The looming threat of Alberta's first trades strike in 25 years could slow construction in the booming oilsands, ultimately harming the province's reputation as a reliable investment climate, observers say.
"Oil and gas companies look at investments all around the world and they weigh the factors," Todd Hirsch, chief economist at ATB Financial, said as 25,000 skilled workers, including pipefitters and electricians, began a strike vote last week.
"If Alberta is starting to be seen as a place where there is a continual threat of strikes, that will weigh into their decision," he said. "They're not going to pull up stakes (in) the province, but it will weigh into their decision on how attractive is the Alberta investment climate."
Alberta's labour board recently ordered that vote results be sealed until after the ironworkers union held its vote July 13.
The looming labour unrest among trades is the first in Alberta since 1982 when the government of Peter Lougheed created legislation grouping 10 building trades unions that negotiate with employer associations for contracts that apply across the province.
Under the province's labour law, none of the unions may take a strike vote unless 60 per cent of unions with unsettled contracts opt for a strike vote.
About 40 per cent of those voting are working on construction at the oilsands near Fort McMurray in northern Alberta, where the cost of living has skyrocketed in recent years.
The energy industry has been struggling for months to cope with soaring development costs in the area, fuelled in part by a shortage of skilled tradespeople and regular labourers. But while manpower has been increasingly expensive, it has always been steady.
A strike could halt or slow down work on several multibillion-dollar projects with unionized labour, including Long Lake, the joint venture between Opti Canada (TSX: OPC) and Nexen Inc. (TSX: NXY) that will use steam-assisted gravity drainage to mine bitumen, slated for completion within a year.
Electricians spokesman Barry Salmon says his members want a contract that recognizes the economic pressures of the booming province and believe a strike mandate will kickstart negotiations.
"We wouldn't want to see any of these projects adversely affected, but we don't feel the responsibility lies with us - not when we've had a six-per-cent increase over the last four years," said Salmon, business manager for the 6,000-member electricians union.
The unions say Alberta's labour code prevents effective bargaining and was written to prevent trades from ever getting to the stage of a strike vote and a potential labour disruption.
Foreign workers make up between 2,500 and 5,000 workers in the Fort McMurray area, but that has never been a sticking point in the contract negotiations.
Meanwhile, about half of unionized workers at Suncor Energy Inc. near Fort McMurray have voted in favour of a new three-year contract.
Members of the Communications Energy and Paperworkers Union (CEP) Local 707 approved an agreement including a wage increase of seven per cent in the first year and six per cent in each of the following two years, as well as a $4,000 lump sum payment.
The union represents more than 2,100 of the 4,000 employees who work at Suncor's oilsands operation north of Fort McMurray.
Alberta's new tax on emissions started July 1 and will cost dozens of industrial giants roughly $175 million a year as the province cracks down on the growing belch of greenhouse gases.
The new rules cover refineries, oilsands plants, large gas plants, electricity generators, petrochemical plants and other major industrial plants - about 120 in total across Alberta.
Oliver Bussler, environmental manager with Epcor, one of Alberta's largest power generators, says it's too early to say how much more consumers will pay as a result of the new rules, which call for a $15 per-tonne levy for emissions that exceed the regulations.
But Bussler says Epcor has decided to use a second option being offered by the province - investing in emission-reduction programs to offset its emissions.
"We're not certain yet exactly how much of those projects will qualify under this new regulation," he said.
Although there was some initial grumbling by the industry, the Canadian Association of Petroleum Producers (CAPP) is now endorsing the levy as being a reasonable approach to the prickly issue of reducing greenhouse gas emissions.
CAPP president Pierre Alvarez says the rules are clear and provide certainty for energy companies and investors.
"What's important about the Alberta plan is there's lots of flexibility," said Alvarez. "If you don't meet the targets there are going to be consequences."
But he also says the impact of the new regulations will "be different for every player," with some paying the penalties and others adopting new technologies or changing equipment to reduce emissions.
"Some large facilities like a big gas plant may be able to make some changes, others may have to wait a few years before they change out equipment," he said. "Still others are going to be looking for the longer-term solution, investing heavily in technology."
A new government agency will determine which plants don't meet the new emissions rules. The first evaluation will be in January 2008 and the companies found in violation will be expected to pay their first levies by March 1, 2008.
Ottawa needs to slap a pricetag on greenhouse gas emissions very soon if it hopes to achieve its promised reductions by 2050, says a group of federally appointed advisers.
And the National Round Table on the Environment and the Economy says the government would save Canadian businesses more money if it signed up to international carbon trading markets, rather than going it alone.
The round table's interim report, commissioned by the government, was yet another voice among a chorus of economists and environmentalists who say the only way to address greenhouse gas emissions is to make it costly to pollute.
Top thinkers at financial institutions and Canadian universities have underlined that the market needs a strong price signal if industries and consumers are to truly change their behaviour.
A price on carbon would mean either a tax on polluters - including consumers - or a cap-and-trade system where companies that cannot meet government-imposed reduction targets trade credits on a carbon market.
"That machinery has to start being defined in the coming months and implemented in the coming years, and we have to see it impacting on some of the major decisions, especially around energy infrastructure and production lines and consumer choice of goods before 2012 and 2015," said Alex Wood, executive director of the round table. "If that isn't designed ... we won't meet our targets, and if it's delayed the cost of it goes up."
The round table's interim report ran a number of scenarios on the impact to the economy, given certain policy choices.
It found that acting quickly to achieve the target of 65 per cent below 2003 emissions levels by 2050 would have a milder impact on the economy and result in an ultimately lower price per tonne of carbon than proceeding slowly.
But the government's newly released plan for dealing with large industrial emitters does not apply a price per tonne of carbon. Instead, it imposes a series of reduction targets on industry, and companies that are unable to meet them can in the short term pay into a technology fund at a rate of $15-$20 per tonne of carbon.
That does not constitute the kind of market signal that will be necessary to achieve promised reductions by 2050, or even those projected by the government for 2020, the report suggests.
Round table president Glen Murray, the former mayor of Winnipeg, said the organization's biggest message to the government is that the choices made now will fundamentally affect how far Canada gets in the emissions battle decades in the future.
He said the current political debate has become trapped in a discussion of Canada meeting targets under the Kyoto protocol for 2008-2012.
Petro-Canada (TSX:PCA) and its partners have nailed down the size, scope and pricetag of the mammoth Fort Hills oilsands project, with the first phase budgeted at $14.1 billion.
The members of the Fort Hills Energy Ltd. Partnership - including Teck Cominco Ltd. (TSX:TCK.B) and UTS Energy Corp. (TSX:UTS) - are committed to proceed with the $1.1-billion front-end engineering and design.
Neil Camarta, Petro-Canada's senior vice-president of oilsands, said it will take about a year to produce a definitive cost estimate, which will be the basis on which a final decision on the project will be made, but preliminary work is already going ahead including a plan to order about $800 million in equipment.
Camarta said the building of the mine and bitumen extraction plant 90 kilometres north of Fort McMurray and upgrader northeast of Edmonton have been staggered to help alleviate worker shortages.
He suggested about half of the roughly 4,000 skilled workers on the project will likely come from outside Alberta. The project will employ as many as 8,000 workers in total during construction.
The project is expected to produce 140,000 barrels a day of synthetic crude oil in its first phase.
Bitumen production is targeted for late 2011, with oil output from the upgrader expected to start around mid-2012. By 2014, Fort Hills is projected to produce up to 280,000 barrels a day.
The Dominion Bond Rating Service suggested Petro-Canada faces "significant project execution risk and a relatively inflexible investment schedule once construction begins."
"Commodity price weakness could also make it more difficult for UTS Energy Corp., a 30-per-cent partner in Fort Hills that does not have financial resources comparable to the company, to raise its share of capital, which would result either in further significant capex (capital expenditure) for existing partners or the need to attract an additional partner."
Petro-Canada has a 55-per-cent interest in the Fort Hills partnership, with 30 per cent held by UTS Energy and 15 per cent by Teck Cominco.
Buoyed by long-term contracts to ship an additional 155,000 barrels a day of oilsands crude from Alberta, TransCanada Corp. (TSX: TRP) has announced plans to expand its proposed Keystone pipeline to the U.S. Gulf Coast.
The proposed expansion, from Illinois to Cushing, Okla., would increase Keystone's transportation capacity to 590,000 barrels a day. Keystone's initial nominal capacity when it enters service in late 2009 is to move about 435,000 barrels of crude oil daily from Hardisty, Alta., to U.S. Midwest markets at Wood River and Patoka, Ill.
Production in Alberta's oilsands has been forecast to triple by 2010 to three million barrels a day. Limited refining capacity in Canada has created a strong demand for increased pipeline capacity to move the crude south.
The expansion would make use of TransCanada's existing pipeline network, but will also include additional pump stations and construction of a 473-km pipeline from the Nebraska-Kansas boundary to Cushing.
No pricetag was attached to the proposal.
Calgary-based TransCanada says it has now secured firm contracts to move 495,000 barrels a day in Keystone's initial phase.
"They see the supply coming (onstream) quicker so I think they've just accelerated the expansion," said Greg Stringham, CAPP vice-president of markets and fiscal policy.
Stringham expects that over the next year, expansion plans for existing pipelines and proposed projects will be pushed forward to handle the forecast demand.
"And we're going to need more beyond that," he said. "Come 2013-2014 we're going to need another round of pipelines to move the oil that's anticipated. Once you've tapped out the (expansion ability) of the existing system, then you have to start looking at new routes."
Last month, Enbridge Inc. (TSX:ENB) announced plans to partner with ExxonMobil Pipelines Co. and build a pipeline to ship Canadian oilsands crude through to Texas from Illinois. That project could be in service by 2010.
TransCanada is one of the largest providers of natural gas storage in North America. It also has a network of 59,000 km of wholly owned pipelines and taps into most of the major gas supply basins on the continent.
Enbridge Inc. (TSX:ENB) has applied to the National Energy Board to build a $300-million oil pipeline between Edmonton and Hardisty in east-central Alberta.
The Line 4 extension - 136 km of 36-inch pipe - will connect existing idle 48-inch segments, moving the origination point of Enbridge's highest-capacity line from Hardisty to Edmonton.
Its capacity of 880,000 barrels per day would match the current Line 4 capacity.
Enbridge says it is proceeding with land access, engineering and initial procurement, aiming to begin construction next year and have the line in service by early 2009.
The NEB has given conditional approval to Enbridge's Westspur capacity expansion, which will build a 60-km line to carry natural gas liquids from Alida, Sask., to Cromer, Man. An existing line between Alida and Cromer will be converted to transport crude oil.
