With a trio of solid results from unconventional natural gas plays in Cutbank Ridge, Jonah and East Texas — and coalbed methane (CBM) joining in — EnCana Corp. delivered a chorus of good news for both its earnings and production in the final three months of 2007.

The Calgary-based producer reported Thursday that its net income rose 63% to US$1.08 billion ($1.43/share), compared with $663 million (82 cents) in 4Q2006. Operating earnings, which exclude special items, rose to $1.33/share from 80 cents. Revenue climbed 58% to $5.8 billion. Wall Street analysts had forecast earnings would average $1.31/share in 4Q2007.

Production-wise, EnCana boasted a 9% hike to its 4Q2007 gas output, averaging 3.7 Bcf/d compared with the same period a year ago. Oil and natural gas liquids output rose 4%, averaging 136,000 bbl/d. For the year, the independent’s total gas output climbed 6% to average 3.6 Bcf/d — roughly twice the original forecast — mostly on strong performance from its Jonah play in Wyoming and a growing asset base in East Texas. Gas production last year was led by a 14% increase in U.S. production.

“Our gas development programs added over 900 MMcf/d of new production, offsetting average annual declines of about 22% and providing the incremental growth,” said CEO Randy Eresman, who led a conference call with financial analysts Thursday. “We expect about 90 natural gas reserves plays will continue to lead our production growth in 2008, in which they are forecasted to grow by approximately 12%. While all of our key resource plays have performed well, those in Texas, British Columbia, and Wyoming are expected to contribute the majority of our year-over-year growth in 2008. We are excited about the performance we’ve seen this past year and the future potential of regions such as Amoruso, Cutbank and Jonah.”

EnCana’s energy resources cover more than 25 million net acres of land in North America, and last year its U.S. gas production represented about 40% of the total gas portfolio, a share that is expected to increase to almost 45% in 2008, Eresman said.

Gas output from EnCana’s key resource plays overall climbed 14% in 2007 to 2.7 Bcf/d, up from 2.4 Bcf/d in 2006. The biggest gains came from its East Texas operations, which reported a 44% jump in gas output. Fort Worth Basin operations, centered in the Barnett Shale, rose 23%; Jonah output in Wyoming climbed 20%. EnCana also benefited from incremental production gains after building its stake in the Amoruso Field in the Deep Bossier in Texas (see NGI, Nov. 12, 2007).

“We have integrated the 3-D seismic program completed last year into our geologic model, successfully targeting a number of entrant wells so far this year,” Eresman said of the Amoruso play. “Initial production rates from these recent wells in Amoruso are currently exceeding our expectations with several individual wells testing at rates over 30 MMcf/d. In fact, our last 10 wells have averaged over 24 MMcf/d…”

EnCana’s total gas production in Canada rose 2% in 2007 from 2006. Cutbank Ridge in northeastern British Columbia led with a 38% gain to gas output. CBM production in central and southern Alberta jumped 34%, and Bighorn in west-central Alberta rose 31%.

For the year EnCana added 2.2 Tcf of proved gas reserves, led by output from the Cutbank Ridge, Jonah and Piceance basin plays. Finding and development (F&D) costs averaged $1.65/Mcfe; F&D costs for gas and associated liquids were around $2.40/Mcfe.

The industry overall was stymied by inflation across the service sector last year, but EnCana now has begun to see “some moderation in U.S. cost structures,” Eresman said. “We believe this has been partly driven by the impact of the credit crunch in the U.S. on smaller E&P [exploration and production] companies’ ability to access capital, resulting in reduced activity levels. In addition, we are benefiting from the steps we’ve taken across all of our programs, both in United States and Canada. These include reduced growing costs and increased efficiencies related to the fit-for-purpose rigs currently operating in our fleet and optimizing factoring and completion programs that have driven step changes in our cycle times for some of our plays.”

This year, he told analysts that the Calgary producer expects overall price inflation to “between zero and 5% in the United States and relatively flat in Canada, excluding the upstream portion of our integrated oil business, which we expect will be between 5% and 10%.”

However, “some of our plays in Alberta are becoming less competitive compared to early years and compared to the rest of our portfolio, particularly emerging gas plays and those affected by the proposed changes to the deep gas royalty program,” Eresman noted. “Despite relatively strong natural gas prices, we expect that the changes to the royalty regime will continue to negatively impact activity levels in Alberta.”

The province is readying changes to its royalty regime program, which are expected to take effect in 2009 (see NGI, Oct. 29, 2007).

The current rig utilization rates “continue to be very high in the United States, while at the same time are very low in Canada,” the CEO noted. “Corresponding to this difference in activity, we are moving some of the newer mobile rigs in our fleet out of Canada and into the U.S. to work on our projects there. Specifically in Alberta, we expect industry activity levels to fall off for the remainder of the year following completion of this winter’s growing season.”

Eresman said the move out of Alberta “will have a cascading impact on all industry-related activity in the province. While this should reduced some service costs, we continue to see cost increases in labor, steel, property taxes, and energy, which we believe will more than offset any benefits in the short-term. For EnCana, we’ll continue to evaluate various supply management initiatives.

“Due to the reduced level of industry activity in Alberta, we are seeing a number of positive indications that may allow us to make strategic commitments, leveraging the size and sustained activity level of our field operations. Longer-term, we believe that industry, the service sector, the Government of Alberta, and the people of Alberta will need to work together to reestablish the competitiveness of the development of Alberta’s conventional oil and natural gas resources. EnCana will play a constructive role towards that end.”

The producer’s commodity price risk management measures in 2007 resulted in realized gains of $1 billion after-tax, composed of a $1.1 billion after-tax gain on gas price and basis hedges and a $100 million after-tax loss on oil price hedges and other hedges. The producer has hedged about 1.9 billion Bcf/d of expected gas production from January to October 2008 at an average New York Mercantile Exchange (Nymex) price of $8.21/Mcfe.

This year the producer also has hedged 100% of its expected U.S. Rockies basis exposure using a combination of downstream transportation and basis hedges, including some hedges that are based on a percentage of Nymex prices. At the end of 2007, U.S. basis hedges, a combination of Rockies, Midcontinent and San Juan instruments, had an effective annual average differential of Nymex less $1.03/Mcf.

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