This is part of an occasional series on Canada's economy and its shift away from resources.
Massive turbine blades are rotating ever so slowly at TransAlta Corp.'s Summerview #1 wind farm, on the edge of the Rocky Mountain Foothills near Pincher Creek, Alta., on a spring afternoon.
The white windmills poke up in nearly every vista here, normally one of the province's breeziest corridors and site of electricity operations that will be emphasized increasingly as Alberta proceeds with tough new carbon restrictions. But a pleasantly calm day shows wind's limitations compared with TransAlta's main power source – coal-fired plants.
"This isn't a good revenue moment right now," Wayne Oliver, supervisor of TransAlta's operations at Pincher Creek, says at the foot of one of the 67-metre-high units. "If a Chinook wind comes in and it starts to ramp up to 30, 40, 50 kilometres per hour and everything's turning, those are the days when you're actually making some money. Today, you just get these spotty little currents."
It belies the change blowing through TransAlta itself, which is anything but spotty and little. More than any Canadian company, TransAlta faces an existential struggle as it navigates through the climate rules that have given it a 14-year deadline to shut down billions of dollars' worth of coal plants for good. Such stations, run by TransAlta and others, make up 39 per cent of Alberta capacity, and form the bedrock of the grid's power availability. Natural gas-fired plants, along with renewable operations, will have to fill the void.
This is the forefront of Western Canada's changing economy, and it is one that the world's push for lower-carbon energy is forcing. Even a company known for moving crude from the oil sands to market – Enbridge Inc. – is expanding its renewable-energy portfolio as bitumen producers approach a 100-megatonne cap on carbon emissions under Alberta's climate-change plan. This comes even as it promotes controversial projects, such as the $7.9-billion Northern Gateway oil pipeline, whose approval was overturned by the Federal Court of Appeal last week.
Alberta – which has been built on fossil-fuel development – is weighing recommendations from the electric system operator for how to achieve a target of one-third renewable-energy generation within 14 years. Big unknowns are what pricing structure will be used, and whether coal generators will be given incentives to switch to other fuel sources.
TransAlta had previously branched out into renewables, including wind and solar, with the expectation that the world was gradually moving to greener energy. Change came more suddenly than it expected.
In 2011, Ottawa brought in rules to limit emissions from burning coal, and had expected that carbon-capture technology would help the cause. But last year, Alberta Premier Rachel Notley's new NDP government introduced its Climate Leadership Plan that mandates the end of coal-fired power in the province by 2030. For TransAlta, the impact is immense.
The company has stakes in five coal-fired power plants, representing 57 per cent of total coal capacity. The newest of which, the 50-per-cent-owned Keephills 3 station west of Edmonton, started up in 2011 and had been expected to keep operating until 2061. Had TransAlta known that the end of coal was on the horizon, it would not have built the $2-billion plant, chief executive officer Dawn Farrell said.
In its annual report, the company doesn't sugarcoat what it faces, telling shareholders that it has become a riskier investment. The shares have been under pressure due to the uncertain remaining value in the Alberta assets, though they have recently strengthened.
"You can't hide anywhere on this," Ms. Farrell said this spring. "When you think about it, we face a $30 carbon tax, renewables will be subsidized and brought into the market and our coal plants can't run beyond 2030 – and they were built to run til 2050. It's a very big issue for us. Our shareholders have to know that we're facing into that issue and this is how we're trying to get them through that."
The government appointed U.S. power-industry regulation veteran Terry Boston to lead talks with generators as they seek to avoid a massive loss of asset value as well as surging power prices and reduced reliability. His report is due in September.
Ms. Farrell said she believes that the government wants the best solution to avoid those problems.
"In order for Alberta to attract the massive amount of private investment that's going to be required to build up this system, you have to take care of the existing investors," she said. "Alberta has always been a market where private investment has been required, and I think investors have to have confidence in the framework, so that gives me confidence."
The bad news for coal is a potential boon for Enbridge, which is aggressively seeking new avenues for growth that aren't tied directly to shipping crude.
It's a dramatic pivot. The Calgary-based pipeline giant remains the dominant shipper of Canadian oil to refineries in the United States. In the first quarter, it moved a record 2.5 million barrels a day on its sprawling mainline network, up 300,000 barrels from the same period a year ago, as oil sands production surged.
But that trajectory is poised to drop significantly. Oil's collapse from more than $100 (U.S.) a barrel two years ago has forced producers to scrap billions of dollars worth of mega-projects, shaving nearly one-fifth from the industry's long-term production outlook. Some analysts doubt much of the squelched potential will be resurrected, as money flows instead to lower-cost U.S. shale plays and oil sands production bumps up against the province's new cap on emissions.
For Enbridge, Alberta's slowdown has coincided with expanding investments in renewable energy and in natural gas. To be sure, the company is not upending its strategy. Its hydrocarbon liquids business still accounts for as much as 75 per cent of earnings and cash flow, chief executive officer Al Monaco said.
Increasingly, however, the oil shipper is responding to what he describes as a fundamental shift in North American – and global – energy markets.
In May, it acquired a 50-per-cent stake in offshore wind developer Éolien Maritime France SAS for $282-million (Canadian). The deal gives Enbridge ownership in three large-scale wind projects being developed off the coast of France with potential to generate more than 1,400 megawatts of power.
The move followed a $750-million investment, last November, in the 400-megawatt Rampion wind project under construction by German utility E.ON off Britain's southern coast.
While such investments represent a small part of Enbridge's overall business, they are poised to grow, according to Mr. Monaco. "We're a bit of a microcosm of what's happening in the future," he said.
TransAlta has interests in 22 wind farms, 12 of them in Alberta. Changes to the market structure in Alberta have to be made clear before major new investments are viable. In recent years, Ontario and Quebec have surpassed Alberta wind capacity through long-term supply contracts.
"The thing that's limited that development has been, with the pricing scheme in Alberta it hasn't been economically viable. The return on investment is so low at today's pricing scheme that it doesn't make sense to develop wind," Mr. Oliver said at the edge of a farmer's field. "If that changes, then there's incentive."