Targa Delaware’s newly approved Rooster Compressor Station in Ward County reflects rising associated gas volumes and increasing system pressure needs in the Delaware Basin. With 125 wells drilled in 2025 led by operators like APA, Crescent, and Continental, midstream infrastructure expansion is keeping pace with sustained, gas-intensive development in the Permian’s western core.
Oklahoma drilling remains in a steady-state holding pattern, with rig counts flat at 46 and operators maintaining disciplined, program-driven activity rather than expanding alongside national gains. YTD spud data shows activity concentrated among a few operators, with H&P and Cactus dominating contractor exposure and repeat rig utilization signaling continuity over acceleration.
Marcellus–Utica rig activity remains flat and highly concentrated, with a small group of core operators controlling nearly all active rigs across Pennsylvania, West Virginia, and Ohio. This is a capital-disciplined basin focused on steady, factory-style development—not a broad-based drilling recovery.
ConocoPhillips’ Lower 48 capital discipline is being driven by engineering, not activity cuts, with longer laterals emerging as a structural cost lever that lowers cost of supply by 25% moving from 1-mile to 2-mile wells and another 10–15% at 3–4 miles. By coring up acreage, standardizing execution, and concentrating activity on a small number of high-utilization rigs, COP is delivering more production for less capital while holding output steady and reducing Lower 48 capex year over year.
Chevron’s Q4 2025 results show that rig efficiency — not rig count — is now the primary driver of capital efficiency in U.S. shale, allowing the company to hold Permian production flat while materially improving cash margins. By concentrating rigs in its core Permian basins and extracting more output per rig through factory-style development, Chevron is turning shale into a cash-flow engine rather than a growth engine, regardless of commodity prices.
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The oilfield services sector is not broken or early-cycle—it is in a disciplined holding pattern where demand growth is inevitable, but capacity has not yet tightened enough to drive a true upcycle. Structural forces tied to LNG, power demand, and deferred investment point to 2027 as the economic inflection point, with pricing power and utilization tightening into 2028.
The oilfield services upcycle is unlikely to begin before 2027 because global markets must first absorb spare capacity, convert LNG and power infrastructure investments into sustained drilling demand, and force deferred upstream projects back onto the table. When that tightening occurs, the inflection will be driven by utilization and pricing power — not rig count — marking a true economic upcycle rather than a short-term activity bounce.
Patterson-UTI said the U.S. industry will require multi-year growth in drilling and completions to meet rising natural gas demand from LNG exports and power generation, as current activity levels are already beginning to pressure production. While near-term drilling may remain flat, they expect incremental rig demand to emerge in the second half of 2026 and beyond, with growth concentrated in high-spec rigs needed for deeper, more complex wells.
U.S. rig demand has moderated by design, not distress, with Helmerich & Payne forecasting a 132–148 rig full-year range that reflects operator discipline, inventory preservation, and a lack of urgency to grow volumes. The takeaway is a stable but selective shale market where fewer rigs are needed, yet each rig must handle harder, more complex wells—concentrating work with high-spec, performance-driven contractors.
