No more big unconventional plays out there, you say? Don't tell shale pioneer Devon Energy Corp., which on Wednesday validated the prospective Tuscaloosa Marine Shale, where it has leased 250,000 net acres for $180/acre.
"We plan to drill the first two horizontal wells this year," said Dave Hager, who runs Devon's exploration and production (E&P) unit. He disclosed the company's entry into the frontier play during a quarterly earnings conference call with financial analysts.
"The play could be equal to the Eagle Ford," he said.
The shale play in recent months has been eyed by some as a frontier unconventional play (see Shale Daily, April 29; Feb. 28), but BP plc and others have leased acreage for years.
Hager said he worked the Tuscaloosa Shale as a geophysicist 25 years ago and "at one time or another everybody was drilling there." However, only three or four horizontal wells have been completed to date -- and that was several years ago, he said.
"There hasn't been a lot of other leasing activity to date, which is the reason why we're excited to get such a strong position at such a low cost," Hager said.
Devon acquired its leasehold along the Louisiana/Mississippi border. The rock there is 200 to 400 feet thick, and Devon plans to use horizontal drilling and fracture stimulation to "enhance the productivity for oil," said the E&P chief.
"We like several things about this play," Hager explained. "It's a frontier play, and we don't want to characterize it as something else. We are leading the industry by taking a position here but there are things we like about the play that give us reason for encouragement."
The Tuscaloosa appears to be "the stratigraphic equivalent of Eagle Ford, but it's deeper...Vertical wells have been drilled in there, and we are getting in good porosity and permeability...
"A small number of horizontal wells were drilled there a couple, three years ago from 50 to 2,000 feet, but they tested up to 500 b/d from limited and minimally fracked [hydraulically fractured] wells.
"Having said that, it's very early on. In order to drill more horizontal wells, we'll need more data on fracks, the sands below, more on the phases and oil versus natural gas boundaries...There are risks associated with it, but it has encouraging qualities. If it's successful, it would create an awful lot of value."
Devon plans to put a rig in the play before the end of June. The first wells drilled have been "science wells," said Hager; later wells will be more efficient. "Eventually, we're thinking costs will be around the $12 million range for drilling and completion."
Louisiana officials said Monday they plan to hold public hearings as early as June about whether to approve Devon's drilling production unit near Ethel, LA, in East Feliciana Parish.
Devon's application indicates that the company believes the area could contain "multiple" pay zones," said Madhurendu Kumar, who directs the geological oil and gas division for the Louisiana Office of Conservation.
Many companies will be eyeing Devon's Tuscaloosa plans, but the frontier play is only one of many established unconventional holdings in the company's burgeoning portfolio. In fact, Hager said the "biggest potential" play for the Oklahoma City-based producer is the Niobrara Shale and the Mowry region of the Green River Basin of Wyoming.
The "new venture activities" have boosted Devon's exploration efforts this year, he said, and today "well over 90% of the upstream budget is for oil and liquids-rich opportunities..."
However, Devon has no plans to shelve its solid onshore natural gas opportunities.
"Inevitably, gas prices will recover and 'incentivize' drilling of dry gas plays," said Hager. Devon is able to put the gassy projects on hold for now because "the vast majority of the leases are held by production...
"In the meantime, we'll allocate our capital to oil and liquids to generate strong rates in the current environment."
Devon reported net earnings of $416 million (97 cents/share) for the first quarter, well below year-ago earnings of $1.2 billion ($2.67). The decrease was attributed mostly to hedging losses. Excluding the one-time items, Devon earned $575 million ($1.34/share).
Production from continuing operations averaged 629,000 boe/d in the first three months of this year, in spite of curtailments related to severe winter weather. Compared with the first quarter of 2010, Devon's North American onshore production increased 7%, exceeding "the top end of the company's guidance by 4,000 boe/d." Production results benefited from better-than-expected results from several core properties, including the Cana-Woodford and Barnett shales.
In aggregate, liquids production onshore averaged 207,000 b/d, which is 11% higher than in the year-ago quarter and 5% more than in the final quarter of 2010.
The Cana-Woodford play's output averaged a record 162 MMcfe/d in the latest period, which is 120% than a year ago. In the Permian Basin oil and natural gas liquids (NGL) production increased 17% year/year, with liquids accounting for nearly 75% of the 44,000 boe/d produced.
Meanwhile, the Barnett Shale's net output exceeded 1.2 Bcfe/d, including 43,000 b/d of liquids, in the first three months of this year, which was 11% higher year/year.
Although production increased, quarterly revenues from oil, gas and NGL sales declined 10% to $1.9 billion in the first quarter of 2011. Lower natural gas prices "more than offset" the increase in production, the company noted.
Devon's average realized natural gas price, before the impact of hedges, plunged 25% to $3.62/Mcf, versus $4.80 in 1Q2010. Average realized oil prices rose 5% to $70.85/bbl, and NGL prices were up 4% to $37.39.
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