Since the start of 2022, the Texas Railroad Commission has issued just under 5,000 allocation well permits compared to fewer than 600 PSA well permits. That eight-to-one ratio is why most off-the-shelf mineral interest calculators get Texas wrong. They were built for forced-pooling states where decimal-interest math is a simple ratio — and Texas isn't a forced-pooling state.
This post explains the allocation well construct, the legal storm it's been weathering for the past two years, and why a calculator built on the pooled-math assumption will systematically misvalue Texas mineral interests. The actual decimal-interest math is the subject of a companion post; this one is about why the math you've been using probably isn't the right math.
Texas is the only major US oil state with no forced pooling
In Oklahoma, New Mexico, Colorado, North Dakota, and Wyoming, an operator who wants to drill a horizontal well across multiple mineral tracts can ask the state regulator to force pool the unconsenting owners. The owner who doesn't sign the lease still gets paid (their share of revenue accumulates in a state-managed account), but they can't block the well. That statutory pooling power is what makes the simple NMA ÷ unit_acres × royalty formula work — every owner in the unit is treated identically.
Texas has nothing like that. The 1965 Mineral Interest Pooling Act (MIPA) is a voluntary-pooling statute on paper, but the procedural friction is high enough that the industry essentially never uses it. The result for decades was that to drill a horizontal across a lease line, the operator had to either (a) get every mineral owner on the wellbore path to sign a pooling clause, or (b) get a Production Sharing Agreement (PSA) signed by at least 65% of royalty interest owners. Both paths require landman work, lease negotiation, and time.
And in the modern Permian, where mineral ownership is fractured into hundreds of inherited fractional interests on a single drilling unit, both paths are slow.
The allocation well: a workaround the industry built
In 2010, Devon Energy obtained the first allocation well (AW) permit from the Railroad Commission. The construct is procedurally simple: the operator files an RRC permit application for a horizontal well that crosses multiple lease lines, the operator commits to allocating production among the tracts the wellbore crosses, and the RRC issues the permit. No royalty owner consent is required. No pooling. No PSA threshold.
Whether the RRC actually has statutory authority to issue those permits without going through formal Administrative Procedure Act rulemaking is the legal question that's been simmering ever since. Operationally, the dam broke. Allocation wells became the dominant horizontal-well permitting path in Texas almost immediately because they're vastly easier than the alternatives.
The 8-to-1 ratio in numbers
RRC permit statistics for the period from the start of 2022 through 2024:
| Permit type | Count (~2022–2024) | What it requires |
|---|---|---|
| Allocation well (AW) | ~5,000 | No royalty owner consent; operator files permit; RRC issues |
| PSA well | ~600 | 65% of royalty owner interest must sign a Production Sharing Agreement first |
| Pooled horizontal | Far less common in modern hot acreage | Pooling clause in every lease, or unanimous consent |
The eight-to-one ratio reflects how much easier the no-consent path is than the 65%-consent path, particularly in counties where ownership is highly fragmented.
The legal status is unresolved
The most prominent recent challenge to RRC authority is Opiela v. Railroad Commission of Texas, involving a Magnolia Oil & Gas allocation well in Karnes County. The case has had four distinct phases:
| Date | What happened |
|---|---|
| 2021–2022 | Magnolia obtained an allocation well permit affecting the Opielas' 640-acre tract in Karnes County. The Opielas held a 1/4 of 1/8 royalty interest under a lease whose pooling clause prohibited the operator from pooling. |
| June 2023 | The Austin Court of Appeals reversed the trial court's earlier ruling and held that the RRC erred in granting Magnolia's permit, because Magnolia had not shown that 65% of royalty owner interest had signed a PSA. |
| 2024 | The Texas Supreme Court granted petition for review. |
| January 2025 | The parties settled out of court. Under Texas Rule of Appellate Procedure 56.3, the Supreme Court vacated the Court of Appeals judgment without considering the merits and remanded to the trial court. |
The settlement preserved the operational status quo (the RRC kept issuing allocation well permits; operators kept drilling them) without producing a binding Supreme Court ruling on whether the RRC's authority is sound. As of mid-2026, allocation wells remain the dominant horizontal-well permitting path in Texas — and they remain on legally contested ground that could re-open with the next operator who picks the fight.
Why this matters for valuation
If you're valuing a Texas mineral interest, the well type determines the decimal-interest formula. There are four families:
| Well type | Interest formula |
|---|---|
| Vertical | NMA ÷ section_acres × royalty |
| Pooled horizontal | NMA ÷ unit_acres × royalty |
| PSA well | Per the PSA terms (usually proportional to NMA across wellbore-crossed tract) |
| Allocation well | (productive_lateral_through_tract ÷ total_productive_lateral) × (NMA ÷ tract_acres) × royalty |
The first three are ratios. The fourth requires a geospatial intersection of the productive wellbore polyline against the mineral tract polygon. Most off-the-shelf mineral calculators were built for forced-pooling states; they implement Formula 2 (pooled horizontal) and call it good. Applied to an allocation well, that approximation will be wrong — and the direction of the error depends entirely on tract geometry.
A quick taste of the divergence
Consider a tract with 60 NMA in a 160-acre mineral tract, 25% royalty, and a 2-mile horizontal well with 9,500 ft of productive lateral. Of that 9,500 ft, 1,800 ft falls inside the 160-acre tract.
- Pooled approximation (60 ÷ 640 × 0.25): DI = 0.02344
- Correct allocation math ((1,800 ÷ 9,500) × (60 ÷ 160) × 0.25): DI = 0.01776
The pooled approximation is 32% higher than the correct number. On a well producing $5M of annual gross revenue, the model phantoms about $28,400 a year that the operator will never actually pay out. Across a portfolio of 50 tracts, the cumulative error compounds into seven-figure mispricing.
The geometry can also swing the other direction — when the wellbore traverses a larger share of a small tract, the allocation math exceeds the pooled approximation. The point isn't that one method is always higher; the point is that the pooled approximation is wrong in both directions, and you cannot tell which way without doing the geospatial intersection. The full math walkthrough is in the companion post on decimal interest math.
Classification signals — how to tell what kind of well you have
Before you can apply the right formula, you have to identify the well type. The RRC permit and the underlying lease tell you most of what you need:
- Vertical: RRC permit shows no lateral. Single section.
- Pooled horizontal: Pooling clause exists in the lease; a declared drilling unit is on file; either all owners signed pooling agreements or the leases include pooling clauses.
- PSA well: RRC permit references a Production Sharing Agreement; 65%+ royalty owner consent is on record.
- Allocation well: Horizontal well crossing multiple lease lines without 65% PSA consent on file. The permit lacks both a PSA reference and a unit declaration.
A common naming convention — though not universal — is that allocation wells carry an "AW" suffix in the well name, but you should never rely on naming alone; check the permit and the lease.
The takeaway
Texas built an entire horizontal-well industry on top of a regulatory construct (the allocation well) that has never been formally rule-made and whose statutory foundation has been challenged but never finally settled. As of 2026 that's still true. The 2025 Opiela settlement preserved the operational status quo without producing the Supreme Court precedent that would have either blessed the construct or required it to be redone through APA rulemaking.
For anyone valuing Texas mineral interests, the practical consequence is the same regardless of how the law ultimately resolves: the math used for pooled wells does not work for allocation wells. Allocation wells are now the majority of new horizontal-well permits in Texas. A calculator that applies pooled math to those wells is wrong. The error direction and magnitude depend on tract geometry, which is exactly why a defensible Texas mineral valuation pipeline needs an actual geospatial intersection step rather than a single ratio approximation.
What that geospatial step looks like — and the worked math comparison — is the next post. The post before it walks through Stages 1 and 2 of the pipeline: getting from a surface parcel to defensible net mineral acres in the first place.
Sources
- Texas Railroad Commission — Drilling Permits (W-1 / W-1H)
- Oil & Gas Lawyer Blog — Update on Opiela v. RRC (case history)
- Kuiper Law Firm — Opiela v. RRC: The Settlement that Left Texas PSA and Allocation Wells in Limbo
- Haynes Boone — Texas Third Court of Appeals on PSA wells
- National Law Review — Allocation and PSA Wells: Current State of Play
- Baylor Law Review — The RRC's Allocation and PSA Permitting Authority
- Oil & Gas Lawyer Blog — Production Sharing Agreements overview
Need to turn this engineering logic into a production-ready tool? Explore built custom engineering workflows for your team.