Low natural gas prices led EnCana Corp. to curtail or shut in about 500 MMcf/d of its North American production in 3Q2009, but the producer is forecasting a price "correction" in the coming year, CEO Randy Eresman said last week.
The lost volumes, which contributed to a 9% decline in gas output in the quarter from a year ago, are to be brought back online over the next few months, Eresman told financial analysts during a conference call to discuss quarterly earnings.
EnCana shut in the gas volumes "when the prices we were exposed to were generally in the $3 [per Mcf] range, and our plan right now is to start bringing them back on stream, and they will be brought back on stream over the course of this winter," he said. "Our expectation is that there will be some form of correction in prices of next year, but the price we're currently seeing...above the $5 range [in the futures strip] are adequate."
EnCana's long-term forecast for North American gas is $6.50/Mcf, he noted. The company's gas prices averaged $3.44/MMBtu on the New York Mercantile Exchange in 3Q2009, which was 62% lower than prices in 3Q2008. Benchmark oil prices averaged $68.24/bbl, down 42% from a year ago.
With a leasehold position in many of the leading onshore gas basins across the continent, EnCana is "very well positioned" even if there is a "gas glut," Eresman said, referring to a scenario recently forecast by the International Energy Agency (see related story).
"We do expect..natural gas to be in abundance for a very long time. The question remains as to how much incremental demand is created in North America. We and others have determined that the supply of natural gas in North America at the current production rate appears to be 100 years in length. That's a very long time...and with the gas available growing using today's technology, as technology grows, gas abundance could be higher...
"We believe strongly that natural gas has a role to play in increased demand in North America through a greater use for power generation, and the opportunity to displace gasoline and diesel in the transportation sector...The question is, how much...gas is taken up? That will determine the growth in gas demand."
One natural gas asset that EnCana intends to keep is its Deep Panuke gas field offshore Nova Scotia, at least for the time being, Eresman said. The East Coast field, which has been in development for several years, finally is expected to ramp up production late next year or in early 2011. Deep Panuke is one of the few assets in EnCana's portfolio that isn't onshore shale or tight gas, and the company has fielded rumors about its possible sale for years.
"On the Deep Panuke project, we've always expressed it as being dissimilar from all of the other projects that EnCana has been pursuing over the last number of years, our unconventional gas strategy, but we have not been actively pursuing the sale of the assets," Eresman said. "We're comfortable keeping it in our portfolio as it is approaching production," he said. However, "...if the situation was right, we would consider selling it as well."
A healthy $220 million is set aside for development of the project in 2010. And even at today's gas prices, Deep Panuke is economically viable, said Mike Graham, who runs EnCana's Canadian operations.
"When you look at sort of Deep Panuke on a go-forward basis, it is definitely economic in today's gas prices, if you will, and that's based on sort of our $6.50/Mcf long-term price," said Graham. "We see Panuke as very economic at this point."
EnCana's total gas and oil production in 3Q2009 was about 4.4 Bcfe/d, down 7% from a year ago. Gas production fell 9% to 3.6 Bcf/d, but oil and natural gas liquids (NGL) production increased 4% to 139,000 b/d, led by a 44% production increase from the Foster Creek enhanced oil project in Canada.
Planning is on track to split EnCana into two independent companies: a pure-play natural gas company, EnCana, and an integrated oil company, Cenovus Energy Inc. (see NGI, Sept. 14). A shareholders' meeting to vote on the proposed transaction is scheduled for Nov. 25, and if the majority vote in favor of the split, the transaction is expected to be completed by Nov. 30.
Based on its expectations that Cenovus will split from EnCana, the management team developed preliminary 2010 capital budgets for the separate companies.
"While there are definite signs of a worldwide economic recovery, the commodity and financial markets continue to experience some degree of uncertainty," Eresman said. "In order to make it easier for the individual executive teams to respond quickly to changing economic and investment circumstances, a high level of flexibility has been built into each company's budget."
EnCana CFO Brian Ferguson, who has been tapped to lead Cenovus, said about 40% of his company's 2010 capital spending, set at $2-2.3 billion, will be "directed to building productive capacity that will provide growth beyond 2010."
EnCana, which Eresman would continue to helm, capital expenditures (capex) is set at $3.6-3.9 billion for the coming year. Based on those spending levels, North American gas output is forecast to jump "about 10%" from 2009, he said.
"Major investments are aimed at the company's large, early stage opportunities in Haynesville and Horn River, as well as completion of the Deep Panuke project. Our budget is designed with the flexibility to adapt to changing economic conditions. Beyond what is currently planned, we have additional attractive investment opportunities that we may pursue if prices improve and market conditions warrant," he noted.
The EnCana USA Division would receive about half of the capex budget, $1.9 billion, with gas output in 2010 projected to jump about 16% from this year to 1.8 Bcf/d. Close to 40% of the U.S. spending is to be spent in the Haynesville Shale; average 2010 production from the play is expected to be about 240 MMcf/d net to EnCana.
About $1.6 billion would be spent in 2010 by EnCana's Canadian Division (currently the Canadian Foothills Division), but output would remain at 2009 levels, said Eresman. EnCana plans to work on "production infrastructure" in the Horn River Basin, the Deep Basin of Alberta, which includes Cutbank Ridge, the Montney formation and Bighorn resource plays, as well as its coalbed methane resource play and completion of the Deep Panuke project offshore Nova Scotia.
"The lack of production growth, despite those investments, can be attributed in part to dispositions in 2009 of noncore assets in the Canadian Division and price sensitive royalty rates in Alberta," said Eresman.
The Calgary-based producer's quarterly profits fell 99% to $25 million (3 cents/share) in 3Q2009 from $3.55 billion ($1.03) in 3Q2008. Cash flow reached $2.1 billion ($2.77/share) and operating earnings were $775 million ($1.03), down 26% and 46%, respectively, from a year ago. Commodity price hedges in 3Q2009 contributed $913 million ($1.22/share) in realized after-tax gains.
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