Permian Completions Weekly

For weeks this newsletter has run the same callout: EOG's paperwork was dark — 244 days dark at last issue, newest job end 2025-12-24 — while New Mexico showed it sitting on the largest DUC backlog in the basin. That callout is now inverted. On this week's bulk file EOG has filed 15 disclosures with 2026 job ends — five in July, ten in August — and its newest job end is 2026-08-24, 8 days back. It goes dark → current in one step, and it is the sixth most active filer of the last 28 days at 10 jobs.

It does not appear in the operator table below, and that is not an error. Settled pace counts jobs that ended 42–126 days back; only five of EOG's new filings fall in that window, so its settled pace reads 1.7/28 d. Expect it to jump next issue as the July and August jobs age into the window. Every pace, fleet and county figure in this issue still understates EOG.

The New Mexico pipeline says the same thing from the other side. EOG's unspudded permit bank fell 10 to 999 — a second consecutive fall and its first print under 1,000 — while its New Mexico DUC stack rose 10 to 815. It is drawing down permits, converting them to drilled wells, and now filing the completions. Devon is the mirror image: unspudded up 24 to 1,326 on its own filer name with DUCs flat at 408. EOG is drilling and converting; Devon is permitting.

Two other things worth saying out loud this week. XTO is the biggest mover in the settled table — 24.7/28 d against the 17.3 we published, +7.4, taking third place — while Occidental, Cimarex, Chevron and Apache each filed zero disclosures in the last 28 days, which is lag, not idleness. And in the county book Midland falls out of the top six entirely, at two jobs against sixteen last issue, as the work concentrates on Lea and Eddy.

Everyone remembers the loading race. From 2016 to 2018 the median Midland Basin well went from 1,474 to 1,855 lb per perforated foot — a 26% jump in two years, the era when every investor deck had a "bigger fracs" slide. Then the race just… stopped. Since 2018 the median has crept from 1,855 to 2,038 lb/ft — about 10% in seven years, and the preliminary 2026 column sits at 2,007 lb/ft, statistically indistinguishable from 2025. Call it ~2,000 lb/ft: the design equilibrium the basin settled on once the cost-per-barrel math stopped rewarding more sand.

Last issue this card said "nothing moved, and the wellbore file was stale — watch the next dbf900 drop." The drop landed on Aug 29, and it is worth reporting that it changed nothing. Two joins have to move for this chart to move — a perforated interval from the RRC and a proppant mass from FracFocus — and the fresh file added 31 wells to the 2026 sample without shifting its median by a pound. That is a real result, not a skipped refresh: the equilibrium held against a 12% larger sample.

The sand bill still doubled — but sideways. Median perforated interval went from 7,642 ft (2016) to 10,522 ft (2025), and median sand per well from 11.8M to 24.7M lb. The growth was laterals, not loading. The 2026 wells joined so far run a median 10,433 ft at the same loading, which is the whole thesis in one line.

Design still isn't monolithic: among 2025–26 completions, Pioneer's median well takes 30.7M lb (n = 743) against Diamondback's 20.8M (n = 807) — same basin, same benches, a 10-million-pound difference in what shows up on the pad. Both reproduce last issue's figures exactly; that line is computed sand-only, with no perf join.

The basis. Completion cost is now built per lateral foot: four foot-priced lines — pumping spread and stimulation service, wireline/plugs/pumpdown, chemicals and additives, and site, rentals, supervision, fuel and other — at $225 per completed foot combined; two pass-throughs priced on the job's own measured volumes — proppant at $0.016/lb on the disclosed sand, and water split by the disclosed produced/recycled share; and three flat per-well lines — drillout, flowback and early production, and tubing, wellhead and surface facilities. The sand-throughput day term is gone entirely.

Where the lateral comes from, and what is wrong with it. The 10,369 ft is a perforated interval, not a drilled lateral, and it is not this issue's wells. It is the median perf span of the lagged cohort: Texas wells completed 6 to 12 months before this issue (n = 1,459, 78% TX coverage). It has to be, because RRC perforation records land 4 to 8 months after the frac — the direct join on this issue's own settled jobs is 1.4%, and on a 28-day window it is essentially zero. A current-window lateral does not exist. Worse, the few recent joins are biased large — prompt filers are big-job operators — so using them would overstate the median. New Mexico has no perforation source at all: dbf900 is a Texas RRC file, only 7 of 15,652 NM disclosures ever join, and NM is a third of every window. The foot priced here is therefore a Texas perforated foot applied basin-wide. For scale, the median permitted lateral this issue is 11,228 ft, 8% longer — the expected heel/toe standoff between drilled and perforated.

The sanity check that should have caught this. The suspended model would have printed about $10.2M on a ~10,369 ft well. Divide it by the lateral: ≈$981 per foot for the completion alone — more than the all-in drilling-and-completion cost per foot of every public Permian operator, which runs about $675–$1,035/ft (Permian Resources at $675–685/ft; Matador at $835–855/ft; Civitas Delaware at $880/ft). A completion-only number cannot exceed an all-in number. The rebuilt figure lands at $409/ft, implying roughly $709/ft all-in once about $300/ft of drilling is added — inside the operator band rather than above it. Standing rule: check any well cost per lateral foot against operator guidance before it ships.

Pricing the median understates the basin. The lateral distribution is bimodal, not a bell: on the well-covered cohort 38% of wells fall in the 10,000–11,000 ft (two-mile) band and 14% in the 15,000–16,000 ft (three-mile) band — roughly one job in seven is a three-miler. A median-only model prices those wells light. Holding these rates and moving only the lateral: a p25 10,058 ft well costs $4.17M and a p75 13,739 ft well costs $5.00M, against $4.24M at the median. The basin run-rate above is therefore a floor, not a midpoint.

Quantities. Median sand, water and produced-water share across this issue's 967 settled jobs (job end 42–126 days back) — the same population the section always priced, not the 28-day tile. 821 of the 967 disclosed sand.