North American natural gas, which helped propel EnCana Corp. to huge profits last year, will continue to be the “primary focus” for the Calgary-based company, CEO Gwyn Morgan said last week. The company on Thursday reported 2003 earnings of US$2.36 billion ($4.92/share), up 183% from pro forma 2002.

Along with its strong production and earnings report, EnCana also announced a one-third increase to its quarterly dividend from C10 cents to US10 cents. Beginning this year, EnCana is reporting its earnings in U.S. dollars. Cash flow increased 67% from pro forma 2002 to $4.46 billion ($9.30/diluted share). In the fourth quarter, EnCana’s earnings increased 51% over the same period in 2002 to $426 million (91 cents/share).

Already, North American gas makes up about two-thirds of production, but within the next few years, it will rise to about 80%, Morgan said. Much of the producer’s success last year and going forward is seen in the United States, where EnCana had a 49% production increase in 2003. And, with much of that success tied to production in the U.S. Rocky Mountains, EnCana announced plans to build a large gas pipeline there (see related story).

Overall, the company reported daily oil, natural gas and natural gas liquids (NGL) sales volumes last year were up 9% from 2002, averaging 650,200 boe/d. Daily sales were comprised of about 2.57 Bcf of gas, up 8% over 2002, and 222,500 bbl/d of oil and NGLs, a 13% increase. Fourth quarter oil, natural gas and NGL sales averaged 713,900 boe/d, up 13% over the 632,700 boe/d reported in 4Q2002. Natural gas sales averaged 2.68 Bcf/d. Gas production was up 9% after adjusting for higher levels of withdrawal from storage in 4Q2002. Oil and NGL sales in the fourth quarter averaged 266,900 bbl/d, up 32% over 4Q2002.

Morgan, who presided over a conference call with investors and financial analysts on Thursday, acknowledged that EnCana, now the largest North American producer, was different from other independents. “We are aware we are a different kind of oil and gas company [and] why we can grow in North America while others can’t. After you have an understanding of how we do things, you see that we really understand resource strategy.” But, he noted, “at the end of the day, the more important thing is that we continue to deliver.”

EnCana’s different way of doing things involves the huge acreage base amassed by the creation of the company through the merger of Alberta Energy and PanCanadian Energy in early 2002. Rather than a resource risk, EnCana assumes an execution risk. With a large acreage holding with hard-to-reach, but known resources, EnCana sets its engineers to work to figure out how to get the gas out at least cost, and then uses that technology across the large holding.

EnCana’s Rockies play is a classic example, one analyst explained, where the return on individual wells may be small, but EnCana makes it pay by applying the same technology over multiple wells over extensive acreage.

“Both Alberta Energy and PanCanadian had huge amounts of land, the equivalent of a couple American states,” said one analyst. “We used to call PanCanadian the sleeping giant; it had so much land, all it had to do was roll over and do something with it. Now, as EnCana, they’re making it pay.” A large chunk of PanCanadian’s land came in the form of land grants for its old parent, which constructed the Canadian Pacific Railway.

EnCana’s reserve additions, “two for every bbl produced, clearly demonstrate the continuous, reliable drill bit growth available through relatively low risk, repeatable development drilling on our huge resource play dominated asset base,” said Morgan. “We added 1.7 Tcf of North American gas at a time when overall industry gas reserves and production growth is faltering. We have clearly identifiable captured resource potential on our existing land base which should allow similar organic reserves and production growth for years to come.”

EnCana’s 203% production replacement came almost entirely through the drill bit, adding 533 MMboe of proved reserves at a finding, development and acquisition cost of $8.75/boe. Operating and administrative costs were $4.11/boe, which was below the 2003 guidance range.

While EnCana had a blow-out success in the past year, Morgan cautioned that he did not see the company nor its peers as able to improve the future supply picture. North American gas supplies, he said, would be flat for at least the near term, adding that producers were “going to have to make do with flat supply at best” because of the volatile gas pricing environment.

The company also sees the possibility of a drop in the current “high level” of drilling because of manpower shortages. “There is the potential for a slow down in some areas,” Morgan said. EnCana drilled 1,517 net wells in the final quarter of last year, which included 1,306 development wells and 211 exploration wells.

EnCana’s 2003 success came from prolific resource plays in the U.S. Rockies, a new, high potential resource play at Cutbank Ridge in British Columbia, and extended shallow gas development in southern Alberta to include commercial production from coalbed methane (CBM). In 2003, the company drilled 5,632 net wells, about 13% more than forecast, which included 5,016 development wells and 616 exploration wells. EnCana currently has about 25 rigs running in the U.S. Rockies and about 100 rigs across Western Canada.

U.S. production averaged 588 MMcf/d last year, up 49% from pro forma 2002. Fourth quarter production averaged 654 MMcf/d, up 27% from the same period in 2002. Current U.S. production is averaging 675 MMcf/d.

“We’ve made strong progress during 2003 developing our two core properties, Jonah in Wyoming and Mamm Creek in Colorado, where production has increased approximately 50% in the past year,” said Roger Biemans, president of EnCana’s U.S. region. “In 2004, we look forward to the completion of the regulatory review of our infill drilling plans at Jonah, plus advancing the development of promising new resource plays in Colorado and Texas.”

EnCana ramped up production at the Greater Sierra resource play in 2003 by drilling 207 net wells in the area. Greater Sierra production exited 2003 at about 215 MMcf/d. Favorable changes in the B.C. government’s royalty regime for summer drilling and the province’s commitment to improve road infrastructure, combined with early winter drilling conditions in the fourth quarter, enabled EnCana to step up its development at Greater Sierra.

Construction of EnCana’s new Ekwan Pipeline started in December, and the 80-kilometer link to the Alberta gas transmission system has a planned capacity of more than 400 MMcf/d. With start-up planned during the second quarter of 2004, the Ekwan Pipeline is expected to facilitate continued sales growth from northeast B.C., where the company currently has about 32 rigs drilling.

On another front, EnCana plans to drill 300 CBM wells this year, taking production to about 30 MMcf/d by year-end 2004. Over the next five years, EnCana expects to increase natural gas production from coal seams to more than 200 MMcf/d. CBM production exited 2003 at about 10 MMcf/d.

For 2004, EnCana reiterated its forecast of 10% organic sales growth. Daily sales are forecast to range between 690,000 and 735,000 boe, comprised of sales of 2.7-2.85 Bcf/d and 240,000-260,000 bbl/d of oil and NGLs.

EnCana recently increased its oil sales guidance because of strong field performance and the acquisition of some interests in the North Sea. Natural gas sales guidance for 2004 remains the same because of expected modest well freeze-offs in January, sales of non-core properties and expected shut-ins due to regulatory rulings in the gas over bitumen issue in northeast Alberta.

“The end of 2003 was marked by an early freeze up that enabled us to advance our drilling programs, taking 2003 drilling to more than 5,600 net wells and giving us a jump on our 2004 program,” said Randy Eresman, COO. “Natural gas sales exited the year at about 2.7 Bcf/d, near the low end of our 2004 guidance. We have about 1,200 wells, approximately double our normal inventory, drilled across western North America that are awaiting tie in. Most of these wells are in southern Alberta.”

Eresman said that the tie-in work is planned following spring break-up, when additional rigs and crews from northern regions are expected to become available. “These well tie-ins, plus substantial field activity elsewhere in North America, are expected to continue to increase gas sales growth as we move through the year,” he said.

Following the earnings announcement, Thomas Driscoll, a Lehman Brothers analyst, wrote in a research note that “EnCana appears to have an excellent asset base and investment opportunities. However, we remain concerned it is spending too aggressively.”

He noted that in the fourth quarter, EnCana spent more than $450 million above its cash flow from continuing operations and bought back $186 million of common stock. “It funded these largely by issuing $526 million of debt and with $282 million of cash from the sale of non-core assets. While diverting asset sale proceeds into other upstream businesses, borrowing to fund drilling, and borrowing to buy back stock could benefit per share growth rates, it is not clear that these actions add to shareholder value.”

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