|
Drag on Canadian gas Low production reflects low prices, exploration downturn; BC has only increases Gary Park For Petroleum News
The payback for an extended natural gas exploration slump that most observers think will stretch over at least another five years is showing up in Canadian production, both current and predicted, as producers across North America curb excess volumes pending a price recovery.
Statistics Canada, a federal agency, reported that marketable volumes dipped another 2 percent last year to 13.97 billion cubic feet per day for an accumulated decline of 16 percent from a peak 16.67 bcf per day in 2002.
Alberta took the major hit, ending 2010 at 10.39 bcf per day, down almost 1 bcf per day from April 2010 and 2.65 bcf per day from its record year in 2000. Only British Columbia bucked the national trend by posting a record 2.7 bcf per day in 2010.
Alberta claimed 73.25 percent of Canada’s output in 2010 compared 78.23 percent in 2007, while British Columbia, as it enters the shale gas age, picked up most of the decline to claim about 21 percent of the national share in 2010. Saskatchewan was third at 3.15 percent and Nova Scotia fourth at 2.22 percent.
For every percentage point shift, British Columbia’s gas revenues rise or fall by up to C$20 million a year.
The British Columbia government has forecast gas royalty revenue for the 2010-11 fiscal year, which ended March 31, of C$365 million on an average price of C$2.71 per gigajoule, barely half the original budget projection of C$698 million at C$4.29 per gigajoule.
The low-price challenge The challenge for industry and governments is to figure out ways of riding out the persistent low gas price as shale gas floods a market that is still struggling to emerge from the economic recession.
Gary Leach, executive director of the Small Explorers and Producers Association, said the downturn “illustrates to policy makers the volatility the industry itself grapples with and the important role governments can play in continuing to ensure a stable, attractive investment climate during a period of low gas prices.”
British Columbia has budgeted C$447 million in gas royalties for 2011-12 at an average C$3.02 per gigajoule, climbing over the following two years to C$597 million at C$3.60 per gigajoule and C$856 million at C$4.20 per gigajoule.
Leach said there are no “fast or easy solutions on the horizon” for Alberta’s shrinking gas royalties.
“Many gas-weighted producers, large and small, are attempting to re-balance their portfolios to more liquids and crude oil production, but that’s not easy to do for most players in Alberta’s large conventional gas industry,” he said.
Although the Alberta government predicts royalty revenues will edge up to C$1.7 billion in the just-ended 2010-11 fiscal year from the previous year, it expects average prices will slip to C$3.26 per gigajoule from C$3.58 per gigajoule in 2009-10. Conventional production for the 2010-11 year is anticipated to drop to 4.2 tcf from 4.5 tcf.
Alberta declining revenues Gas revenues for Alberta are expected to decline in the 2011-12 budget year to just over C$1 billion on an average price of C$3.45 per gigajoule, then recover to C$1.2 billion and C$1.5 billion over the following two fiscal years on prices of C$4.05 per gigajoule and C$5 per gigajoule. Each 10 cent decrease in gas prices lowers revenues by C$51 million.
The province forecasts conventional production will continue its downward spiral to 3.8 tcf, 3.5 tcf and 3.2 tcf over the next three years.
Leach said Alberta’s search for options to open new markets and demand in North America and start liquefied natural gas exports to Asia is “years away from impacting in a meaningful way on gas prices. In the meantime, Alberta and Western Canadian producers risk losing traditional North American markets.”
The damage is already surfacing, according to the National Energy Board, which says the progressive drop in the price of exports to the United States to C$4.29 per gigajoule in 2010 from C$8.89 per gigajoule in 2008 dragged export revenues over the same period to C$15.15 billion from C$33.1 billion.
The NEB reported that Canadian producers shipped 3.26 tcf into the United States in 2010, up fractionally from 2009, but lagging well behind the record 3.8 tcf in 2007.
The federal regulator has estimated the export volumes could drop by 2.2 bcf per day over the next two years, as conventional output declines in Alberta.
Relying on exploration British Columbia is now relying on producers to start exploring and developing lands they have acquired in recent years.
The province’s land sales have gone into decline since mid-2010, when a single auction fetched C$404 million, one of the largest in Canadian history.
The first three auctions of 2011 have generated only C$17 million, putting British Columbia on track for its worst sales year in almost two decades and for a 90 percent drop from last year’s C$844 million.
British Columbia’s newly appointed Energy Minister Rich Coleman met with industry executives in Calgary earlier in April to discuss an extension of the province’s special low-royalty program for Horn River.
“One of the CEOs said to me British Columbia is in the Top Five or Top 10 as places to invest in the energy sector, probably in the world. And I said ‘How do we get to No. 1?’” he said, hinting that reduced front-end royalties are possible to capture more long-term investment.
Coleman acknowledged there has been a sharp downturn in land sales now that most of the best exploration prospects have been acquired in Horn River and Montney, where companies paid C$5.44 billion for rights in the 2007-10 period.
But he said “it’s activity on the ground that’s more important to us, because that creates long-term jobs.”
He strongly endorsed the two LNG export terminals planned for British Columbia and a third project by Shell Canada that is in the planning stages as the best hope of diversifying his province’s dependence on distant and saturated U.S. markets.
| 