Since uncertainty breeds caution, throughout earnings season several E&P companies announced new capital spending restraints. In the past, these decisions were due to lower oil and gas prices, or stretched balance sheets that demanded that capital allocation be reset.

But today, lower spending is also borne out of a growing belief that E&Ps should focus on delivering returns. They’ve already proved they can grow production below $50 per barrel (bbl) and show improved well results in the bargain.

“Growth at all costs is taking a back seat to economic returns, at least for now,” wrote Baird senior analyst Daniel Katzenberg. “A welcome priority shift in our opinion.”

EOG Resources Inc. CEO Bill Thomas has been talking about this for a long time, and the company’s stellar financial and operational results are a sign EOG walks the talk.

Other analysts also noted this strategy shift. They think reduced spending could bolster crude prices eventually, although in the near term some stocks announcing this took a beating.

Kashy Harrison, senior research analyst for Piper Jaffray Cos., said industry seeks “a less incendiary growth” path.

“After years of capital destruction facilitated by a combination of misdirected growth incentives, volatile commodity cycles and benevolent capital markets, a desire for bottom line returns appears to be gaining traction,” said Harrison.

“Specifically, capital restraint appears to be in the early innings of seeping into capital allocation decisions by operators. Further, we cannot recall an earnings season where returns vs. growth was such a prevalent question.

“Of course, time will tell if these aforementioned decisions and trends are substantive and durable or the result of the current environment. As the saying goes, ‘Watch what they do, not what they say!’’

Anadarko Petroleum Corp. CEO Al Walker led off earnings season with his pledge to cut capex slightly. That was followed by small-percentage budget cuts for 2017 by Whiting Petroleum Corp., Pioneer Natural Resources Co., Devon Energy Corp., Hess Corp. and Diamondback Energy Inc. Sanchez Energy Corp. said it plans to lower 2018 capex estimates as well.

During Newfield Exploration Co.’s second-quarter conference call, CEO Lee Boothby opened his remarks by observing, “These remain very interesting times in our sector.” Later in the call, his voice grew urgent, almost stern, when he said, “It is our belief that the industry will be more rationale, more mature, more disciplined … Winners will find a way. …”

Despite reduced spending plans, companies are revising upward their type curves in every play while they drill longer laterals on tighter spacing, followed by much more intense completions.

“Year-to-date, we have generated more production than we expected, with less capital investment than we planned, and we are further increasing 2017 production guidance to reflect our projections for continued outperformance,” said SM Energy Co. CEO Jay Ottoson during his conference call. This mantra was repeated in so many words by a dozen other operators on their calls.

It’s THE big story. If they drill in the right zip code and apply ever-larger fracks, CEOs can prudently cut a rig here or there to reduce spending, yet at the same time, they aren’t necessarily reducing production growth estimates for the full year.

E&Ps are putting astonishing well results on the board. EOG reported a few months ago that at its Whirling Wind pad in Lea County, N.M., each of the four wells averaged 5,060 barrels of oil equivalent per day (boe/d) in the first 30 days.

Chesapeake Energy Corp. reported its biggest Marcellus well ever, with a 24-hour IP of 61 million cubic feet equivalent per day (MMcfe/d), after completing what it called the “Rambo frack.” It’s in Wyoming County, northeastern Pennsylvania. Now the company will reduce its operated rigs in the play from 18 to 14 by year-end. Southwestern Energy Co. said its well in Bradford County, Pa., the Seymour 1H, tested 37.7 MMcfe/d on an extended lateral of 12,000 feet.

In Oklahoma, Devon Energy Co.’s Privott well in southwestern Kingfisher County tested 3,000 bbl/d and 18 MMcf/d, or an astounding 6,000 boe/d, from the Upper Meramec.

From play to play, the leading operators keep upping the performance ante no matter what direction oil prices move. Pundits say the 950 rigs working now can yield production similar to what 2,000 rigs were achieving a year or two ago. Permian players claim they can hold oil production steady at $40, so if we ever see a sustained $50 or $55, then it’s “Katie, bar the door.”

These results are a tribute to the service companies and operators that have pushed the efficiency envelop about as far as it can go.

The next big question is, if the core of the core in a play gets drilled out to the max so efficiently, what comes next? Will the industry revert to the Tier 2 acreage (absent buying more of the core)? I think we’ll see the definition of which acreage merits being called core change with each new well. The rock quality may change two sections away, but the brain power gets better.