What Are Mineral Rights Worth?

Anyone quoting a flat number before hearing your county and your production status is guessing, or worse, banking on you not knowing better.

There's no statewide answer to what mineral rights are worth in Texas, and treat anyone who gives you one flat number without asking a single question as someone not doing real work on your behalf. Value depends on a handful of concrete factors that change tract by tract, sometimes even within the same section.

This is a rundown of what actually moves the number, so you can evaluate an offer with something more than a gut feeling.

Producing versus non-producing

The single biggest fork in the road is whether there's a well currently producing on your tract or unit. Producing interests have an actual revenue history to value against: royalty decimal, monthly volumes, and a decline curve. Non-producing, undeveloped interests are valued more speculatively, based on how likely development looks given nearby permitting and drilling activity.

As a rough rule, producing interests with a solid decimal and a well early in its productive life carry more certain value than undeveloped acreage sitting in a quiet part of the state with no operators showing interest. That's not a knock on undeveloped acreage, it just means the value conversation leans on different evidence.

Which county and which play you're in

Texas has several distinct active plays, from the Permian Basin counties of West Texas to the Eagle Ford trend in South Texas to pockets of Haynesville activity in East Texas near the Louisiana line, and value tracks operator activity in each. Core counties inside a hot play, where multiple operators are actively permitting and drilling, command more attention from buyers than flank counties on the edge of the same play.

Even within one county, position matters. A tract near recent horizontal permits and multi-well pads reads very differently than a tract in a section with no recent activity, even if both sit in the same county with the same formation underneath. This is the kind of detail a buyer who actually works Texas counties day to day will factor in, and one working off a spreadsheet won't.

Your specific decimal and net mineral acres

Your royalty decimal, the fraction of production revenue you're actually entitled to, is a function of your net mineral acres divided by the total acreage in the spacing unit, multiplied by the royalty rate in your lease. Two owners in the same unit with different net mineral acre counts, or different royalty rates from leases signed decades apart, will have meaningfully different decimals and therefore different value.

This is why comparing your offer to a neighbor's without knowing their exact numbers doesn't tell you much. It's a reasonable data point to bring up in conversation, but the specifics of your own interest are what actually drive your number.

Decline curves and how much runway is left

For producing wells, remaining value depends heavily on where the well sits in its decline curve. Most unconventional Texas wells produce heavily in the first year or two, then decline steadily for years after. A well early in that curve still has significant remaining value ahead of it; a well deep into a long, flat decline has less runway left, which shows up directly in any cash flow based valuation.

This is worth understanding because it explains why an offer on the same interest can differ meaningfully year to year, even without a sale happening in between. It's not a moving target for no reason, it's the decline curve doing what decline curves do.

Lease terms baked into your interest

If your minerals are leased, the royalty rate negotiated in that lease, whether it's a rate typical of an older lease signed decades ago or a more recent one negotiated during an active leasing push, directly sets your decimal alongside your net mineral acres. Older leases in some parts of the state carry lower royalty rates than what's typically negotiated today, which matters when a buyer runs the math on your specific interest.

Lease term length, whether the lease is currently held by production or approaching expiration with no drilling yet, and any special provisions around post-production cost deductions all factor in as well, since they shape both current cash flow and how much certainty there is about the interest going forward.