This article is excerpted from a new Hart Energy product, The Well Site Market Report, a benchmarking service that includes weekly updates and monthly overviews on the U.S. land oilfield services market, including the well stimulation, drilling, completions and well service/workover segments. To participate in a free, no obligation 60-day trial, contact Richard Mason at rmason@hartenergy.com.

The 1990s television series “Star Trek: The Next Generation” had it right when it came to governing precepts. The underlying principle for Starfleet behavior when boldly traveling where no one had gone before was the prime directive, which forbade Jean-Luc Picard and his troops from messing with the local planetary mindset.

The oil and gas field services sector is experiencing its version of the prime directive. At the end of the day, at the low point in the oil and gas cycle, oil service activity is a function first and foremost of commodity price. It’s worth keeping energy’s prime directive in mind when attempting to game out the upcoming earnings call cycle for publicly-held oil service providers (OSPs.)

First, the set up: The sector bottomed in the second quarter following the basement in commodity prices that occurred in February. Rig count followed 90 days later by establishing its bottom in May. This was not out of line with the traditional rule of thumb that the land rig count follows commodity price with a 90-day lag. The third quarter started impressively with a commodity price rally that flirted with $50 oil, subsequently lost momentum at the halfway point, only to regain a little mojo as the quarter came to a close. One interesting story line about the rig count coming off the May bottom is that more than half of the new activity originated with privately held E&Ps, typically drilling lower tech wells and employing commodity rigs to do so, a development that was opposite of what Wall Street anticipated.

But hope that the strong out-of-the-gate start in the third quarter would serve as the initial step in a rising rebound for the sector in second-half 2016 is proving elusive. While the fourth quarter will be better, it will still lack the zest most OSPs need to overcome the sector’s economic headwinds.

It is instructive to look at changes in the nature of horizontal wells turned to completion during the third quarter as additional rigs went to work. The good news is aggregate volume increased about 200 wells above second-quarter 2016 in the major unconventional plays. The bad news is that the volume was still about 200 wells lower than first-quarter 2016. On a relative basis, second-quarter 2016 saw a sequential 31% decline in regard to wells turned to completion. Volume rose an impressive 22% in the third quarter, but still finished 16% below first-quarter levels, despite a strong flurry of September rig releases.

In other words, the recovery for the oil service sector was spottier and slower in the third quarter than several sell-side financial observers expected.

Midland Basin Mojo

A look at relative basin performance shows where E&Ps are circling the wagons. (see Horizontal Well Share By Basin graph.) This graph shows the Midland Basin increasing quarterly market share of all horizontal wells from 17% in fourth-quarter 2015 to 27% in third-quarter 2016. That’s material.

Elsewhere, both the Delaware and the Anadarko basins experienced an increase in relative market share from 13% and 12%, respectively, in fourth-quarter 2015 to 16% each of domestic horizontal wells in third-quarter 2016. In contrast, the Williston Basin saw its share of the domestic horizontal market unchanged, while the Eagle Ford/Woodbine/Austin Chalk experienced a net decline. Again, this takes place against a backdrop in which overall horizontal well count dropped 30% from fourth-quarter 2015 to third-quarter 2016.

Despite the carnage, the Midland Basin remains the only market to generate improved activity on a nominal basis during the period. Midland Basin E&Ps turned wells to completion at the rate of about 100 per month in third-quarter 2016 vs. about 95 per month in the final quarter of 2016. Although the gain is incremental, it is attracting headlines in a heavily challenged industry. All other domestic markets revealed lower nominal well count in third-quarter 2016 vs. the pace of activity in the last three months of 2015. That is the story in a nutshell for the major oily domestic markets.

Appalachia Narrative

Meanwhile, Appalachia and the traditional dry gas basins have their own narrative, which involves hope for an improved natural gas market this winter rather than any significant activity gains over the last year.

Maybe the most instructive item illustrating how E&Ps are responding to the low-price environment is found by comparing the Midland Basin to one other cohort in terms of drilled wells. Lumping remaining horizontal activity outside the major shale plays into an “all others” category finds the share of wells turned to completion in this segment drop from 27% of domestic horizontal wells in fourth-quarter 2015 to 14% in third-quarter 2016. Essentially, it is the mirror opposite of the Midland Basin.

Specifically, the main narrative in the 2016 domestic oil service market involves an expansion in Spraberry drilling in the Midland Basin, followed distantly by Wolfcamp Shale drilling in the Delaware Basin along the Texas/New Mexico state line and straddling the great bend of the Pecos River in Reeves, Ward and Loving counties in Texas. The evolving Mississippian-aged play in the Anadarko Basin runs a close third.

While there are notable regional activity headlines elsewhere, including improving well performance in the Marcellus/Utica in southwest Pennsylvania and the Haynesville in the ArkLaTex, those stories await an accelerating rate of change in a brightening natural gas market.

No Midland Mojo For OSPs

And that leads back to the prime directive. The Permian will be the leading indicator for the long-anticipated revival in demand for oil services. Unfortunately, the word in West Texas was mixed in September as volatility in commodity price took some mojo out of regional momentum.

Permian OSPs peg the sustained commodity price necessary for an increase in regional activity in the low to mid-$50s, which is about $3 to $5 lower than what OSPs are reporting in other unconventional plays. Tracking regional OSP perceptions over time is informative. Drilling contractors indicate the threshold recently moved back toward the upper $50s.

Elsewhere, workover contractors cite a sweet spot at which E&Ps increase routine maintenance for existing wells in the mid-$40s and increase completion activity as price moves above $45. Workover contractors also report E&Ps addressing drilled but uncompleted wells as oil price nears $50, which is echoed among well stimulation service providers.

At the end of the day, a recovery that provides sustainable economic health for OSPs has been pushed to second-half 2017. Consequently, OSP attitude currently resides in that precarious zone between hope that recovery is finally underway and fear that the next couple of quarters may not provide demand on a scale large enough to alleviate challenging economic headwinds.