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Devon Looks to Share the Wealth in Lower Tertiary

Devon Energy Corp.'s North American quarterly natural gas output jumped nearly 10% from a year ago after surpassing production records in the Barnett Shale in Texas and the Powder River Basin in Wyoming, the company said Wednesday. However, to ensure it has adequate funding for its near-term, onshore projects, the producer wants to find a partner to share expenses for its longer-term projects in the deepwater Gulf of Mexico (GOM).

The Oklahoma City-based independent, like its peers, saw its 1Q2009 earnings impacted by ceiling test write-downs -- all noncash -- on the value of its natural gas and oil reserves. The ceiling test charges, based on the value of Devon's assets at the end of 2008, resulted in a $4.2 billion loss in 1Q2009. The charges were almost entirely the result of deteriorating U.S. natural gas prices, CFO John Richels told energy analysts during a conference call. Devon is about 75% weighted to gas. In total net quarterly losses were $3.96 billion (minus $8.92/share), compared with income of $749 million ($1.66) in 1Q2008. Revenue fell 32% to $2.03 billion. Excluding one-time charges, Devon earned $216 million (48 cents/share) in the first three months of 2009.

"Looking ahead, we see lower commodity prices through 2009. It's been our view for some time," CEO J. Larry Nichols said. "We reduced our rig count in the first quarter, but we increased production from the carry-over from a robust 2008. I'm confident the lower activity will correct gas supplies in the U.S., and costs will decline further." He said it would take time for the full effects of lower drilling to impact gas supplies, but at this time, "almost all domestic gas production drilling is subeconomic."

Until gas and oil prices strengthen, Devon "will continue to execute its strategy and decrease its activity over North America," Nichols said. "We want to continue to advance our longer-term developments, like Jackfish [an oilsands project in Canada] and the Lower Tertiary in the Gulf of Mexico, but we want to maintain strong liquidity until we see signs of a recovery in the hydrocarbon markets."

Deepwater costs are eating into Devon's budget, and possible production is years away, said Nichols. Total capital expenditures this year are set at $3.5-4.1 billion, but "more than a third" of the exploration funding is going to long-term projects, he said.

"We're a victim of our own success," Nichols said. To maintain its onshore development, which requires "near-term" funds, Devon hopes to secure a partner to help finance the offshore activity. "We think it's prudent to limit capital allocations to longer-term projects...the amount of capital required in the Lower Tertiary is going to be significantly large over the next few years."

As one of the biggest leaseholders in the Lower Tertiary, Devon has an enticing offer on the table (see NGI, Sept. 11, 2006). The producer jointly owns the St. Malo and Jack prospects with Chevron Corp. and StatoilHydro ASA. Earlier this month Chevron said work continues there on front-end engineering and design for a production facility in the Lower Tertiary that would have a capacity of between 120,000 boe/d and 150,000 boe/d (see NGI, May 4).

Relatively few wells had penetrated the Lower Tertiary until June 2002 with the Cascade discovery by Devon, BHP Billiton and Petrobras (see NGI, Aug. 21, 2006; June 10, 2002). Like the Jack and St. Malo discoveries, Cascade is located in the Walker Ridge area of the central GOM.

Four Lower Tertiary discoveries alone hold an estimated 900 MMboe of net resource to Devon, Nichols noted. "It's a very valuable package. We believe this package will have appeal to large companies around the world."

Devon doesn't want to sell any of its offshore holdings outright, he said. "We plan to maintain a meaningful interest in the play...I don't see us selling more than a 50% stake...We'll open the data room in the next several weeks to see what that generates. We're under no pressure to have a transaction, and we won't just sell" stakes to build capital.

Devon has enough liquidity, Nichols said, to ensure that ongoing onshore projects continue whether it finds an offshore partner or not.

In the Barnett Shale, where Devon is the largest producer, net output in the first three months of 2009 rose to an all-time high of 1.2 Bcfe/d. Output was 1% higher than in 4Q2008, and the increase came year/year even though there were only eight rigs running compared with 39 in 1Q2008.

Devon also broke a production record in the Powder River Basin, where production reached 114 MMcf/d. In addition, net output rose to 86 MMcfe/d in the Arkoma-Woodford Shale in eastern Oklahoma. In its emerging Cana-Woodford Shale play in western Oklahoma, Devon ramped up production from nine wells in 1Q2009 at an average initial production (IP) rate of 4.3 MMcf/d.

Devon achieved over-the-top IP rates from two wells in the promising Nan-Su-Gail Field, which is in East Texas. Neal B 14H, in which Devon holds a 93% stake, had an IP rate of 23 MMcf/d. The Hill 17H well, which is 100% owned by Devon, initiated production at 19 MMcf/d, the company said.

Low commodity prices have impacted Devon's drilling activity and its capital spending, the company noted. Devon drilled a total of only 451 wells in the first three months of 2009 versus 646 wells in the year-ago period. In the United States Devon drilled 301 wells, down from 381 in 1Q2008. In Canada Devon drilled 143 wells in the period, versus 249 a year earlier.

Still, Devon's combined gas, oil and natural gas liquids (NGL) production averaged 685,000 boe/d in 1Q2009, which was 7% higher than in the year-ago period. Total gas production in the first three months of 2009 -- almost entirely from onshore U.S. fields -- reached 2.72 MMcf/d, compared with 2.45 MMcf/d a year ago. Total oil equivalent output rose to 685 MMboe/d from 640 MMboe/d.

U.S. onshore production averaged 2.01 Bcf/d compared with 1.68 Bcf/d a year earlier. In the U.S. offshore, gas output declined to 119.4 MMcf/d from 201.2 MMcf/d. Canadian gas output was slightly higher in the period at 585.5 MMcf/d, compared with 567.4 MMcf/d in 1Q2008.

Devon's realized price for natural gas decreased by half from a year ago to average $3.73/Mcf. Average realized oil prices plunged 62% to $33.61/bbl from $88.23, and NGL prices reached $18.60/bbl from $47.40 in 1Q2008.

Exploration chief Dave Hager said companywide expenses have fallen 10-15% since the beginning of the year. Cost reductions vary by operating region, but for example, he said that in the Barnett Shale, in spite of long-term contracts, the company has been able to achieve 15-20% savings in well costs. Haynesville Shale wells, which were costing $10-11 million apiece, are now down to around $9 million.

"Companywide for the year we expect to see costs fall 10-20% on average as service companies respond to commodity prices," Hagar said.

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