Sell Mineral Rights in Mississippi

Depth is doing a lot of the explaining in Mississippi. Shallow Tuscaloosa Marine Shale acreage and deep Jurassic salt basin fields require almost opposite assumptions when you're estimating value.

Two very different plays sit under Mississippi soil, and confusing them is the fastest way to get a misleading number out of any calculator. The Tuscaloosa Marine Shale crosses into southwest Mississippi from Louisiana, an oil shale play that drew serious operator attention roughly a decade ago and, honestly, hasn't lived up to the early projections since. The Jurassic salt basin trend, running through counties in south Mississippi, involves much older, deeper, conventional fields tied to salt dome structures, some producing since the mid-20th century.

One is a newer play still working out whether it's commercially repeatable at scale. The other is old, understood, and largely a matter of managing decline. Your inputs should reflect which one you're dealing with.

TMS acreage: be realistic about where this play stands

The Tuscaloosa Marine Shale's rock characteristics turned out to be more challenging than early operators expected, and well costs versus production volumes didn't consistently pencil out the way the Haynesville or Eagle Ford did elsewhere in the Gulf Coast region. If you have an actual producing TMS well, use real trailing income for your monthly income input rather than optimistic projections. If your acreage is undeveloped or leased but not yet drilled, any value estimate is inherently speculative, tied more to whether operator interest in the play picks back up than to income you can point to today.

Jurassic salt basin fields: old, deep, and predictable

Fields tied to Mississippi's salt dome structures have often been producing for fifty years or more, and that longevity means decline rate is one of the more reliably estimable inputs you'll find anywhere in the state. Wells this mature tend to sit on a long, gentle tail, with production changes driven more by workovers, secondary recovery efforts, or eventual plugging than by any dramatic natural decline. WTI-linked oil pricing typically drives the commodity input for these fields, and buyer interest, while not as deep as an active shale play, tends to be steadier because the asset's behavior is well understood rather than uncertain.

Setting the five inputs for each

For TMS interests: decimal interest from your division order or lease, monthly income from actual checks if producing or treated as zero if not, decline rate cautious and well-specific if producing, commodity price WTI-linked with attention to the play's typically higher well costs, and buyer multiple conservative given thin current activity. For Jurassic salt basin interests: decimal interest confirmed against a unit that may have been amended multiple times over decades, monthly income averaged over a longer window given production stability, decline rate assumed gentle and mature, commodity price WTI-linked, and buyer multiple moderate, reflecting a smaller but steadier pool of buyers who specifically understand mature Gulf Coast conventional assets.

A note on secondary recovery and workovers

Older Mississippi salt basin fields have sometimes gone through secondary recovery projects, like waterflooding, to extend economic life well beyond what a well's original decline curve would have predicted on its own. If your interest is tied to a field that's undergone this kind of enhancement, it's worth confirming whether the current production reflects the original decline or a post-project curve, since those two are genuinely different inputs and mixing them up will skew a calculator's decline rate assumption in either direction. Operators typically file this kind of enhanced recovery activity with the Mississippi State Oil and Gas Board, which is a reasonable place to check the field's development history before finalizing your own estimate.

It's also worth remembering that a secondary recovery project usually comes with additional operating cost, and some leases pass a share of that cost back to royalty owners depending on how the lease was originally written. If your monthly check has shifted after a workover was announced, checking your division order or a recent royalty statement for a cost deduction line is a better explanation to rule out first than assuming the field is simply declining faster than expected.