not.
Has the tract been permitted in the last 24 months, and by whom? An active operator's permits are a price floor; a permitted-but-dormant tract is a question mark. Pull the operator's filing history before you price anything — the free TRRC permit tracker covers every Texas drilling permit, updated daily. Check wellbore profile and depth, not just the count, because three permitted laterals from a major is a real drilling commitment.
What is the expected decline? First-year declines on unconventional Permian horizontals commonly run 60 to 70%, so year-one revenue times six is not a 6x cash-flow multiple — it is closer to 2x once the curve rolls over. And are there pooling or unit declarations on file? As a rule of thumb, pooled interests are commonly discounted relative to comparable unpooled tracts because of voting-right and consent limitations — treat it as a directional haircut to verify against the specific unit terms, not a fixed percentage. Family-owned, single-lessor tracts tend to command a premium over fragmented ownership.
Building the Band, and Where Scout Fits
Stack the methods rather than picking one. For a producing package, the cash-flow multiple sets the floor, recent $/NMA comps in the same county and operator density set the market range, permitted development adds weighted upside on non-HBP acreage, and the seller's offer history sets a practical ceiling. Where those four overlap is your defensible band. If they do not overlap, you have found a question you have not answered yet — go back to the title chain or the permits.
This is the work Scout is built to organize. Scout holds one record per owner with their ownership schedule — every tract, every NMA and NRI — and is the system of record for the package as you work it: the four-stage deal pipeline from Under Negotiation to PSA Sent to Signed to Closed, a per-deal document vault, and a PSA and offer-letter generator. You still run your own outreach and log call attempts yourself; Scout keeps the record straight so the price band is built on documented ownership, not a guessed acreage figure.
The arithmetic of valuation has not changed in decades. What changes the outcome is whether your NMA is right, whether you saw the permits, and whether you priced to the envelope instead of to the last number someone quoted you. Get those three right and the multiple takes care of itself. Treat the result as your estimate to negotiate against — and when the stakes warrant it, back it with a formal appraisal before you close.
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