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Producers More 'Comfortable' as Costs Decline, High Grading Continues

The sharp decline in oilfield service (OFS) costs and a focus by explorers on the best drilling locations may mitigate the drastic drop in commodity prices and improve the bottom line for the exploration and production (E&P) sector, according to experts.

An analysis by IHS Energy found that U.S. E&Ps may post a 25-30% increase over 2014 in average efficiencies of their onshore upstream capital investments. Researchers also are forecasting a 60%-plus increase in overall capital efficiencies by the end of this year from 4Q2014.

"This substantial improvement for E&P performance results from many forces, but the key driver is the compounding effect of the high-grading of drilling locations combined with the continuing reduction in drilling and completion costs, which we at IHS Energy estimate has led to a roughly 10% gain in capital efficiencies since December," said IHS Energy's Raoul LeBlanc, senior director of research. He is lead author of the new IHS Energy analysis, "Strong Capital Efficiency Gains Mitigating Damage to E&P Companies."

"We expect those drilling and completion costs to fall by about 15% on average and climb to reach 30% by year-end," he said.

The specific plays driving the most capital investments today are the Permian Basin and the Eagle Ford and Bakken shales, which together accounted for 62% of capital invested from January 2013 to May 2014, according to IHS. Close to 75% of the capital generating production from the three plays had breakevens of less than $70/bbl.

A poorer return on capital is concentrated in smaller plays, which make them prime candidates for reductions, said IHS Energy's Stephen Trammel, who directs unconventionals research. More attractive assets should line up once prices improve.He conducted supporting analysis examining how E&Ps are coping with the fallout from success following the oil price decline.

Goldman Sachs analysts Damien Courvalin and Raquel Ohana said the costs to drill wells in the U.S. onshore have fallen enough to incentivize some E&Ps to begin drilling again. If oil prices remain near $60/bbl West Texas Intermediate, producers will become more "comfortable" with the costs, the returns and the funding mix.                      

"The current U.S. horizontal and vertical rig count across the Permian, Eagle Ford, Bakken and Niobrara shale plays implies that U.S. oil production growth will reach 155,000 b/d  year/year by 4Q2015 if we account for the impact of a 10% delay in well completion (120,000 b/d assuming no deferral)." The current rig count in the U.S. onshore is pointing to a decline in domestic output sequentially between the second and third quarters, said the Goldman analysts.

"Production would continue to grow in 2016 by 205,000 b/d at the current rig count under our well deferral scenario, which we view as likely given the observed rise in the well backlog. While we attempt to take into account the impact of increased productivity, factoring in that well productivity in the first half of 2015 is double its 2013­-2014 trend, we see risk to our production modeling as skewed to the upside later this year should high grading become more apparent.

"Further, a rapid drawdown of the observed backlog of uncompleted wells could lead to higher production later this year and in 2016," the Goldman analysts said. The current rig count "implies that U.S. production will sequentially decline in 3Q2015, although [it will] continue to grow in 2016."

Goldman's scenario assumes that well productivity in the first half of 2015 is double the trend of 2013 and 2014, but it should be flat in the second half of this year. The delay between rig activity and well production is two months.                                                                                            

The sharp decline in service costs, particularly to drill and complete wells, should help stabilize many E&Ps. As utilization has fallen, the OFS sector has lost pricing power and has had to increase discounts amid fierce competition. Domestic OFS spending this year could decline by about one-third year/year, according to a recent survey by Douglas-Westwood (see Shale Daily, May 21). Operators indicated in first quarter conference calls that they were making deals to keep clients happy.

"Despite these discounts and other considerations, these improvements in capital efficiency do not fully offset lower prices for E&P companies," LeBlanc said. "Producers would still be much better off if oil were at $100/bbl. Furthermore, the gains are not irreversible, but rather a function of the downcycle."

According to IHS, capital efficiency gains by E&Ps should act to lower breakeven prices and raise activity levels at least modestly, which could lead to improved production growth at a given price.

"This should make a material difference in 2016 E&P company performance and plays an important role in our IHS view that U.S. production will be able to rebound in 2016, even if capital budgets remain muted," Trammel said.

"The E&P companies are the relative winners in this scenario as margin migrates out of services to the E&P sector," Trammel said. "Even in a flat commodity price environment, getting more for each dollar invested should allow producers to experience improved profit margins."

The OFS sector could see a rebound in activity but overall, capital efficiencies are working against those companies, at least in the short term.

"Well completions are primarily focused on the larger unconventional plays, and IHS expects that as costs continue to fall and oil prices begin to rise, the industry will start to drill the prime picks from the inventory of 2,500-3,000 drilled but uncompleted [DUC] wells that exist in the U.S. unconventional plays," Trammel said. "This will generate efficient growth for operators and reduce idle capital."

Genscape Inc.'s Randall Collum, managing director of supply side analytics, said in April U.S. operators had planned to defer more than 800 onshore wells, but if oil prices were to increase, there was a real possibility even more production would ramp up this summer (see Shale Daily,April 10). Analysts had estimated in March that there were about 3,000 DUCs across the country.

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