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Providing coverage of Alaska and northern Canada's oil and gas industry
March 2003

Vol. 8, No. 10 Week of March 09, 2003

North American natural gas takes a wild ride

Continental markets face grim times as storage levels slump to near all-time lows; focus again on hastening development of Arctic and offshore frontiers

Gary Park

PNA Canadian Correspondent

With North American natural gas prices surging to two-year highs in late February, ignited by bitterly cold weather in the Lower 48 that sapped volumes in storage, the fear factor is again stalking the industry.

On the New York Mercantile Exchange, the U.S. benchmark futures contract for March delivery rocketed to US$9.20 per million British thermal units on Feb. 24, while spot prices in Ontario hit C$21.92 (US$14.69) per gigajoule (0.9482 British thermal units) before easing back to C$9.70 entering March.

The Canadian Energy Research Institute expects prices to remain closer to C$6.50 (US$4.35) per gigajoule through 2003, as demand outpaces supply growth.

Inventories have been drawn down almost to record lows, with some analysts predicting a mere 500 billion cubic feet in storage by the end of March, and gas drilling remains sluggish in the United States — a volatile combination that spells a jump in consumer bills later this year.

No demand growth

All of this is happening despite an absence of demand growth while the U.S. economy struggles to get back on its feet.

“There is the potential for crisis by next winter, or earlier,” said Peter Linder, senior market strategist for DeltaOne Energy Fund, who was among the first to set off the alarm bells last fall.

Matt Janisch, an analyst with BMO Nesbitt Burns, told the firm’s global resources conference Feb. 26, that achieving minimum storage levels by next winter requires a staggering 4 billion cubic feet per day of reduced consumption by residential and industrial users.

“This is a fear-driven market,” said Martin King, an analyst with FirstEnergy Capital Corp.

What the outlook does is intensify the spotlight on Canada’s Mackenzie Delta for the near-term and Alaska’s North Slope over the longer-term.

Tim Hearn, chief executive officer of Imperial Oil Ltd., Canada’s largest integrated oil company and the lead player in the Mackenzie project, told a media briefing Feb. 25 that he does not expect gas prices to remain at peak levels, nor is Mackenzie decision-making tied to such pricing volatility.

But he said Imperial will “push as hard as we possibly can” to move ahead with the first project to deliver gas from the Canadian Arctic to southern markets.

Financing delays defer filing

Delays in securing financing for the Aboriginal Pipeline Group prevented the filing of a “preliminary information package” with regulators last year, although 2008 is still viewed as a possible start-up date.

If the proposed Mackenzie Valley pipeline operates to its initial pipeline design, volumes could include 1.2 billion cubic feet per day from the Delta producers and another 500 million cubic feet per day to fill the aboriginal portion.

For now, there are no other projects on the horizon in Canada that offer incremental growth on such a scale, which is a troubling outlook if Canada is to continuing meeting about 16 percent of U.S. demand.

A Feb. 12 report by Lehman Brothers analysts Thomas Driscoll and Philip Skolnick said Canadian output was down 0.2 percent in 2002 and Western Canadian production dropped an estimated 2 percent in January from a year earlier.

“As the industry continues to struggle to maintain production levels in Western Canada, we estimate that total Canadian natural gas production will fall another 2 percent-4 percent in 2003,” they said. “This should be bullish for North American natural gas prices.”

Lower 48 production down

A survey of 37 leading producers by Raymond James & Associates showed Lower 48 production fell in 2002 by 6.4 percent, year-over-year.

The one shred of hope has been the aggressive winter drilling program, with the Canadian Association of Oilwell Drilling Contractors estimating that 90 percent of its 667 available rigs were active in February.

Industry records show a record 2,147 wells were spudded across Canada in January — up 25 percent from a year ago and 63 wells ahead of the January 2001 benchmark – with close to 70 percent chasing gas prospects.

Even so, Roger Soucy, president of the Petroleum Services Association of Canada, said there is a tough road ahead to translate drilling into significant new volumes.

He said Feb. 26 that the potential for new gas discoveries has shrunk and the finds are smaller.

The same prognosis is contained in a new study by Purvin & Gertz Inc., which said new fields in the United States and Canada are depleting by 25 percent a year.

It said that because of the smaller discoveries in existing basins, prices are unlikely to fall below $4 per million British thermal units for the next two years.

The hope for a turnaround rests heavily on an acceleration of projects in the Arctic, offshore Atlantic Canada and the U.S. Gulf Coast, plus development of liquefied natural gas and coalbed methane.

Purvin & Gertz forecasts that:

• Alberta, the dominant Canadian supply source for 50 years, has likely peaked at 13.7 billion cubic feet per day, with CBM being the best hope to sustain that output level.

• British Columbia could grow significantly from its 2.6 billion cubic feet per day if the hopes of large finds in the northeast are realized, but Saskatchewan is expected to level off at 600 million cubic feet per day.

• Fort Liard, in the lower Northwest Territories, could double volumes over the next 15 years to 300 million cubic feet per day, but the Mackenzie Delta/Beaufort Sea is the best bet for big gains, just as Alaska is the U.S. ace-in-the-hole.

Nova Scotia setback

In Canada, the biggest setback has occurred in offshore Nova Scotia, where EnCana Corp. has called an indefinite “time out” for its Deep Panuke project, that was once expected to come on stream in late 2005 at 400 million cubic feet per day, the bulk destined for the U.S. Northeast.

Deep Panuke was to be Nova Scotia’s second producing field after Sable, which pumps at peak volumes of 550 million cubic feet per day to serve New England markets, but has itself been rocked by a 11 percent reserve write down by partner Shell Canada Ltd. and is expected to start declining earlier than anticipated.

The Lehman Brothers report, dated Feb. 12, said the negative reserve revision “could point towards potential longer-term difficulties of maintaining production from the East Coast.”

EnCana said last month the economics of developing estimated recoverable reserves of 935 billion cubic feet make no sense.

The National Energy Board and Canada-Nova Scotia Offshore Petroleum Board agreed Feb. 26 to suspend the public review process, asking for an update by Dec. 10.

EnCana chief executive officer Gwyn Morgan said major new discoveries boosting reserves to 1.4 trillion cubic feet would “help a lot” to make the C$1.2 billion project viable, along with possibly tying Deep Panuke gas into the Sable delivery system and obtaining concessions from the Nova Scotia and Canadian governments.

“We hope we don’t drop dead,” he said. “We’re trying to find a way of not doing that.”

But the hunt for new gas has hit a series of snags with a succession of wells failing to yield commercial finds and EnCana abandoning its first deepwater well in January.

Politicians and industry players keep pointing out that Nova Scotia is an underexplored basin that will need patience. Some analysts take the view that unless some of the 10 exploration wells planned for this year hit pay dirt, E&P companies will take their money elsewhere.

A first quarter review by FirstEnergy predicts gas prices will average $4.50 per million British thermal units at the New York Mercantile Exchange this year, compared with $3.36 in 2006.

It said a drilling surge in Canada won’t be enough to improve supply performance in 2004 and 2005.

The rapid draw down of storage levels that originally seemed adequate for winter needs will pose a challenge to regain levels of 3 trillion cubic feet by November, FirstEnergy said.






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