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In Shift to Lower 48 Unconventionals, ConocoPhillips to Add Five Rigs by Year's End

With several major projects now complete, ConocoPhillips plans to shift its focus to unconventional production in the Lower 48, adding five rigs to form an eight-rig drilling program before the end of the year in an effort to get a jump start on production for 2017.

Despite the additional rigs, the largest independent in the country lowered its full-year guidance for capital expenditures (capex) from $5.5 billion to $5.2 billion. But Houston-based ConocoPhillips also raised its full-year production guidance to 1.56-1.57 million boe/d.

ConocoPhillips reported Thursday that it had safely completed major turnarounds in Alaska and Europe, and earlier this month achieved first production from the second train at its Australia Pacific Liquefied Natural Gas (APLNG) project in Australia (see Shale Daily, March 4, 2013). Third quarter production was 1.56 million boe/d, a 0.2% increase (3,000 boe/d) from 3Q2015. The company attributed the slight increase to growth from major projects, improved well performance and lower planned downtime.

"We continue to see some production resiliency in Lower 48 unconventionals, despite the fact that we've been running only three rigs for the majority of the year. We do expect more of a decline in the fourth quarter," Al Hirshberg, executive vice president for production, drilling and projects, said during a conference call to discuss 3Q2016 on Thursday.

"Now that APLNG Train 2 has started up, the major project capital roll off that we have been experiencing is essentially complete. We've been working to shift more of our capital spending to the Lower 48 unconventionals. We have already been able to secure drilling rigs and pressure pumping crews at attractive rates to maintain our low cost of supply. We expect this incremental drilling work to start ramping in November. This work will have no impact on 2016 volumes, but will give us a head start on our 2017 production."

ConocoPhillips holds a stake (37.5%) in APLNG, along with Origin Energy (37.5%) and Sinopec (25%).

During the Q&A session, Hirshberg said Lower 48 unconventional production totaled 259,000 boe/d in 3Q2016, a 1.1% decline from the 262,000 boe/d produced in 2Q2016 (see Shale Daily, Aug. 1). Broken down by play, third quarter production in the Eagle Ford Shale was 163,000 boe/d, a 4.7% decrease from the second quarter (171,000 boe/d), while production in the Bakken Shale also slipped 4.7%, from 64,000 boe/d in 2Q2016 to 61,000 boe/d in 3Q2016.

But production in the Permian Basin increased 61.5% -- from 13,000 boe/d in 2Q2016 to 21,000 boe/d in 3Q2016 -- which helped offset some of the losses. Hirshberg attributed the increase to "some very nice wells" in the company's China Draw and Red Hills operating areas in the Delaware Basin.

"The timing of our completions and our hookups, and our gas plant access, have driven some shift there and when some of the volumes have come on into the third quarter," Hirshberg said.

ConocoPhillips currently has two rigs deployed in the Eagle Ford and one in the Bakken. According to Hirshberg, the company has contracts to deploy three more rigs in the Bakken and two in the Eagle Ford before the end of the year.

"We will be looking to add rigs in our Permian acreage in 2017, but that's not part of this late 2016 effort," Hirshberg said. "In the Bakken, we've been fairly steady there, [making] progress in terms of recoveries and costs. Recently we've put a new completion design into place that we're going to talk more about in our Investor Day [on Nov. 10 in New York]. We're really pretty excited. That's part of why we are eager to get some rigs back to work in the Bakken.

"In the Eagle Ford, if you look at our cost of supply there, we've got such a huge segment that's got down in below $25, fully-burdened cost of supply, [and with] single well cost supply in the mid-teens. Who wouldn't want to go run more rigs there in the Eagle Ford? That's [why] we've got those extra rigs allocated in those two places right now."

ConocoPhillips said it was continuing to sell some of its assets.

Last year, the company announced plans to cut spending in the deepwater Gulf of Mexico (GOM) and sell its North Cook Inlet Field and one-third interest in the Beluga River Field in Alaska (see Daily GPI, July 29, 2015; July 17, 2015). On Thursday, ConocoPhillips said it has signed sale and purchase agreements for exploration blocks offshore Senegal and for Block B in Indonesia. The company hopes to close both sales before the end of the year.

"We've been pretty active in managing the portfolio," CFO Don Wallette said during Thursday's call. "Through 2015 we have generated about $16 billion in asset sales. With the falling price and the soft market, we backed off and said we had done most of the strategic things we wanted to do...

"As prices recover we will continue to look at the portfolio for opportunities. We get a little more interested in asset sales in a recovering market than the one we've been in the last couple of years."

Last February, ConocoPhillips cut its quarterly dividend for the first time in at least 25 years, from 74 to 25 cents/share (see Shale Daily, Feb. 4). It kept the quarterly dividend unchanged in an announcement on Oct. 6.

ConocoPhillips recorded a net loss of $1.04 billion (minus 84 cents/share) for 3Q2016, compared to a net loss of $1.07 billion (minus 87 cents/share) in 3Q2015. Excluding special items -- specifically, a tax functional currency change at APLNG, restructuring costs across the company's portfolio, the termination of a rig contract for a deepwater GOM drillship and a deferred tax benefit from a change in UK tax law -- adjusted earnings in 3Q2016 were a net loss of $826 million (minus 66 cents/share), compared to an adjusted net loss of $466 million (minus 38 cents/share) in 3Q2015.

Stay up to date on 3Q16 earnings and projections for the remainder of the year with NGI's Earnings Call and Coverage sheet.

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