Devon Energy Corp. will drill more wells in North America's onshore this year than it originally planned, with an eye on discovering another emerging play, company executives said Tuesday.
CEO John Richels and his management team shared some of the company's operational plans on Tuesday in Calgary. In addition to its substantial North American portfolio, which is anchored by the Barnett Shale, the Oklahoma City-based independent quietly has been adding acreage in key basins around the United States. In early May the company disclosed that it has added 250,000 net acres in the prospective Tuscaloosa Marine Shale, which exploration chief Dave Hager said at the time "could be equal to the Eagle Ford" shale (see Shale Daily, May 5).
Devon also is attempting to amass "at least" 150,000 net acres in several other North American plays, said Richels. About 110,000 net acres already have been accumulated in Ohio's Utica Shale and 300,000 net acres have been added in Michigan's portion of the Utica play. In addition, around 300,000 net acres have been acquired in Wyoming's Niobrara Shale, 150,000 net acres in Oklahoma's Mississippian Lime play and 65,000 net acres in the Wolfberry Shale in Texas.
"We're pretty excited about what we have," said Richels.
If preliminary drilling tests indicate that some of the new portfolio additions are worth additional investments, Devon may look for new funding resources, including joint ventures. "We wouldn't be shy about looking for alternative ways to fund them either," said the CEO.
Devon is "just starting to drill wells" in the new plays, said Hager. "We have the opportunity to create a lot of value for the shareholders."
To that end Devon has boosted its 2011 capital spending plan by $1 billion to not only build its portfolio but also to accelerate operations in Canada and the Permian Basin and increase development in the Barnett and Cana-Woodford shales. The Oklahoma City-based independent now plans to spend between $5.5 billion and $5.9 billion to the end of the year, paid for by the $10 billion it earned last year by selling its selling its international holdings to BP plc and its Gulf of Mexico assets to Apache Corp. (see Daily GPI, April 13, 2010; March 12, 2010).
The twin deals should net Devon "at least" $7.7 billion, which "really exceeded everybody's expectations," Richels explained. Now the company is optimizing its returns by investing in operations and repurchasing stock. Through June 23 Devon had spent close to $2.4 billion to repurchase almost 33 million shares. A $3.5 billion buyback program is slated to be completed by the end of the year. The $1 billion in additional exploration spending includes $200 million to cover rising service costs, as well as $100 million to account for unexpected weakness in the U.S. dollar, said the CEO.
Devon last year revamped its long-range exploration and production (E&P) strategy to move from gas-weighted production to a more liquids base, which helped it to be ready for the new spending plans (see Shale Daily, Nov. 8, 2010). However, the company will keep its sights trained on boosting gas production as prices strengthen, Richels said.
"We have put together a tremendous opportunity portfolio in a number of locations...and we're trying to move that value forward," he told investors. About 20% of the increased capital budget will be devoted to E&P, up from earlier projections to spend about 14% of the budget on E&P.
Devon's success has put the company in the enviable position of being able to bolster its operations, something other onshore producers have been hesitant or unable to do, noted Hager. "We'll actually be drilling more wells than we originally had budgeted."
About $200 million of the augmented budget will be for three areas in Western Canada, where Devon has about four million acres to explore and develop. The company has only begun to determine the potential of its resources there; about 58 wells are to be drilled there by the end of the year, he said.
In the Permian Basin, Devon plans to spend $900 million to drill 310 wells in several oil- and liquids-rich plays, including the Wolfcamp Shale, which is "truly one of the hottest plays in the industry," said Hager. About $300 million will be used to extend drilling programs in the Barnett Shale and the Cana-Woodford Shale through the end of the year. About 375 wells now are to be drilled this year in the Barnett, versus 325 that originally were planned. In the Cana play, Devon plans to drill 225 wells this year, which is 25 more than it had forecast.
The producer, which built the Barnett Shale into the hottest of the red hot shales, hopes to find the next big play on its own, said Hager. There's a better value to discovering a play than by paying a premium to buy into an area already being worked, he explained.
If preliminary drilling tests indicate that some of the new portfolio additions are worth additional investments, Devon may look for new funding resources, including joint ventures. "We wouldn't be shy about looking for alternative ways to fund them either," said Richels.
Analyst Dave Heikkinen of Tudor, Pickering, Holt & Co. said in a note Wednesday the company was "doing the right thing by getting in early to several new plays at relatively low acreage costs," because "multiple shots on goal means high probability of a lay-up play (or lay-ups) that more than recoup the entry cost for all plays. But at this point, plays are still pretty rocks and no idea yet which will turn into gems. For the stock to outperform, activity/scalability will need to be outlined..." Devon has "five-plus potentially strong plays but how quickly/big can they grow in each and how much will that move the total company needle?...
"We like the info but at this point want development plans and well results to value," said Heikkinen. Results are "coming to us this year with Niobrara wells spudding 3Q2011, Mississippian Lime spudding now, Utica horizontals planned in both Ohio and Michigan later this year and one vertical core well drilling now to evaluate the Tuscaloosa Marine Shale."