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Arctic key as North America faces tightening natural gas supplies E&P companies play it cautiously after wild ride of 2000-2001; direct strong cash flows into paying down debt and rebuilding balance sheets rather than drilling Gary Park PNA Canadian Correspondent
The more the evidence piles up, the more it points to one verdict — the Arctic, on both sides of the U.S. and Canadian boundary, is an essential part of North America’s natural gas future.
But long before Arctic gas starts flowing to market, flagging production across the continent is setting off alarm bells, with analysts slashing their supply forecasts for this winter and beyond.
As production dwindles and producers keep a tight hold on their purse strings, there is a growing consensus that a supply shortfall is only weeks away, despite conservative demand growth expectations of 1.7 billion cubic feet per day.
Price forecasts vary Calgary-based FirstEnergy Capital Corp. expects marketable output for North America to decline by about 3.4 billion cubic feet per day this year, or about 15 percent of projected U.S. consumption, while demand is predicted to grow by 1.7 billion cubic feet per day this year and 1.5 billion cubic feet per day in 2003.
As a result it forecasts gas prices will be in the range of C$5 (US$3.20) per thousand cubic feet in the next three months and remain there through the next two years.
U.S. brokerage Salomon Smith Barney sees the New York Mercantile Exchange composite spot gas prices averaging US$3.50 per million British thermal units this winter.
In a more bullish assessment, Peter Linder, an analyst with DeltaOne Energy Fund in Calgary, said Oct. 24 he expects prices to range from C$4 (US$2.56) per thousand cubic feet, if there is a repeat of last winter’s temperatures to C$7 (US$4.48) in “normal to colder” temperatures, with an overall winter prediction of C$6 (US$3.84).
In its October Natural Gas Market Watch publication, the Calgary-based Canadian Energy Research Institute says high levels of gas storage — now at about 3.2 trillion cubic feet in the United States — and an expected mild winter will keep prices down during the heating season that runs through March.
“We are in better shape now than we were in 2000-2001,” said Matthew Foss, a senior economist at CERI. “Now there’s a large amount of gas in storage and forecasts call for a mild winter while that winter was cold.”
But analysts such as Linder, who is counting on a 5 percent rise in North American demand this winter and a 5 percent shortfall in supply, are adamant that prices will increase regardless of the weather, the rate of economic recovery or the depletion in gas storage levels.
Gas drilling lagging Gas drilling is lagging 20 to 30 percent behind last year in the United States and Canada because E&P companies are wary of repeating the dramatic rise and fall in prices in late 2000 and early 2001, while major discoveries are few and far between.
In addition, John Olson, chief investment officer at Sanders Morris Harris in New York, said Oct. 25 said U.S. gas pipelines can’t raise the equity or debt needed to expand pipeline grids because investors are unwilling to gamble on the stocks of companies whose debt has been downgraded in many cases.
The supply outlook in Canada, which meets 16 percent of U.S. demand, is especially grim as producers use the windfall from strong oil and gas prices to pay down debt and rebuild balance sheets rather than drilling holes.
As a result, capital spending as a percentage of cash flow, according to new figures from FirstEnergy Capital Corp. and the Canadian Association of Petroleum Producers, slumped to about 75 percent in the third quarter, from 89.7 percent for all of 2001 and from staggering 146 percent in 1998 and 123 percent in 1997.
Linder said that even if there is a ramp up in drilling into the winter it will be “too little, too late.”
High decline rates Senior producers are fighting high decline rates — calculated at up to 40 percent in the first year of production for new wells in Western Canada — and are finding it impossible to replace that decline through the drill bit, he said.
Linder said that Canada’s only hope for a significant improvement in supply is for major discoveries in the East Coast offshore — where this year’s results were bleak, with five of the six wells off Nova Scotia logged as failures — or the Arctic frontier.
The pressing need for development of Arctic resources, in both the North Slope and Mackenzie Delta/Beaufort Sea, is reflected in the stunning depletion of reserves in northeastern British Columbia’s Ladyfern field — hailed in 2000 as Canada’s most “prolific discovery” in 15 years and now heading for the minor leagues.
From 700 million cubic feet per day last year, accounting for all of Canada’s incremental production growth, it is now pumping about 400 million cubic feet per day and Linder predicts it will fall to 100 million cubic feet per day in 2003, with varying consequences for the partners in a production-sharing agreement — Murphy Oil Co. Ltd. and Anadarko Petroleum Corp. with a combined 48 percent interest, Canadian Natural Resources Ltd. 30 percent and EnCana Corp. 22 percent.
Money continues to pour into the region, spurred partly by EnCana’s possible 5 trillion-cubic-foot Greater Sierra find this year, although on a reduced scale from last year and counter to warnings from people such as Alan Markin, chairman of Canadian Natural, who has rated the chances of unlocking a second Ladyfern in the immediate are as “probably close to zero.”
Downward production general The picture is no brighter elsewhere in Western Canada’s conventional fields, where government and private sector forecasters have identified a sharp slowdown in productivity.
Natural Resources Canada reported that the growth rate in Western Canada’s “deliverability” dipped to 0.7 percent in 2001 from 2.1 percent in the late 1990s and was only achieved by drilling 1,000 wells a month compared with 300 wells a month in 1997.
FirstEnergy, in a summer report, predicted 2002 will “represent a watershed year for Canadian natural gas production and 2003, with less Ladyfern production and less production elsewhere in Western Canada, will bring about the largest decline in marketable gas production of 4-5 percent (600-800 million cubic feet per day) seen in the past 20 years.”
Thomas Driscoll of Lehman Bros., in an updated forecast Oct. 17, issued a “conservative” forecast that Canadian gas production will decline by 2 percent in 2003 and remain unchanged in 2004, compared with previous estimates of 5 percent and 7 percent growth, respectively.
On the supply side, anxious investors, having delivered a stinging rebuke to Talisman Energy Inc. after Oct. 8 when it said its 2003 oil and gas production could miss the mark by 10 percent, are now waiting to find out if Canada’s other key producers face a similar plight.
Attention has shifted to EnCana and Canadian Natural, which will release third-quarter results on Nov. 5 and 6, respectively.
EnCana drilling down compared to predecessor companies The wisdom among analysts is that EnCana, despite its Ladyfern interest, has enough strength and diversification in its North American gas properties to keep investors onside.
But Linder is not counting on more than minimal growth through the drill bit for EnCana, North America’s largest independent gas producer, a view reinforced by Calgary-based investment dealer Peters & Co., which has noted that EnCana drilled 1,600 wells to the end of August, compared with more than 3,000 wells in both 2000 and 2001 by its predecessor companies, Alberta Energy Co. Ltd. and PanCanadian Petroleum Ltd.
Even so, Peters is confident that the industry’s 2003 budgets will shift from debt repayment to stepped up drilling, including shallow gas targets in Western Canada. CEO of EOG Resources says gas production will be down Among the U.S.-based companies which have invested heavily in Canadian gas assets over the last three years, EOG Resources Inc. has raised hopes that even the heavily exploited shallow plays of southern Alberta and Saskatchewan are not without hope.
The Houston-based company reported on Oct. 22 that its third-quarter Canadian gas output, concentrated in those regions, rose to 152 million cubic feet per day from 124 million cubic feet per day a year earlier.
Mark Pap, chairman chief executive officer of Houston-based EOG, said Oct. 22 that U.S. trends point to a “very substantial decline” in gas production in the range of 5-6 percent this year and 2-4 percent in 2003.
“Because of this decrease and a likely decline in Canadian import availability, we foresee a supply constrained environment resulting in higher prices in 2003,” he said.
Although off the radar screen, those looking for new hotspots in Canada are turning their attention to northwestern Alberta, where Alliance Pipeline Ltd. has said customers on its two-year-old export line from British Columbia to Chicago are seeking added service.
In applications filed with the National Energy Board, Alliance wants to build a lateral with capacity of 300 million cubic feet per day from the Fox Creek area and an increase in take-away capacity from a Devon Canada processing plant to 345 million from 65 million cubic feet per day.
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