A version of this story appears in the August 2017, edition of Oil and Gas Investor. Subscribe to the magazine here.

Fasten those seatbelts. Oil and gas has a been busier than commonly understood and the tsunami of accelerating field work in first-half 2017 will add significant crude oil production by year-end 2017.

The production surge does not bode well for the price of oil heading into 2018. Still, it is an unequivocal testimonial to the size of the mobilization effort that the oil service sector has provided exiting the worst financial trough in 35 years.

It is useful at midyear to revisit the industry’s oft-discussed manufacturing model to benchmark the arc of development in tight formation plays. Whether measured by new drilling permits, active rig count, wells waiting on completion, or completions themselves, field activity underwent a step level change in first-half 2017.

The most widely followed industry statistic is rig count. After industry capitulation in second-quarter 2016, average quarterly rig count in tight formation plays rose 12% in third-quarter 2016, 26% in fourth-quarter, 28% in first-half 2017 and 24% in second-quarter 2017. From trough to peak, horizontal drilling in tight formation plays gained 421 units, or 158% vs. the second-quarter 2016 trench.

Those rigs drilled laterals of greater complexity more quickly, mostly due to pad drilling and greater downhole intensity in the form of trainloads of proppant and closer stage spacing. Crowd-sourced data via Hart Energy’s “Heard in the Field” surveys indicate the percentage of zipper fracks bottomed at 44% of wells at the trough in second-quarter 2016 and improved to an all-time high of 76% in second-quarter 2017. Zipper fracks are a proxy for batch completions on pad sites. At the low point, operators were drilling multiple wells but only completing a single well to capture acreage. As the industry entered 2017, operators began completing the backlog of drilled but uncompleted wells (DUCs) while simultaneously completing newly drilled wells.

Of note, the nature of rig count expansion indicates the increase in field activity is program-based as opposed to spot market driven. The move is backed by hedges executed earlier in 2017 when oil traded above $50, or driven by private equity-backed privately held entities that are capturing acreage and ramping activity in anticipation of a future exit. Meanwhile, E&P outspend continues in tight formation plays with operators promising for the seventh straight year that they will return to spending within cash flow soon.

Horizontal permit volume in four major tight formation plays, including the Denver-Julesburg Basin, Eagle Ford, and the Midland and Delaware basins was up 89% in June 2017 when compared with fourth-quarter 2016. Furthermore, horizontal permitting continued to accelerate past midyear. While permits are not a guarantee of future drilling, they serve as a reflection of future expectations.

The acceleration in drilling activity during first-half 2017 was reflected in a 75% increase in horizontal well starts when compared with fourth-quarter 2016. The number rose from an average 10.26 per day in fourth-quarter 2016 to 18 in second-quarter 2017 in the major tight formation markets, led by privately held oil and gas operators and followed by small- to mid-cap public independents. Combined, these two cohorts accounted for 58% of well starts, according to state records, but grew to more than 63% of new well starts in early July. It is worth noting that management in these two groups historically is the most responsive to change in commodity price.

Market share for the top 25 most active drilling programs remained at or about 51% over the last three quarters with the stability in share suggesting the current expansion is program-driven and broad-based. That is further indication that momentum will continue deep into the second half of 2017.

Persistent softness in commodity price presages expectations that a shale production tsunami is heading to the global crude oil market as 2017 closes out. Crowd-sourced data suggest operators are in the early stages of re-assessing 2018 plans.

First, operators are pushing back on well stimulation pricing as they grapple with declining efficiency as new crews are rushed to the market. The average price per stage was approaching $60,000 in June 2017 vs. $34,000 at the trough. Crews are also facing double the time to complete a stage due to greater downhole inputs. Proppant per lateral foot was up 22% in first-half 2017. Secondly, E&Ps are debating whether to pick up new projects once current hedging expires over the next six to 12 months. Thirdly, few operators express interest in following the DUC strategy that characterized the market downturn two years ago; it just doesn’t make economic sense with higher field cost.

Stay tuned—and keep those observational seatbelts firmly fastened.

Richard Mason can be reached at rmason@hartenergy.com.

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