E&P companies put 68 additional rigs to work in first-quarter 2018, reversing a slight decline in the fourth quarter, which no doubt was due to bad weather and end-of-year budgets drying up.

Drillinginfo Inc. data suggest that more than half of the latest rig additions took place in January alone, as operators finalized their 2018 capital spending budgets and “scrambled to contract any remaining Super-Spec rig capacity,” said Guggenheim analyst Michael LaMotte in a report. The latter rigs, used for ever-longer laterals, are in hot demand in each shale play.

He expects the U.S. rig count to grow at a modest pace of two or three rigs per week through second-half 2018, because many operators were still scaling up at press time.

“Our 2018 forecast has been increased to 1,025 rigs from 960 rigs. However, we expect drilling activity to taper through 2H18 for two reasons: 1) We expect E&Ps to hit drilling activity targets by the end of 2Q18 and maintain them through 2H18; and 2) We expect capital allocation to shift away from drilling toward completions as frack constraints abate and DUC [drill but uncompleted wells] backlogs are likely to remain elevated.”

In this new era of capital discipline we have to ask, if 68 rigs went back to work in the first quarter, are they targeting the right acreage, i.e, locations with the highest returns and lowest breakeven numbers?

When Bernstein Research analyst Bob Brackett aggregated fourth-quarter 2017 results for 58 E&Ps, he found that EBITDA margins were the highest since third-quarter 2014. Organic capex only increased by 6.5% while operating cash flow increased by 25.5%. As a result, E&Ps spent 92% of cash flow on organic capex in fourth-quarter 2017.

Many companies are well beyond drilling to HBP; many are pivoting to the highest-return plays. Oh, to be a pure play in the Permian or Stack! SM Energy Co., which just sold assets elsewhere in order to focus on the Permian, is but one example of the latter. Chevron said it will focus on capital efficiency, not IPs or EURs, and thus, it will step on the accelerator to monetize its Permian assets. These will be an anchor for the company going forward, said Bruce Niemeyer.

“For EOG Resources Inc., we’d definitely say yes, it’s targeting the right things. One of the most active E&Ps, it will deploy 39 rigs in 2018; it added nine to achieve that level by the end of January, LaMotte noted.

A first-mover in many areas, EOG vows to be the leader among peers in return on capital employed (ROCE) through all commodity cycles. “Growth is an outcome of investing in high-return projects,” COO Billy Helms said, addressing a group at the Houston Petroleum Club recently. “But we’re not going to grow just for the sake of growth. If we get ahead of our learnings or returns, we pull back.”

Helms said he’s confident EOG can get back to double-digit ROCE this year after the downturn. Since inception in 1998, the company has posted an average ROCE of 13% to 2017. Last year, only 85% of its wells met that hurdle, but this year, all of them will, he vowed.

He attributed EOG’s success to four things: cost advantages, technical learning, science and great-quality rock. What’s more, it will ensure that its development pace does not exceed its technical progress. This philosophy must be working: In the Eagle Ford, its return averages 143% vs. the industry average of 41%, he said. In the Powder River Basin, it averages 113% vs. the industry’s 12%.

EOG only drills premium locations: those that will return at least 30% after tax, at $40 per barrel (bbl) oil and $2.50 gas. It claims more than 3,000 locations meet this strict hurdle.

“Our all-in reserve replacement is less than $10/bbl since we switched to this measure. We added 2,000 locations this past year and drilled about 500, so this is a permanent part of our strategy.

“Why would we drill anything else?” he asked.

The goal this year is to replace that premium inventory twice as fast as the drilling pace on it. EOG plans to drill 690 net wells, using 39 rigs and 19 frack spreads—and this level of activity makes for great negotiating power with service companies. EOG has locked up 85% of the rigs and 80% of the tubulars it will need and on procurement, it self-sources a lot of the materials such as drilling mud, chemicals and water.

But the supply chain or the pace is not the point—it is results that count. The company’s first-year gross production per well continues to improve. In 2017, its oil production rose 19%, all done within cash flow and while maintaining the dividend (which has risen 17 times in 19 years).

Helms advice? “Analyze big data for not only the production improvements, but for the returns a well makes. Technology is the tool to improve your margins, so once you figure out the optimum completion, then go to town.”

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