Texas decimal interest math — pooled vs allocation walkthrough

Same well. Same NMA. Same royalty rate. Two methods. The pooled approximation gives a decimal interest of 0.02344. The correct allocation-well math gives 0.01776. That's a 32% gap on the same well — and on a $5M-per-year producer it's $28,400 a year the wrong calculator phantoms into existence. This post walks through both formulas, shows the worked example, and explains the geospatial step that makes the allocation-well answer defensible.

This is Stage 4 of the five-stage mineral valuation pipeline. The anchor post explains why allocation wells exist and what their legal status is. The data-layer post covers how to get a defensible NMA into the math in the first place. This one is the math itself.

Classify the well before you do the math

The decimal-interest formula depends entirely on what kind of well you're looking at. There are four families, and applying the wrong formula gives a wrong answer regardless of how careful the inputs are:

The first three formulas are simple ratios. The fourth requires a geospatial intersection. That single difference is the source of most Texas mineral mispricing.

Pooled unit math

The pooled-unit formula assumes every mineral owner in the drilling unit shares the well's production proportionally to their share of the unit. It's the simple ratio that most calculators implement:

DI_pooled = NMA ÷ unit_acres × royalty_rate

Example:
  NMA           = 60
  Unit acres    = 1,280   (standard 2-mile-lateral Permian unit)
  Royalty rate  = 25%
  DI_pooled     = 60 ÷ 1,280 × 0.25
              = 0.011719   (~1.17%)

This formula works when the well is genuinely pooled — when all mineral owners on the drilling unit have either signed pooling agreements directly or have leases with pooling clauses that the operator can use. In modern Texas hot acreage, that's increasingly rare. Most modern horizontal wells in Texas are allocation wells, not pooled wells, and the math is different.

Allocation well math

The allocation-well formula computes the mineral owner's share based on the actual physical length of the productive wellbore inside their tract — not on a unit-wide proportional split. The formula has three multiplicative factors:

DI_allocation = (productive_lateral_through_tract ÷ total_productive_lateral)
              × (NMA ÷ tract_acres)
              × royalty_rate

Where:
  productive_lateral_through_tract = length of the producing portion of the
                                     wellbore physically inside the mineral
                                     tract (after subtracting non-productive
                                     heel and toe sections)
  total_productive_lateral         = total producing wellbore length, summed
                                     across all tracts traversed

The first factor is the lateral share — what fraction of the productive wellbore is in this tract. The second factor is the tract share — what fraction of this tract the mineral owner holds. The third is the royalty rate from the lease. Multiplied together, they give the owner's share of every barrel produced from the well.

The worked comparison — same well, two methods

Consider a tract with these characteristics:

• 60 NMA in a 160-acre mineral tract
• 25% royalty rate
• 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

If you treat the well as pooled into a hypothetical 640-acre unit (which a generic calculator would default to):

DI_pooled = 60 ÷ 640 × 0.25
          = 0.0234   (~2.34%)

Allocation-well correct math

DI_allocation = (1,800 ÷ 9,500) × (60 ÷ 160) × 0.25
              = 0.1895 × 0.375 × 0.25
              = 0.0178   (~1.78%)

The gap

On the same well, with the same NMA, the same royalty, the pooled-math estimate is 32% higher than the correct allocation-well figure. To put that in dollars:

Across a portfolio of 50 tracts, that compounds into seven-figure mispricing.

The direction of the error depends on geometry

The pooled approximation is not always higher. Consider an alternate scenario where the same wellbore traverses 4,500 ft of a smaller 100-acre tract:

DI_allocation = (4,500 ÷ 9,500) × (60 ÷ 100) × 0.25
              = 0.4737 × 0.60 × 0.25
              = 0.0711   (~7.11%)

DI_pooled (60 ÷ 640 × 0.25)      = 0.0234   (~2.34%)

Here the allocation math gives a decimal interest three times larger than the pooled approximation, because the wellbore is concentrated in a small tract where the owner has a big stake. The pooled approximation systematically understates this owner's interest.

The point: pooled math is wrong in both directions, and you cannot tell which way without doing the geospatial intersection. That's why the calculation cannot be approximated — it has to be computed.

The geospatial pipeline that makes this correct

Pulling the well-bore as-drilled path from the Railroad Commission gives you a polyline in latitude/longitude (or, more commonly, in the State Plane projection the RRC publishes). The full correct calculation:

1. Pull the productive-lateral polyline. Not the entire wellbore — the productive section. The RRC permit and the operator's completion report identify where the heel (kick-off-point or KOP) and toe shoe segments are; those don't produce and shouldn't count toward the lateral length.
2. Reproject if necessary. Compute lengths geodesically or in an equal-area projection. Never compute lengths in Web Mercator at Texas latitudes; it'll be off by several percent.
3. Intersect the productive polyline with the mineral tract polygon. In PostGIS, this is ST_Intersection(geography(LINESTRING), geography(POLYGON)) — using the geography type, not geometry, so the intersection respects curvature.
4. Compute lengths of the intersection and of the original productive polyline. Both with ST_Length on the geography type.
5. Take the ratio. intersection length ÷ total productive length.
6. Apply the allocation formula with the owner's NMA, the tract acres, and the lease royalty rate.

A representative query:

WITH well AS (
  SELECT
    permit_id,
    productive_path::geography AS path_geog
  FROM wells WHERE permit_id = :permit
),
tract AS (
  SELECT
    geometry::geography AS poly_geog,
    acres
  FROM mineral_tracts WHERE id = :tract
)
SELECT
  permit_id,
  ST_Length(ST_Intersection(well.path_geog, tract.poly_geog)) AS tract_lateral_m,
  ST_Length(well.path_geog)                                    AS total_lateral_m,
  ST_Length(ST_Intersection(well.path_geog, tract.poly_geog))
    / NULLIF(ST_Length(well.path_geog), 0)                    AS lateral_share,
  tract.acres
FROM well, tract;

That query gives you the two components — lateral_share and tract_acres — that go into the allocation formula. NMA and royalty rate come from the ownership and lease records (Stage 2). The arithmetic that joins them is a single multiplication.

Edge cases

• Well drilled before the tract was severed. Ownership at first production may differ from current ownership; you may need to track the chain back to the date the well was permitted to identify the correct historical owner.
• Lateral re-entry or sidetrack. Count the productive sidetrack, not the original (now plugged) bore. The completion report identifies which is which.
• Multi-tract allocation across counties. Geospatial intersections at scale are expensive; pre-index mineral tract polygons with GiST.
• Operator's reported allocation differs from your calculation. Don't silently overwrite either number. Surface the gap explicitly as a candidate for division-order audit. The operator's number is what they're paying you against; your number is what they should be paying.
• Well crosses a state line. Different regulatory regimes (Texas RRC vs. New Mexico OCD for Delaware Basin wells) report wellbore data in different formats. Reconcile to a common projection before intersection.

The takeaway

Texas decimal-interest math splits into two regimes depending on the well type. For vertical wells, pooled horizontals, and PSA wells, the math is a simple ratio that almost any calculator gets right. For allocation wells — which now account for the majority of new horizontal-well permits in Texas — the math requires a geospatial intersection that almost no off-the-shelf calculator does.

The cost of using the wrong formula is real and varies with tract geometry. The pooled approximation overstates the owner's interest when the wellbore barely crosses the tract, and understates it when the wellbore traverses most of the tract. Multiplied across a portfolio, the cumulative pricing error is seven figures on most institutional positions.

The fix is straightforward in principle: classify every well, apply the right formula, and use a geodesic geometry library (PostGIS or equivalent) for the allocation-well case. The fix is hard in practice only because the data integration — pulling productive-lateral polylines from RRC, reconciling them with mineral tract polygons from county GIS, and tracking which formula belongs with which well — is the kind of work that doesn't fit in a spreadsheet.

The next post in the series covers what happens after the decimal interest is computed: turning per-well DI plus a forecast and a discount rate into a defensible NPV, PV-10, and per-NMA price.

Sources

• Texas Railroad Commission — Drilling Permits and as-drilled wellbore paths
• RRC Texas — Production Data (P-1 monthly reports)
• PostGIS — ST_Intersection documentation
• PostGIS — ST_Length (geodesic length on geography type)
• Oil & Gas Lawyer Blog — Opiela v. RRC (allocation-well legal background)
• National Law Review — Allocation and PSA Wells: Current State of Play
• National Association of Division Order Analysts (NADOA) — model division order standards

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