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Vol. 11, No. 13 Week of March 26, 2006
Providing coverage of Alaska and northern Canada's oil and gas industry

Canadian gas in trouble?

Gary Park

For Petroleum News

The loss of accessible, low-cost natural gas reserves combined with fast-rising finding and development costs are posing a threat to Canada’s natural gas sector.

Add this year’s slide in gas prices to the mix and what looked like a robust future only three months ago has turned sour.

The challenge is outlined in recent findings by Ziff Energy Group, which has predicted output from the Western Canada Sedimentary basin will shrink by 2.6 billion cubic feet per day to 14 bcf per day over the next decade.

Having previously reported that the full-cycle cost of replacing reserves in the basin was C$6.10 per thousand cubic feet in 2004 — double five years earlier — its message took on new meaning earlier this month when AECO/NGX spot prices and the near-month contract price stumbled close to C$6 per gigajoule (a thousand cubic feet equals 1.05 gigajoules).

The simple message from those trends is that producers will likely cut their budgets, Simon Mauger, manager of gas services at the Calgary-based energy consulting firm, told a Ziff seminar March 15.

And some have already moved in that direction, including industry giant EnCana and closely followed junior Anderson Energy.

F&D Western Canada basin costs C$17 per barrel

Ziff analysts now put finding and development costs in the Western Canada basin — the largest single component of gas-supply costs at 45 percent — at C$17 per barrel of oil equivalent compared with C$6 in 1995.

Although many producers have hiked their capital spending plans and service companies are churning out new equipment to handle the projected demand, EnCana rattled the industry in February when it slashed US$500 million from a capital budget of US$5.7 billion-$6 billion in response to the fast-rising costs of drilling rigs and support services.

Anderson, under the chairmanship of industry icon J.C. Anderson, announced March 17 that low gas prices and high rig rates had forced it to slash C$12 million from a C$70 million capital budget.

Fueling the mood of unease, gas-heavy Shiningbank Energy Income Fund overturned its earlier decision to hike its monthly cash distributions to 30 cents from 23 cents and lowered the payouts to 25 cents, blaming the current gas roller-coaster.

The fall in commodity prices is also a factor in a decision by privately held Profico Energy Management, Canada’s largest junior producer at 105 million cubic feet per day from its Saskatchewan properties, to cancel a sales process which had been expected to fetch a bid of about C$2 billion.

Anderson and Profico merit close attention because of the experience at their helms.

J.C. Anderson built his previous creation, Anderson Exploration, into Canada’s sixth largest independent producer over more than 30 years before selling out to Devon Energy for C$5.3 billion in 2001, then going back to his roots by launching a new junior E&P company.

Profico’s chief executive officer is Clayton Woitas, who was CEO at high-flying Renaissance Energy when it was acquired by Husky Energy for C$4.3 billion in 2000.

Mauger said the highest-cost supplies will get hit the hardest as prices turn down at some point.

Foothills, B.C. feeling cost crunch

Of the eight strategy areas Ziff has carved out of the Western Canada basin, two are feeling the cost crunch — the Foothills area, which extends down the spine of the Canadian Rockies has experienced cost escalation, with acquisition costs now slightly higher than F&D costs, while the British Columbia Plains is a victim of higher F&D costs, making it cheaper to buy than explore.

On the growth front, Ziff expects 2,500 to 3,000 coalbed methane wells annually in the Calgary-to-Edmonton corridor until 2014, while tight gas should double over the same period to 1.2 billion cubic feet per day.

Speaking to a Canadian Energy Research Institute conference, David Russum, a technical specialist with AJM Petroleum Consultants, echoed the theme that record drilling is unable to replace production.

He pointed the finger at insufficient spending on research into exploration and extraction methods to offset the risk-averse mood as F&D costs have climbed.

Russum estimates that Alberta, Canada’s energy powerhouse, could face a rapid decline in gas output from 14 bcf per day in 2000 to 9 bcf in 2020 and less than 6 bcf by 2024.

Just to hold the line on current output, Alberta would have to complete 17,000 conventional wells a year or 25,000 average Horseshoe Canyon wells, assuming base production is declining by 22 percent a year.

While conceding that price forecasts are difficult, Russum is in no doubt that activity is driven by climbing prices, not shrinking production.

Russum noted that researchers have underscored the challenge facing Canada, where reserve replacement costs were C$19.09 per boe in 2005, compared with US$8.40 (about C$7.30 at current exchange rates) in 2002.

That puts Canada in an unfavorable light when staked up against other 2002 numbers of US$7.10 in the United States, US$6.50 in Europe, US$5.30 in South and Central America, US$3.10 in the Middle East and US$2.50 in Asia-Pacific.

He said other negatives in the Canadian gas industry include a focus on short-term results, a reluctance to take on risk, a hands-off approach by governments to developing an overall energy plan; Canada’s commitment to the North American Free Trade Agreement which requires it to keep U.S. exports and domestic consumption in proportion and the growing need for gas to extract oil, generate electricity and meet industrial order.

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LNG poses threat to Arctic gas pipelines

Just a handful of liquefied natural gas terminals could throw a wrench into the Alaska and Mackenzie Delta gas projects, a Calgary analyst warned.

Bill Gwozd, the Ziff Energy Group’s vice president of gas services, said five plants importing 1 billion cubic feet per day of LNG would match the combined output of the two northern schemes.

And delays would further imperil the two Arctic pipelines, which are already lagging several years behind their original timetables, he told a Ziff seminar.

Consistent with the concerns previously expressed by Imperial Oil executives, he said North American producers should be “very wary of the potential of LNG to overrun them.”

Depending on where the imports originated, he estimated that regasified LNG could reach the Gulf of Mexico for prices ranging from US$2.49 per thousand cubic feet to US$4.50, with the average price likely to be US$3.50.

Gwozd said LNG liquefaction costs for a 1 bcf per day terminal would be US$1 per thousand cubic feet, or lower, while regasification would cost about 50 cents.

The worry for Western Canada’s gas producers is that offshore gas could be delivered to North America for less than the cost of producing the gas on the continent.

However, Gwozd does not expect all of the LNG import terminals proposed for North America will be built, virtually ruling out the two facilities planned for the northern British Columbia coast because of the economics.

Ziff believes it is more likely LNG terminals in the works for eastern North America will go ahead to offset declining Western Canadian output, rising gas consumption in Alberta’s oil sands and higher demand in Ontario as that province’s coal-fired gas plants are phased out.

—Gary Park