Coming off a two-year period of belt-tightening the first-quarter earnings of some North American exploration-and-production companies are expected to reflect the first signs of new gas production growth, but that growth is conditional upon the basins where the producer operates and the individual company's economic circumstances going into the quarter.
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In addition, the quarterly results are apt to show a continuation of the trend of producers increasingly focusing on basins with better economic returns -- chiefly oilier and more liquids-rich plays -- while downplaying efforts in the drier gas basins.
US drilling activity has been on the upswing, particularly in the Permian Basin of West Texas and southeastern New Mexico, the hottest oil and gas play in the country.
Producers in recent months have flocked to the Permian, which boasts some of the highest initial production (IP) rates for oil and gas of any basin in the country. The Permian hovers around a 30-day average oil IP rate of 600 b/d, and for the gas the IP rate is closer to 1,400 Mcf/d, according to Platts Analytics.
Crude-focused producers such as Anadarko Petroleum are expected to post strong Q1 results as a result of investments in the oil-rich Permian as well as the DJ Basin of Colorado, another oily province.
Anadarko said last month it expected a 25% increase in oil sales volumes over the prior year.
Meanwhile, some gas producers could see production growth in the quarter as well. Appalachian producers operating in the liquids-rich portions of the basin -- chiefly the southwestern Marcellus and Utica plays -- are largely expected to increase drilling and production in the quarter compared with the same period last year.
Consol Energy recently said it expects to double its capital expenditures in full-year 2017 to an estimated $555 million, versus $205 million last year, while it expects to increase its production by about 5% to 1.14 Bcfe/d in 2017 compared with actual production of 1.08 Bcf/d in 2016.
Appalachian producer Range Resources also provided guidance that it would increase its capital expenditures to $1.150 billion versus $513 million in 2016, while the producer estimated it would increase its production for full-year 2017 to 2.07 Bcfe/d versus 1.54 Bcfe/d in 2016.
To drill a well in the Marcellus costs around $6 million with a gas IP rate of 10,000 Mcf/d, according to Platts Analytics. Producers drilling in the Utica Shale in eastern Ohio have mentioned gas IP rates around 20,000 Mcf/d with a well cost around $10.6 million.
Chesapeake Energy, which operates in a number of basins across the country, is expected to drill and produce less oil and gas than last year, largely as a result of the sale of some of its non-core assets, such as the Barnett Shale of North Texas last year, according to its most recent guidance.
The producer will operate fewer rigs and drill fewer wells in 2017 than it did last year. The company said in February it plans to operate an average of 16-18 rigs in 2017, compared with 28 in 2016, and complete 420-480 gross wells, compared with 547 last year.
For Q1, the company expects production of 515,000-535,000 b/d of oil equivalent, of which oil production is expected at 80,000-85,000 b/d, which is consistent with prior guidance, Chesapeake said.
Meanwhile, other producers, such as Gulfport Energy, have already posted positive results by pursuing a diversified basin strategy.
Earlier this month the producer reported that Q1 production of 850 MMcf/d came in above expectations, "driven by the continued strong performance of our Utica Shale assets."
In addition, the producer said in the quarter it closed on the acquisition of assets in the SCOOP play of central Oklahoma from Vitruvian II Woodford, and since the closing in mid-February has been running four operated rigs on the acreage.
Among other trends expected to surface in the E&P companies' quarterly reports are an increase in the cost of drilling services, particularly the percentage of drilling costs that go toward the purchase of fracking sands.
As producers drill ever-longer laterals and pump greater volumes of proppants, the cost of the sand is expected to increase, taking up a larger portion of producers' drilling budgets.
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--Edited by Jason Lindquist, email@example.com