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Devon Takes Sumitomo as Partner in Permian

August 6, 2012
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Devon Energy Corp. last week secured $1.4 billion from Japan's Sumitomo Corp. in exchange for a 30% stake in 650,000 net acres in the Permian Basin's Cline and Midland-Wolfcamp shales.

The news offset the company's 2Q2012 earnings report, which indicated profits were down sharply from a year ago on lower commodity prices.

Devon CEO John Richels, who has not been averse to taking partners to help pay for development costs, said earlier this year that the Cline Shale was a top candidate for a joint venture (see NGI, April 9).

"This transaction once again demonstrates the value embedded in our high-quality portfolio," said Richels. "This arrangement will materially enhance Devon's future returns and improve our capital efficiency. It will also further enhance our financial strength."

Sumitomo already is a substantial player in the United States, with investments in the exploration and midstream sectors, as well as emerging liquefied natural gas export projects (see NGI, May 21; May 14; Feb. 21, 2011; Sept. 6, 2010). Last year company officials indicated that they were looking for more partnerships in North America (see NGI, Aug. 1, 2011).

"For quite some time we have had a strong working relationship with Sumitomo and look forward to a mutually beneficial joint venture," said Richels.

The transaction is expected to close before the end of September. Sumitomo has agreed to invest $340 million in cash. Another $1.025 billion would be invested through a drilling carry, which would fund 70% of Devon's capital requirements. Devon said the arrangement would result in Sumitomo paying 79% of the overall drilling and completion costs over the carry period.

The partners now plan to drill about 40 gross wells through December. Based on the current work plan, the entire drilling carry by Sumitomo is expected to be realized by mid-2014, Devon said. Devon is serving as operator of the partnership and would be responsible for marketing all production from these plays into the North American market. The effective date of the transaction is Jan. 1, 2012.

Like many U.S. producers, Devon's quarterly earnings were pummeled in part by write-downs because of lower natural gas prices from a year ago. Devon reported net earnings of $477 million ($1.18/share) in 2Q2012, compared with $2.7 billion ($6.50) in the year-ago period. A one-time gain of $2.5 billion resulting from the sale of Brazilian assets enhanced the year-ago earnings, Devon said.

Excluding one-time items, which are typically excluded from financial analyst estimates, Devon earned $224 million (55 cents/share) in 2Q2012, well below Wall Street's estimates of 81 cents/share. Cash flow from operations totaled $1.4 billion.

Lifted by growth from the Permian Basin and the massive Canadian oilsands Jackfish project, oil output averaged 149,000 b/d in April through June, which was 26% higher than a year ago. Total oil, natural gas and natural gas liquids (NGL) production rose 3% from a year ago to average 679,00 boe/d, despite some maintenance issues at NGL processing facilities in the latest quarter.

"A number of production interruptions primarily related to natural gas processing facilities reduced the company's quarterly output by 16,000 boe/d," Devon said. "The most significant occurrence was maintenance downtime at Devon's Bridgeport facility in North Texas, which reduced natural gas liquids production by approximately 10,000 b/d in the quarter."

Because of the "low natural gas liquids price environment, the second quarter was an opportune time for plant maintenance activities. Other minor disruptions at third-party facilities in the Permian Basin, Midcontinent and Gulf Coast regions also contributed to the reduced volumes."

In spite of the turnaround issues, which Devon said had been resolved, company-wide production increased 3% year/year (y/y), led by activity in the Permian Basin. Oil activity in the basin jumped 24% y/y; oil output accounted for nearly 60% of the 59,000 boe/d produced.

Among the highlights in the quarter, 19 Bone Spring wells were brought online with initial production (IP) rates over 30 days averaging 680 boe/d. Net production from Jackfish 1 and 2 oilsands projects in Canada averaged a record 51,000 b/d, representing a 63% jump in oil production y/y. Six operated Granite Wash wells were brought online with IP rates averaging 1,270 boe/d. And net production from the Cana-Woodford Shale averaged 280 MMcfe, with liquids output, which accounts for 30% of total output, up 59% y/y.

Devon also has increased its leasehold in the Mississippian Lime formation by adding 400,000 net acres in Oklahoma, giving it a total of 545,000 net acres in the resource play.

In spite of the increased production from a year ago, quarterly revenues from oil, natural gas and natural gas liquids sales declined 26% because lower realized prices for all three products "more than offset the production increase," Devon said. However, cash settlements related to hedges increased revenues by $267 million or $4.33/boe.

Through the end of this year Devon has 128,000 b/d of oil protected at a weighted average floor price of $97/bbl, and about 1.7 Bcf/d of natural gas is protected at a weighted average floor price of $3.76/Mcf. These positions represent about 85% of forecasted oil production and "roughly" 65% of expected gas output for the rest of 2012.

Marketing and midstream operating profit was $68 million in 2Q2012, down almost half from the $148 million in year-ago period. Downtime related to a planned expansion at Devon's Gulf Coast Fractionators facility at Mont Belvieu, TX, and lower commodity prices led to the y/y decline. The expansion at the fractionator facility is now complete and operations have resumed

Lease operating expenses (LOE) totaled $513 million in 2Q2012. On a unit of production basis, LOE was $8.30/boe, about 2% higher than in 1Q2012 and 10% more than a year ago. Devon said the increase in costs reflected higher activity levels in oil-rich basins. "In general, oil projects are more expensive to produce and have higher operating costs than gas production."

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