How to Value a Mineral Package in Texas

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. This walks through how we actually price a package of mineral or royalty interests in Texas — the framework, the comps, and the questions that can move the number by 50% before you’ve even opened a spreadsheet.

Start with what you’re actually buying

Before any math, clarify the asset. Four things change the price materially, and if any one of them is unclear the number is a guess:

• Interest type. Mineral interest, royalty interest (RI), overriding royalty interest (ORRI), or non-participating royalty (NPRI) — each prices differently. A straight mineral interest participates in lease bonus, delay rentals, and royalty. An ORRI carries no lease-renewal upside and burns off with the well.
• NMA (net mineral acres).The acreage figure the seller quotes is often gross or undivided. NMA is what you own after fractionalization. Always re-derive it from the deed and tract description. A “40-acre” interest that’s a 1/8 undivided share of a 320-acre tract is 40 NMA, not 320.
• HBP status. Held by production means the lease runs as long as the well produces. Not HBP means the lease expires and you have bonus + re-lease upside. That swing is 2–4× in package price.
• Operator + permit activity.Diamondback filing five permits on your tract next quarter is a very different asset than a tract Pioneer drilled ten years ago and walked away from. Pull the operator’s TRRC filing history for the tract before pricing anything.

The four numbers that set the floor and ceiling

Once you know what you’re buying, a sane value sits somewhere in this envelope:

1. Recent cash flow × a multiple

The floor for a producing package. Take 12-month trailing net royalty revenue and multiply by a basin-appropriate multiple. In the Permian core right now that’s typically 4.5–6× for mature producers, higher for tracts with visible development upside. Eagle Ford producing sits at 3.5–5×. Anything outside those ranges needs a reason.

2. $/NMA comparable sales

Pull the last six months of transactions in the same county at the same operator density. Reeves and Loving are trading differently than Midland and Martin, and the gap shifts month to month. $/NMA comps should never be a single number — it’s a range, usually 20–40% wide, and where in the range depends on the specifics below.

3. Permit-based development value

Non-HBP tracts with active operator interest get priced on expected development. If a major has permitted three laterals on the tract, that’s a real drilling commitment. Pull permits from the TRRC permit tracker, check wellbore profile and depth, and add a development-likelihood weighted value to the cash-flow floor.

4. Offer-history ceiling

Sellers with good counsel have a number they’ve already been offered. Your package price can’t beat the ceiling without structural leverage (speed of close, all-cash, avoiding commissions). The offer history is your binding constraint even when you think the fundamentals support more.

NMA math, done right

Every mispriced package we’ve seen traces back to NMA errors. The two that bite hardest:

• Fractionalization stacking. If the seller owns a 1/2 mineral interest in a tract that already has a 1/5-royalty lease, their NRI is 1/2 × 1/5 = 1/10, not 1/2. Always walk the title chain.
• Unrecorded partial sales.Older tracts have 20+ years of partial-interest deeds that didn’t make it into clean title. Price against the conservative NMA, not the quoted one, and adjust up only after you’ve seen the backing instruments.

The questions that move the number by half

Before committing to a price, make sure you know the answer to each of these:

1. What’s the current lease, and when does it terminate if the current well stops producing? HBP for another 30 years vs. expiring next year is the biggest single swing.
2. Has the tract been permitted in the last 24 months? By whom?An active operator’s permits are a price floor. A permitted-but-dormant tract is a question mark.
3. What’s the expected production decline?First-year declines in unconventional Permian horizontals run 60–70%. Year-one revenue × 6 is not a 6× cash-flow multiple — it’s closer to 2×.
4. Are there pooling / unit declarations on file?Pooled interests trade differently than fee simple — often discounted 10–25% because of voting-right limitations.
5. Who’s the current lessor and how many neighboring tracts do they own? Family-owned, single- lessor tracts trade at a premium over fragmented ownership.

What we do in Scout

When we’re working a package, Scout pulls the owner’s ownership schedule (every tract, every NMA/NRI), overlays TRRC permits on that tract over the last 24 months, runs the four price benchmarks side by side, and produces a single price band we’ll underwrite to. The math isn’t harder than a spreadsheet — but the data gathering is where spreadsheet workflows eat days. That’s the whole reason we built Scout.

One thing to never do

Don’t price from one number. The instinct on a cold outreach is to quote “$X,000 per NMA” because that’s what the last deal did. Every package is different; two tracts a mile apart in Midland County can trade at a 3× ratio to each other depending on operator activity, HBP status, and the chain of title. Price to the envelope, not to the last number someone told you.

If you’re evaluating a package and want a second read on the price, send us the tract and NMA — we’ll tell you where in the envelope it lands. No pitch, no commitment.