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Challenge looms in Canada’s gas fields Operators face higher risks to sustain exports, as shipments to the United States drop compared to 2002 Gary Park Petroleum News Calgary correspondent
Canada’s natural gas exports to the United States have been lower every month this year compared with 2002 — a trend that sets the stage for the next era of development in Western Canada.
The latest National Energy Board statistics to the end of August show that shipments to the United States totaled 2.28 trillion cubic feet over eight months, down from 2.47 tcf over the same period of last year.
The U.S. Energy Information Administration has projected total exports for 2003 will slump to 3.37 tcf from 3.78 tcf in 2002, noting that “pipeline imports from Canada are down this year for the first time since 1986 and are projected to be 11 percent less than in 2002.”
But the export volumes are being camouflaged by returns, which climbed to C$17.88 billion for the January-August period from C$10.79 billion a year earlier as average prices over the eight months climbed to US$5.38 per million British thermal units from US$2.77.
The worrying trend is that Western Canadian produces are relying so heavily on low-cost shallow gas wells in southern Alberta and Saskatchewan. Companies no longer required to maintain 20 years of gas reserves Peter Tertzakian, chief energy economist for ARC Financial Corp., painted a picture of the challenges ahead in a late November presentation.
Now that E&P companies are no longer required by the National Energy Board to maintain 20 years of gas reserves that index has declined to eight years since 1989.
On the upside, that deregulation has allowed producers to be more sensitive to price signals, which means “better capital efficiency ... the faster you can get it out of the ground, the better your capital efficiency,” he said.
From 1996 to 2002, the number of wells in the mid-depth range of about 4,900 feet has fallen by about 70-80 percent in the Western Canada sedimentary basin, while the number of shallow wells to about 2,300 feet has soared by 175 percent, Tertzakian said.
Contrary to popular belief, Western Canada sedimentary basin production is actually growing by 2.5 percent a year, but maintaining that rate will require E&P companies to complete about 18,000 wells a year, up 50 percent from current levels, he said. Companies pushing to increase wells per section That in turn poses a new set of obstacles for operators who hope to push the average number of wells per section beyond 10, Tertzakian said, referring to environmental access, field capacity, equipment, manpower, availability of infrastructure and the markets.
On a more encouraging note, he said companies such as EnCana are moving cash flow from shallow plays into deeper and riskier plays, such as Cutbank Ridge in northeastern British Columbia.
If the industry advances in a fiscally rational manner, the average reserves per well — currently about 1.2 billion to 1.3 billion cubic feet in the Western Canada sedimentary basin — can be recaptured and should rise, Tertzakian said.
He said that pattern has already been established in the United States, where operators have moved from Oklahoma and Texas to the deepwater Gulf of Mexico, the Rockies, coalbed methane and tight gas.
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