Apache Corp., which now claims to be the second biggest North American onshore operator, reported a 45% increase in total liquids output year/year in the United States and Canada, driven by a revamped drilling program in the legacy Permian and Anadarko basins.
North America onshore drilling also rose 6% from the fourth quarter, CEO G. Steven Farris told analysts during a conference call.
“Our onshore North American liquids production averaged 165,000 b/d of oil, which constitutes 21% of our total worldwide production,” he said. Farris credited the U.S. onshore asset base, “which we bolstered over the last three years,” as the biggest contributor.
“Apache is currently the second most active U.S. onshore driller. During the first quarter, we averaged 206,000 boe/d from the Permian and Central regions alone, or 26% of our worldwide production.”
The gains “represent a 50% increase over the first quarter of 2012, and a 40% increase if you adjust for the Cordillera acquisition,” he said. Apache bought Anadarko Basin-focused Cordillera Energy Partners III LLC in early 2012 (see Shale Daily, Jan. 24, 2012).
“In addition, our Central region in the Anadarko Basin grew production almost 9% from the fourth quarter of 2012 to the first quarter, or nearly 36% on an annualized basis, and increased liquids production over 28%.”
Apache today is running 42 rigs in the Permian Basin and 28 rigs in the Anadarko Basin, “and we expect this level to continue.” North American natural gas production fell 5% year/year “as we chose not to drill any dry gas wells during the first quarter…However, we’ve already incorporated these deferrals and declines into our plans and we remain on track to achieve our full year guidance of 3-5%.”
About three years ago, Farris said, “we set out to expand our portfolio in areas that we believed could generate profitable growth. With this goal in mind, we significantly strengthened our onshore North American asset base through acquisitions in the Permian, Anadarko and Western Canadian Sedimentary Basin. We also entered the deepwater Gulf of Mexico and added tactical extensions to our Gulf of Mexico shelf, North Sea, and Egyptian asset base.”
Since its portfolio revamp, Apache’s output has grown by almost 200,000 boe/d, “with 162,000 boe/d, about 82%, coming from North American onshore.” With a strong portfolio now in place, Apache management now is evaluating the assets to determine which to keep and which to sell. About $4 billion worth on a long list of possibilities are expected to go to market this year, said Farris.
The determining factor as to what would be sold is based on the rate of return, cash flow, as well as long- and short-term growth, he told analysts. The highest costs are overseas and in the deepwater, but he couldn’t be pinned down on any specific sales.
However, it appears to be clear from the latest results that North America’s onshore portfolio will remain intact. Worldwide, Apache’s total output averaged 781,00 boe/d in 1Q2013, with liquids comprising 53%.
Consider how much the North American onshore is contributing to Apache’s bottom line: total global revenues, the bellwether for any business, were $4.2 billion in 1Q2013, with North American natural gas liquids (NGL) accounting for more than one-third at $1.5 billion (37%). North American natural gas also provided 11%, or $5 million, to revenues.
Nearly all (90%) of the wells drilled from January through March were in North America, or 355 out of a total of 455 worldwide, COO Rod Eichler told analysts. Onshore operations in the United States and Canada accounted for 44% of total global production, with the Permian contributing 15%, Canada 14%, Central operations 11% and Gulf Coast onshore adding 4%. The Gulf of Mexico (GOM) Shelf provided 12%, and the deepwater GOM contributed 2%.
The Permian and Central region output were the workhorses, together contributing 206,000 boe/d in 1Q2013, or more than 25% of Apache’s total output worldwide. Combined liquids production, which represented about 31% of Apache’s total, rose sequentially in the plays by about 9% (10,000 b/d) to 129,000 b/d. No wells were drilled in the Mississippian Lime or Bakken Shale plays.
For some perspective on how strong Apache’s U.S. onshore was versus a year ago, Central and Permian region liquids output skyrocketed 148%; oil rose 40%. The Central operations had a 129% increase, while in the Permian, output was up 20% from the same period of 2012.
In fact, Permian production would have been higher except for the fact that unplanned facility downtime resulted in deferred output of about 3,000 boe/d, triple the amount from a year earlier, Eichler said. Apache averaged 37 rigs and drilled 147 net wells in the Permian between January and March.
In the Central region, Apache’s first core area dating back more than 50 years, production historically had grown through natural gas exploitation, but no more. In the past three years, an increase in horizontals from vertical wells, and the price disparity between crude oil and gas, led to a liquids-heavy shift.
Two years ago, Apache’s liquids output in the Central region jumped 115% from 2010. Last year oil output more than doubled and NGL production almost tripled, with the region contributing 8% of equivalent production and 9% of total proved reserves.
There’s no plan to reverse the liquids strategy, said Farris. Apache today is targeting liquids and oil in the Cottage Grove, Tonkawa, Granite Wash, Canyon Granite Wash and Cleveland formations, where liquids production tripled in 1Q2013 year/year, and rose 46% from 4Q2012. Twenty-five drilling rigs were running at the end of March; Apache had drilled 43 net wells in the first three months.
For instance, flow rates from the first seven wells drilled this year in the legacy Tonkawa oilfield in Oklahoma averaged 662 boe/d, a 70% increase year/year. The 30-day initial production rates averaged 428 b/d of crude oil, 103 b/d of NGLs and 789 MMcf/d of natural gas.
Natural gas, once Apache’s sole focus, accounted for 29% of total output worldwide. And even though there was no U.S. dry gas wells begun, production still rose to 95 MMcf/d from 73 MMcf/d. In Canada, however, infrastructure issues sent gas production down by more than 18% to 87 MMcf/d from 106 MMcf/d.
Natural gas, however, still remains a big target in Canada, said Farris. The operator has some of the biggest prospects in North America in the Liard Basin, Horn River and Montney shales. And there is the proposed joint venture with Chevron Corp. to consider, which includes plans to export liquefied natural gas from British Columbia near Kitimat.
However, Kitimat received scant attention during the conference call. The final investment decision hasn’t been made, and Farris gave no indication that it was coming anytime soon.
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