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South from Canada ... and Alaska Mackenzie and North Slope gas vital to North America’s long-term supply Gary Park Petroleum News Calgary Correspondent
The question increasingly is how soon, not when, natural gas will start flowing from the Arctic — both the North Slope and the Mackenzie Delta.
The initial answer, as North America’s fast-evaporating supply surplus sets off a desperate scramble for solutions, is that the Delta has moved from a distant dream in the 1970s to a real prospect by the end of this decade.
But even with both basins pumping at projected initial volumes of better than 5 billion cubic feet per day they will fall far short of demand growth that could soar by as much as 18 bcf per day over the next decade.
Despite higher-than-expected injection rates in early June, U.S. storage levels are still lagging and fears about supply shortages remain elevated, propelling gas to the top of the energy agenda for the first time.
In a speech and testimony to a U.S. Congressional committee June 10, U.S. Federal Reserve chairman Alan Greenspan said North America will forever be condemned to a volatile and inefficient gas market unless it can secure “unlimited access to the vast world reserves” just as it has with oil.
That primarily means building more liquefied natural gas terminals to tap the huge supplies of Russia and the Middle East, he said. No short-term solution However, the depth of the challenge was explained to the same committee by Hal Kvisle, chief executive officer of the pipeline company TransCanada.
Short of destroying demand to solve the growing U.S. supply-demand imbalance, he said there is “virtually nothing that can be done to increase the supply of natural gas.”
“This is a multi-year process and big projects — whether it’s LNG importation or natural gas from the (Arctic) — take a long time. The mid-term market balancing mechanism will in fact be demand destruction.”
He said Alaska and Mackenzie Delta gas at the rate of 5 bcf per day and 7 bcf per day of LNG “are all required in the next decade if North America is to have acceptable gas prices” in the range of $4 per million British thermal units.
Kvisle said volumes from existing basins in the United States and Western Canada will contribute only another 5 bcf per day by 2012, while new oil sands projects in Alberta are expected to consume an extra 1.5 bcf per day — or roughly what is expected from the Mackenzie Delta.
He also strongly advocated the Alaska Highway pipeline route, describing it as the most economic, least risky and fastest option, while an “over-the-top” pipeline faces uncontrollable weather risks, technology and environmental issues, without offering any cost advantage. Council meeting called U.S. Energy Secretary Spencer Abraham held a June 26 meeting of the National Petroleum Council, his privately-funded advisory group, to speed up a comprehensive study that was originally due this fall. He asked incoming council chairman Bobby Shackouls, chief executive officer of Burlington Resources, to identify immediate steps that can be implemented this summer to ease short-term supply constraints.
Abraham said any prospect of weekly injection rates into storage above the average 60 bcf could be derailed by a hot summer.
“We already know that increased depletion rates and less productive new drilling have led to a projected 2 percent decrease in supply this year,” he said.
On another front, the chairmen of North America’s three energy agencies — Pat Wood of the U.S. Federal Energy Regulatory Commission, Ken Vollman of Canada’s National Energy Board and Dionisio Perez-Jacome of Mexico’s Comision Reguladora de Energia — have agreed to develop the most favorable regulatory environment possible to approve projects, including Arctic pipelines and liquefied natural gas development.
Vollman has warned the United States that it should not expect the Western Canada Sedimentary Basin to continue meeting 15 percent of U.S. demand if consumption rises from 22 trillion cubic feet a year to above 30 tcf, let alone the 23 percent projected by the Conference Board of Canada for 2025. Alberta gas in decline The sharpest wake-up call came June 2 when the Alberta Energy and Utilities Board said the province, which produces 70 percent of Canada’s gas, is into a period of “long-term decline” in production and reserves. (See related story in this issue’s gas section.)
It said the emphasis on drilling cheaper, shallow gas plays means Alberta will “not be able to sustain production levels” over the next 10 years. In fact, from 2004 to 2012, the regulator expects a 2 percent annual decline in output.
That weight of evidence has been reinforced in a report by FirstEnergy Capital analyst Martin King, who told clients that drilling and production results in Western Canada over the last six months have been “dreadful.”
“Given the limitations of the drilling fleet and the supply of capital within the basin, we believe that almost no amount of drilling can now be achieved to overcome steady natural gas production declines in the next few years,” he said.
FirstEnergy predicts initial well production declines will hit 24.8 percent this year and 25.5 percent in 2004, with overall output falling this year by 500 million cubic feet per day.
Under those circumstances, Vollman said relief is only possible from imported LNG, development of coalbed methane and new supplies from offshore regions and the Arctic.
With conventional supplies tightening, Greenspan has identified LNG as the best hope of all for closing the supply gap. LNG could rise to 10 percent of gas supply Lehman Brothers analyst Thomas Driscoll predicts LNG imports will rise from 1 percent of U.S. domestic supply to 5 percent in 2006 and possibly 10 percent in 2010.
By some estimates, LNG could boost supplies by 9 bcf per day over the next three years if some of the 18 U.S. projects now before regulators get the go-ahead.
Canada’s ability to come to the rescue is being widely downplayed.
“Canada, our major source of imported natural gas, has little room to expand shipments to the United States,” said Greenspan.
Kvisle said Canada is no longer able to meet half of all new U.S. demand, as it has done for a decade.
“Our industry is now running flat out,” he said, arguing that 10,000 wells a year won’t significantly boost production. “There’s not much more production increase available for export. We see production growth flattening.”
The American Gas Association said production in Canada can grow only if there is a regulatory regime in place for and producers more vigorously target drilling offshore Eastern Canada, the northern tier of the Yukon, the Northwest Territories and the Arctic Islands, where the Canadian Gas Potential Committee has estimated untapped resources at 80 tcf compared with the National Energy Board’s estimate of 175 tcf in the Arctic regions and 78 tcf offshore Newfoundland and Nova Scotia.
The American Gas Association made a strong case for the U.S. government to work closely with Canadian and Mexican officials to tackle the challenges of supplying North America by developing competitively priced gas in an environmentally sound manner.
Continued migration to new areas of supply growth is “absolutely critical,” the gas association report said.
J. David Hughes of the Canadian Geological Survey told a symposium earlier this year that U.S. demand for Canadian gas could climb to 5.7 tcf by 2025 from its current 3.7 tcf.
But he agreed with others in the industry who doubt that the Western Canada Sedimentary Basin can come anywhere close to meeting those needs.
“We’ve found and produced two-thirds of the (WCSB) reserve that it took 100,000 wells to discover,” he said. Only some 200 coalbed methane wells drilled in Canada On the coalbed methane front, Hughes said more than 200 wells have been drilled — a far cry from the 14,000 in the United States that produce 1.4 tcf a year and far from proving up bullish claims of 600 tcf in the coal seams of Alberta and British Columbia compared with 60 tcf in the United States.
“Meeting the potential of CBM in Canada will be a major challenge,” he said. “There are big numbers, but the only numbers that count are the numbers than can be produced.”
Hughes suggested the best hope for major reserve gains lies in the deeper, costlier plays of northern British Columbia and Alberta, but “we keep waiting for a big response from industry to those areas and it hasn’t happened yet.”
For the near-term, the industry is counting heavily on British Columbia, where the government hopes its sweeping royalty reforms will trigger a 20 percent hike in activity over the next couple of years from annual current spending of C$4 billion-$5 billion.
The province has targeted a doubling of gas production by 2008 from its current 900 bcf a year — one of the few prospects of holding the line on production as the East Coast offshore flounders and Alberta tries to shake off a “flattening” trend. Canadian Arctic beckons Amidst these intensifying supply-and-demand pressures, the Canadian Arctic beckons, especially following a June 18 deal by the Mackenzie Delta Producers Group, TransCanada and the Aboriginal Pipeline Group in the Northwest Territories that allowed the producers to file their preliminary information package with regulators.
If final applications are filed in 2004 and approvals are received within the expected time-frame of 24 to 30 months, gas could be flowing from the delta between 2008 and 2010 at 800 million to 1.2 bcf per day, with the option of using additional compression to boost volumes to 1.9 bcf per day.
For TransCanada, Arctic gas represents vital supplies to fill spare capacity on its mainline system based on company projections that sometime between 2009 and 2027 its mainline to Eastern Canada with links to the United States will be operating at 50 percent of current capacity of 7.3 billion cubic feet per day as resources in the Western Canada Sedimentary Basin shrink.
But Kvisle cautioned there are still “literally dozens of regulatory agencies and you tend to get tied up in this rigor mortis of the regulatory process where nothing goes ahead,” with the constant threat that a single objection or intervention could push the process back to the starting point.
Despite efforts by Indian and Northern Affairs Minister Robert Nault to streamline that approvals process, Kvisle said the process in Canada remains so “long and painful” that no-one should assume “we can get this thing approved quickly.”
On the importance of developing delta gas, Kvisle believes “very strongly that North America needs a secure energy supply.” Financing deal still needed However, his hopes of an agreement “any day now,” echoing earlier optimism by Nault and aboriginal leaders, remains entangled in the efforts to achieve common ground on a financing deal between the Aboriginal Pipeline Group and TransCanada.
Meanwhile, combined with the apparent growing lead by the Mackenzie project, the contentious prospect of tax credits to encourage construction of an Alaska Highway pipeline is being downplayed.
There is still anxiety that a heavily-subsidized North Slope project could derail the Mackenzie Delta, but Nault has lobbied U.S. legislators and the Bush administration to join Canada in a cooperative effort to speed up both projects.
To that end, he said loan guarantees or accelerated depreciation of capital for the Alaska Highway scheme would be acceptable.
He agrees with Abraham, who told a press conference May 15 that the White House wants a pipeline from Alaska.
“We are not unwilling to discuss various mechanisms (such as loan guarantees) to get it built. But the price floor method is not the way to go,” Abraham declared.
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