The rig count used to be the simplest proxy for how active US drilling was in a given month: fewer rigs, less activity; more rigs, more. That relationship has quietly broken down over the past several years, and the divergence between falling rig counts and record production is reshaping what drill pipe and downhole tooling actually need to do on the jobs that remain.
Fewer rigs, steadily declining since 2022
The decline has been substantial and sustained. Average active rigs in the US Lower 48 fell from a recent peak of 750 in December 2022 to 517 by October of the following year, a drop of roughly 30 percent. Oil-directed rigs alone fell 33 percent to 397 over that window, natural gas-directed rigs declined 23 percent to 120.
By the usual read on drilling activity, that would suggest a meaningfully smaller industry. It didn’t.
Production records despite the smaller fleet
Production kept climbing instead. In July 2025, crude oil production in the Lower 48 set a monthly record of 11.4 million barrels per day, and the following month natural gas production hit its own record of 117.2 billion cubic feet per day. Fewer rigs, more oil and gas out of the ground: a combination that only makes sense once you look at what each rig, and the drill string running through it, is actually doing.
The Permian Basin shows the pattern clearly. Operators there achieved an 18 percent production increase, roughly 1 million barrels per day, while the total rig count dropped 29 percent over the same period. Appalachia tells a similar story on the gas side: rigs down 29 percent, natural gas production up 10 percent, a gain of 3.3 billion cubic feet per day.
What efficiency actually means for drill pipe
The mechanism is operators focusing on the most productive plays, drilling longer lateral lengths to access more hydrocarbons per well, and applying more efficient completion techniques. All three trends put more demand on drill pipe specifically, even as the rig count shrinks.
Longer laterals mean drill strings spend more time in extended-reach sections, where combined loading, torque, bending, tension, and internal pressure from circulating drilling fluid all acting at once rather than as isolated load cases, runs more severe and more sustained than in a conventional vertical well. Connection integrity at the tool joint, where torque and bending stress concentrate most intensely, becomes the limiting factor for how far and how fast an operator can push a lateral before fatigue or connection failure becomes a real risk.
Grade selection reflects this shift too. Higher-strength grades once reserved for unusually demanding wells are becoming standard for extended-lateral work, because the combined stress profile of a modern long lateral routinely exceeds what a mid-grade pipe was ever designed to handle comfortably. Heavy weight drill pipe, positioned as the transition zone between standard pipe and drill collars, does more structural work in these strings too, managing buckling and compressive load issues that come with longer, more aggressively steered wellbores.
The rig count will likely keep drawing headlines as the go-to shorthand for industry activity, but the numbers underneath tell the more useful story. What’s happening in the Permian and Appalachia isn’t a shrinking industry. It’s a smaller number of rigs doing dramatically more per well, putting real, measurable pressure on drill pipe specification, connection design, and grade selection in ways the headline rig count doesn’t capture.
There’s a downstream consequence of extended-lateral, high-intensity drilling that doesn’t show up in production statistics but matters enormously to operators managing pipe inventory: fatigue accumulation. Drill pipe under more severe combined loading over longer laterals accumulates fatigue damage faster per foot drilled than pipe used in conventional vertical work, even when total footage looks similar on paper.
That’s pushed inspection intervals tighter for strings working extended-lateral programs. Operators running the most aggressive lateral lengths increasingly treat full-body and tool-joint inspection as a per-well or per-few-wells requirement rather than the longer intervals standard when most drilling was conventional. The economics still favor this: a failed connection downhole costs dramatically more than a more frequent inspection cycle. But the effective service life of a joint of pipe, measured in wells drilled rather than years owned, has compressed even as the pipe does more productive work per well.
Operators and drilling contractors planning pipe inventory for 2027 and beyond are increasingly specifying toward the higher end of available grades by default, given how routinely extended-lateral programs now exceed the stress envelope mid-grade pipe was designed around. That shift matters for manufacturers too; friction-welded tool joint quality and precision machining tolerances count for more when the pipe spends its working life closer to its stress limits than pipe built for more conservative vertical programs ever did.
Rental and third-party inspection companies have adjusted their own business models around this shift. A pipe supplier that used to run a standard inspection cadence across its entire rental fleet is increasingly segmenting inventory by well type, tracking which strings have worked extended-lateral programs separately from strings that have only seen conventional vertical work, because pooling them under one inspection schedule either over-inspects the easy pipe or under-inspects the hard-worked pipe. Neither is a mistake an operator wants to make twice, and the tracking overhead is a small price for avoiding a downhole failure on a well that costs millions of dollars a day to keep running.
