Permian Completions Weekly

By job end date. Faded columns are recent weeks still filling in — operators have up to ~30 days to file, so the newest weeks always start low and grow.

From NM OCD well records, horizontal wells in Lea / Eddy / Chaves / Roosevelt: 8,270 approved permits not yet spudded (the drilling backlog — includes some older unexercised permits) and 1,041 wells spudded 2023+ with no FracFocus disclosure yet — drilled or drilling, not yet frac'd (some are mid-completion or awaiting the operator's disclosure filing), of which 235 were spudded in the last 90 days — the wells hitting frac schedules next. Every well in the drilled column needs a frac crew and a drillout. Texas permit pipeline (RRC W-1 files) is the next data source to wire in.

From the RRC drilling permit master (current through early July): 5,404 approved horizontal permits issued since Jan 2024, not yet spudded or completed, in the 35 Permian counties. Texas receives spud dates late (typically with completion filings), so a drilled-not-yet-frac'd column isn't reliably possible from TX public data — the NM table above is the timelier read on that stage.

Everyone outside the top 10 with 6+ completions since March 1 (24 operators) — the private and mid-cap programs that don't make headlines but buy sand, water, and services every month. Entities reflect current ownership (e.g., Double Eagle's retained DE Central position; Tap Rock's NM wells now under Jonah Energy).

Median job design over each operator's own most recent 90 reported days — dark filers (e.g., EOG, whose disclosures stop in Dec 2025) appear at last-reported design rather than vanishing · operators with ≥8 jobs reporting water · "n/d" = proppant mass not disclosed (EOG reports water volumes but not sand mass) · basin median sand concentration 1.07 lbs/gal

Median job design by true vertical depth band — a rough proxy for target bench (103 of 117 jobs report TVD, water, and proppant)

FracFocus does not disclose target formation or perforated-interval length. Formation names (Wolfcamp, Bone Spring, Spraberry…) and true per-lateral-foot intensity (lbs/ft, bbl/ft) are planned additions via Texas RRC completion records and NM OCD pool data.

Jobs ended in last 28 days · formation resolved for 83 of 117 jobs by joining state records (TX RRC wellbore filings, NM OCD pool assignments) by API number

Jobs ended July 2025 – present with a completed-lateral length on file (1524 jobs). State completion filings trail the frac by ~3–6 months, so this table reflects the settled record, not the newest wells. TX lateral = perforated interval span (RRC); NM lateral = MD − TVD − 600 ft curve allowance (OCD).

Inferred from disclosure cadence: a pad whose latest job ended within ~1.5× its own well-to-well pace is probably still being pumped or just finishing. 17 pads read as likely active as of the latest filings (through Jul 19), 13 more recently released. Disclosures lag the frac by up to 30 days, so this view sees roughly half of true live activity — treat as a floor and a lead list, not a map. Pumper marked * is inferred from the operator's dominant 2026 service company. Field confirmations will upgrade rows from "inferred" to "confirmed" in the production version.

Pressure pumper identified on 69% of the last 12 months' jobs: from FracFocus supplier records directly, plus two inference methods — chemical fingerprinting (pumper-specific product trade names, e.g. proprietary friction reducers, validated on the directly-labeled jobs) and fleet continuity (operator/county/month blocks dominated by one labeled pumper). Fleet-equivalents from each pumper's observed pad pace over the last 90 days of reported jobs. "Not disclosed" jobs are genuinely unidentifiable from public data — largely self-sourcing operators and ProPetro's current work (identifiable only on pre-merger Endeavor filings) — so shares are a floor, not a census.

Fleet-equivalents = settled wells/28 days (last 3 fully-reported months, so slow filers like ExxonMobil are counted at true pace — marked ·· ) × the operator's own observed pad pace (days per well, multi-well pads) ÷ 28. This is an activity index, not a crew census — heavy simul-frac operators turn pads faster than their pad-window suggests, so their true crew count runs lower. Implied drillout units assume ~6 well drillouts per coil/workover unit per month. Basin total on this basis: 394 wells/28d ≈ 71 fleet-equivalents among operators with 4+ settled wells/month. NM data shows a median 34 days from frac end to first production (p25 19 – p75 57) — the drillout / cleanout / turn-in-line window.

Modeled from each job's disclosed sand, water, water-source mix, and lateral. Basin total from the last 3 fully-reported months: ≈ $1.91B per 28 days (1244 settled jobs), incl. ≈ $187M proppant and ≈ $124M water. Operator rows use each operator's own most recent 90 reported days, so slow and dark filers (ExxonMobil, EOG) are counted at last-reported pace — stale data is flagged. Estimates, not invoices — see assumptions below.

Assumptions (2026 Permian benchmarks + field estimates): sand $39/ton delivered (field-verified 2026: 100 mesh ≈ $38.9, 40/70 regional ≈ $39.9); produced/recycled water $1.00/bbl all-in; fresh $0.32/bbl sourcing; water transfer $0.13/bbl; pumping $50k/stage at 200-ft stage spacing; wireline & plugs $10k/stage; chemicals $20/lateral-ft; drillout & flowback $300k/well. Operators that don't disclose proppant mass (e.g., EOG) have sand estimated at the basin-median 1.10 lbs/gal of disclosed water. Model back-tests at ≈$424/completed-ft on settled wells, consistent with operator-reported D&C economics. AFEs are private; these are modeled market estimates.

Wells frac'd July 2024 – Feb 2026, 7735 with a clean 90-day production window. New Mexico: true well-level oil volumes from OCD C-115 filings. Texas: oil + condensate from RRC lease-level filings, allocated evenly across each pad's new wells, with legacy-producing leases excluded. IP90 = average daily oil over the first three reported production months.

Ranked by total base water volume