Two operators can hold acreage a mile apart, drill the same formation to the same lateral length, and still book wildly different production. One has a completion recipe dialed in; the other is still learning the rock. If you're a mineral buyer weighing where to lease, an investor sizing up a management team, or an operator benchmarking against the competition next section, the question is blunt: who drills the better well here?
It's an answerable question. The record holds every well both operators have completed in the county, and once you normalize for the obvious differences, the gap usually shows up fast.
Start by pulling both books, same county
The first move is to isolate each operator's wells in a single county and look at them side by side. Ask the platform for both operators' production history in, say, Reeves County, and you get two populations to compare — count of wells, first-production dates, cumulative oil and gas, and each well's early rate.
Raw averages lie, though. If Operator A has fifteen wells that came online in the last eighteen months and Operator B has forty wells stretching back six years, B's book will look tired simply because more of its wells are further down the decline curve. Vintage matters. So does lateral length, and so does the target bench. Before you crown a winner, the wells have to be put on equal footing.
Normalize before you compare
The honest comparison controls for the things that aren't about operator skill:
- Vintage. Group wells by completion year. A 2024 well and a 2019 well are at different points in their lives; comparing their current monthly rates tells you nothing. Compare first-year cumulative to first-year cumulative.
- Lateral length. A 10,000-ft lateral should out-produce a 5,000-ft lateral. Normalizing to production per thousand feet of lateral strips that advantage out and tells you who's getting more per foot of rock contacted.
- Formation. If one operator is landing in a better bench, that's a geology story, not a completions story. Filter to a common target where you can.
Once you've done that, the comparison gets clean: for wells of the same vintage, same bench, same lateral length, what does each operator's average well cumulatively produce at 6, 12, and 24 months?
Build the two type curves
The clearest way to see it is to build an average well — a type curve — for each operator from their county wells, then overlay them. Ask for the county type curve segmented by operator and you get two decline profiles on the same axis.
This is where the differences stop being anecdotes. You'll see things like:
- Higher IP, same decline. Operator A's wells come on 30% stronger and hold a similar decline shape — a cleaner completion, more effective stimulation, better landing. That gap compounds into meaningfully more cumulative oil.
- Same IP, shallower decline. Two wells peak at the same rate, but one flattens out while the other falls off a cliff. The flatter well recovers far more over its life — often a sign of better reservoir contact or a more conservative choke management program.
- Higher IP, steeper decline. The aggressive completion that flashes big early and gives it back. First-year numbers flatter it; the 24-month cumulative tells the real story.
The 12- and 24-month cumulative per thousand feet of lateral is the single number that cuts through most of the noise. It captures both the early rate and how well the well holds up.
Check consistency, not just the average
An average can be carried by one or two monster wells. Before you conclude one operator is simply better, look at the spread. If Operator A's book is a tight cluster of solid wells and Operator B's is a handful of great wells surrounding a lot of mediocre ones, that tells you something about repeatability. An operator who can reliably drill a good well is worth more than one who occasionally drills a great one and often misses.
Outlier detection helps here — flag the wells sitting well above or below each operator's own trend, then decide whether to keep them in the comparison or set them aside as one-offs (a stray refrac, a well that ate an offset frac hit, a long shut-in).
What the answer is actually for
Once you've got the two normalized type curves and the consistency picture, the question resolves into a decision:
- Leasing minerals? Lean toward the acreage the better operator is developing — you'll capture more barrels per section.
- Underwriting a deal? A team that consistently out-produces its neighbors on the same rock is booking real, repeatable value, not just riding good geology.
- Benchmarking your own program? If a competitor is pulling 20% more oil per foot from the same bench, that's a completions conversation worth having before you drill the next pad.
The rock is the rock. Two operators standing on the same rock, delivering different results, is one of the most useful signals in the county — and it's sitting in the record, waiting to be pulled.