Who says Western Canada is running out of oil?
Fuelled by more than $30 billion in new oilsands projects over the next decade, the region’s crude oil production is expected to increase by 3.7 per cent a year over the next dozen years, says the Canadian Association of Petroleum Producers (CAPP).
Total crude production from Western Canada should reach more than 3.3 million barrels per day (b/d) by 2015, CAPP says in its new biennial oil production and supply forecast.
On the other hand, production of conventional light and heavy crude from the waning Western Canadian Sedimentary Basin will continue a decline begun a couple of years ago.
Total conventional light and heavy production from the basin will fall by more than half, from 1.12 million b/d in 2003 to about 600,000 b/d in 2015.
CAPP’s conclusion: “The substantial growth in oilsands production is far more than the decline in conventional production, resulting in significant overall industry growth.”
Oilsands production, which now makes up about half of total production, will grow by an average 9.6 per cent annually and account for three-quarters of all Western Canadian production by 2015.
What CAPP’s forecast doesn’t mention is that there’s still “another Alberta” trapped in rock formations in the western geological basin – as much conventional crude as all of the oil the province has ever produced.
But it will take a renewed investment by the oilpatch, especially in research and development of new oil-recovery technologies, to ever unlock this treasure.
The industry is certainly making enough money to afford to put more of it back into the ground, in terms of R&D, than it does right now.
Analysts say the oilpatch is poised to report one of its most profitable quarters in history, thanks to high world oil and gas prices.
Companies such as EnCana Corp., Imperial Oil Ltd., Talisman Energy Inc., Petro-Canada Inc. and others could come close to matching record quarterly profits last year, on their way to each earning more than $1 billion this year.
But if anything, Nexen Inc.’s decidedly down second-quarter results should spur companies to invest in technologies to pull more oil out of the ground at home.
Nexen surprised the market last week by reporting a 45-per-cent drop in second- quarter earnings, to $143 million or $1.11 a share, down from $264 million or $2.03 a share in the same period last year.
The company blamed operating costs that rose 14 per cent as well as declining production from its major facilities in Yemen, unplanned maintenance in offshore Australia and especially disappointing output from wells in the Gulf of Mexico.
Two things about the oil that’s still in the ground in Western Canada: Industry knows it’s here and production costs are a lot more predictable than they are in more volatile regions of the world.
COST CONTROL
Syncrude Canada made the right move by doing the pink-slip-and-staff shuffle earlier this month.
Enormous cost overruns on the oilsands operator’s mega-expansion project near Fort McMurray led to some personnel being shown the door.
That shouldn’t come as a surprise, given that the expansion work’s costs nearly doubled to $7.8 billion from initial estimates of $4.8 billion.
As part of the purge, Syncrude created a new layer of expert management, directly accountable to the plant’s owners, to keep rein on up to 5,500 construction workers employed by multiple contractors involved in the project.
But there is a much harder cost increase to corral for Fort McMurray operators Syncrude, Suncor Energy Inc. and the new Muskeg River Mine, completed last year by Shell Canada Ltd., Western Oil Sands and Chevron Canada Resources.
It’s the cost of natural gas used to fuel their bitumen-mining and upgrading operations.
High gas prices are to blame for much of Suncor’s expected 16-per-cent increase in operating costs this year, pushing expenses to $12 to $12.50 per barrel of production.
Syncrude and Suncor are both working on new technologies to extract the fuel they need from their own bitumen or from coke, the charcoal-like byproduct of synthetic oil upgrading.
Unless the companies want gas prices to take a bigger bite out of profits, the sooner they start using their own fuel, the better.
ENCANA TACKLES DEBT
EnCana Corp. must have been getting a little edgy about that mountain of debt.
The company reached an agreement last week to sell conventional oil and gas assets in east-central and southern Alberta to Harvest Energy Trust for about $526 million.
The move came a day after Moody’s Investors Service cut EnCana’s long-term credit ratings to the second-lowest investment grade, over concern about $350 million in debt EnCana assumed in its purchase earlier this year of U.S. oil and gas producer Tom Brown Inc.
EnCana said the Moody’s downgrade would have only a marginal impact on EnCana’s borrowing costs and wouldn’t affect expansion plans.
EnCana Corp.’s chief executive Gwyn Morgan has been increasing borrowing while making acquisitions and raising spending on exploration to boost reserves and output.
It’s obvious from the assets sale to Harvest Energy Trust that Morgan’s strategy also includes keeping a close eye on EnCana’s debt level.
(Mark Lowey can be reached at mark@businessedge.ca)
