U.S. onshore horizontal drilling has improved steadily across every category, in part because of improvements in technology, but the “human experience factor” appears to be playing a substantial role as well in moving well times and depth curves to the left, according to an analysis by Tudor, Pickering, Holt & Co. (TPH).

With “drilling efficiencies” now a buzzword for exploration and production (E&P) operators, analysts Jeff Tillery, Joe Hill, Byron Pope and Klayton Kovac “drilled down” to the contractor level and delineated the rig count by power type and horsepower category. They wanted to determine whether horizontal drill time improvements followed new technology, or whether they resulted from coming up the learning curve by rig crews and E&P customers.

They initially researched the topic last fall to quantify the efficiencies (see NGI, Oct. 8, 2012). “Implications of Drilling Efficiency Trends for U.S. Land Drilling Companies and Stocks,” issued on Tuesday, is considered the second report of their quest.

Several things stood out. “Younger” plays are indicating more improvements than mature plays, in both days to drill and mobilization times. Improvements in drill days were not limited to a single asset class and were attributed in part to the learning curve. Experienced contractors outperformed in the beginning stages, but industry performance is converging.

Also, fleet composition continues to shift toward AC-powered rigs, while silicon-controlled rectifier (SCR) and mechanical rigs are “sidelined or retired.” Current utilization indicates strength at the higher-end market, with AC at 79%, SCR at 54% and mechanical at 36%. As well, drilling contractors that had the most high-end idle capacity were in the best position if the rig count rebounds.

“If crews are materially impacting drilling efficiencies, then it begs the question of extent of performance discrepancies among them,” noted Tillery and his team. “Our analysis suggests said discrepancies can be meaningful among drilling contractors in early days of unconventional play development and that there are first-mover advantages, albeit ones which generally appear to dissipate over time.”

They offered two examples: Nabors Industries’ (NBR) experience in the Williston Basin, and Helmerich & Payne Inc.’s (HP) in the Eagle Ford Shale.

“Both drillers outperformed the industry average in these respective plays, and we believe the root cause is experience. Over the last few years, NBR consistently holds the largest market share in the Williston Basin, while the same holds for HP in Eagle Ford.” The largest market share “implies having drilled the most wells for E&P operators active in the play (i.e., learning curve effect) and having largest physical presence (logistics, infrastructure, etc.).”

The disparity for operators’ drilling performance “is at its largest” in the early days, which was found in both the Williston and Eagle Ford “as variance between fastest and slowest contractor during 1Q2010 was 10 days in Williston and 16 days in Eagle Ford. These variances converged over time, currently only three days in Williston and two days in Eagle Ford.”

The “magnitude” of the advantage of first movers generally fades over time as E&Ps and service providers climb the learning curve.

“As these plays move to full development mode, the low hanging fruit (learning curve) has been picked, and we believe industry will need to turn toward other sources for additional well cycle time improvements. Our thesis is that this primary source will be a continued shift toward AC-powered rigs, at expense of older-vintage mechanical and SCR rigs.”

As horizontal drilling gains market share, AC-powered rigs will take more of it, said the analysts. “These rigs are better suited for the demanding nature of horizontal drilling due to their variable frequency drives, computerized electronic drillers and improved designs allowing for faster movements between wells.”

HP CEO Hans Helmerich early last year said the company’s AC-drive rigs were well suited to more complicated drilling work (see NGI, Feb. 6, 2012).

The shift in the rig count toward more AC power was found to be “much more dramatic” than for the overall U.S. rig count, noted the TPH team.

“For instance, the Eagle Ford shifted from 28% AC rigs in 1Q2010 to 65% in 3Q2012 versus the overall rig count having migrated from 21% AC rigs to 28% horizontal over the same period.”

Using Baker Hughes Inc. drilling data, TPH is forecasting 2013 U.S. land activity to increase by 7% from current levels, implying an addition of 120 rigs.

“Among the land drillers in our study, we count 57 AC, 204 SCR, and 133 mechanical rigs currently idle. Absent a sustained natural gas price rebound, we expect many of these SCR and mechanical rigs to remain idle, while higher-quality AC rigs return to work,” said analysts. That gives NBR and HP a possible advantage.

“We doubt U.S. land rig count activity accelerates fast enough for this earnings upside optionality to be in-the-money vis-a-vis 2013 results, but the point is to understand the true nature of one’s bets as it relates to investing in land driller stocks this year.”

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