Coal is the backbone of Alberta’s electricity generation market. At nearly 6,300 megawatts, the fuel accounts for over 40 per cent of the province’s installed generation capacity. More importantly, as the major source of baseload power supply in Alberta, coal provided 67 per cent of the electricity used in the province in 2014.
Replacing all of that electricity is a daunting task, to be sure. But that is precisely what the Alberta government proposes to do in a plan announced last November. By 2030, coal will be phased out, replaced by cleaner fuel sources like natural gas and renewables. The entire power system is supposed to consist of 30 per cent renewable energy.
“I would call it a once-in-a-lifetime unique opportunity for the investment and construction side of this industry to essentially rebuild a generation fleet,” says Mike Law, vice-president of market services at the Alberta Electric System Operator (AESO).
That may sound like a huge task, but this policy shift is still more of a nudge on the accelerator than a complete U-turn. For one thing, the province is already Canada’s third-leading jurisdiction for wind power, with 1,400 megawatts of installed capacity. Meanwhile, regulations were already in place to reduce reliance on coal-fired generation, if at a slower pace. The greening of the Alberta grid is well underway—and has been for years.
Bullish on wind
Commissioned by BluEarth Renewables at the end of 2015, the 29.2-megawatt Bull Creek wind farm is the latest project to join the province’s robust wind-power fleet. Located 20 kilometres northeast of Provost, Bull Creek’s 17 turbines can produce enough electricity to power 10,000 average Alberta homes.
Grant Arnold, president and chief executive officer of BluEarth, says that Bull Creek is proof of wind power’s viability in Alberta. After submitting to a competitive process, the project was awarded the rights to sell power to a number of area school boards. For their part, the school boards were motivated to choose renewable energy as a hedge against future costs tied to carbon emissions—a prescient move considering the province has since announced plans to create a $20/tonne carbon tax in 2017 before moving up to $30/tonne the following year.
“Wind is a very strong resource in Alberta, and the price of constructing wind has come down,” Arnold says. He adds that solar, despite seeing steady cost decreases in recent years, still lags behind the wind sector.
However, he expects solar projects to become more attractive in the near future as the province reveals more details of its renewables policy in the coming year. His company currently has two utility-scale solar projects in the regulatory phase, as well as its Hand Hills wind project, which awaits a power purchase agreement before it can proceed to construction.
Two-thirds of the province’s coal capacity is supposed to be replaced by renewables, but the other third will be replaced by natural gas. For the province’s beleaguered natural gas producers, this represents a major opportunity. The Canadian Association of Petroleum Producers has estimated that switching off of coal could create the demand for 1.5 bcf/d of natural gas in the province.
“Alberta benefits from the economic development of gas exploration and as a royalty owner of that gas, so we’re what they call ‘naturally hedged,’” says Evan Bahry, executive director of the Independent Power Producers Society of Alberta. “We have the stuff. The more we sell, the better off we are, and the higher the price we sell it at, the better off we are.”
Between concerns over health effects and greenhouse gas emissions, coal was already in a precarious public position before the phase-out was even announced. The appeal of creating a homegrown market for the province’s ample natural gas reserves only makes the phase-out argument that much more persuasive. Andrew Leach, the University of Alberta energy economist who chaired the government’s climate change advisory panel, has summed up the situation well in public talks: “There is no one better positioned than Alberta to get themselves off of coal.”
Nearly half of the province’s installed generation capacity is natural gas, but the fuel is still primarily used as a source of peaking power during times of high demand—natural gas accounted for just 20 per cent of the power generated in Alberta in 2014. But projects like the Shepard Energy Centre in Calgary show the industry setting the stage for gas to take on a larger role in the power market.
Opened in March 2015, the 800-megawatt combined cycle plant is the largest of its kind in the province—and a good example of the kind of large-scale development that will be needed to fill the gap left by coal. A $1.4-billion project, Shepard required 4.3 million hours of construction, 2,630 workers at peak, 4,400 tonnes of structural steel and 20,000 cubic metres of concrete.
Now imagine building it seven times over.
That’s the yardstick used by Bahry when estimating just how much natural gas generation capacity will need to be built in the province by 2030 to meet the government’s goals. Renewables like solar and wind, while still a cornerstone of the energy strategy, are intermittent power sources. Natural gas will have to shoulder the burden of replacing coal’s baseload power production and backstopping renewable sources.
Timing an orderly shutdown of coal plants will be crucial to ensuring a successful energy transition. To this end, the government plans to appoint a facilitator to negotiate the process with power producers, but outstanding questions remain. Bahry expects reliability will be the first consideration among all involved, but other factors like the emissions of each facility will almost certainly play a role in deciding the order of shutdowns. He also speculates that the government will need make sure that no single company is financially overburdened.
“You don’t want to be impacting the same owner three times in a row,” he says. “You’re probably going to want to share the impact of taking plants out among the coal owners.”
Bahry notes that some coal plants are crucial to the flow of power in their respective regions, and this will have to inform the transition as well. But for the AESO—which oversees grid operations in the province and safeguards system reliability—this is just business as usual.
“There are some specific locations in the province that do require larger plants to be put back in because you need to ensure that there’s a mass and a momentum associated with the power system there,” Law says. “But in lots of other areas there isn’t that worry. If you take your heart out, you better replace your heart. But if you take out your appendix, you may not need to.”
Let it flow
Changes in generation invariably impact the transmission system, but the province seems prepared to cope following years of major expansions, including ATCO Electric’s Eastern Alberta Transmission Line (EATL) and AltaLink’s Western Alberta Transmission Line (WATL). Both commissioned late in 2015, the two massive multi-year projects—EATL costing $1.8 billion and WATL $1.7 billion—link the Edmonton and Calgary regions. The lines both employ direct-current technology, which can reverse directions to better accommodate the ebbs in power from intermittent sources like wind.
For the grid operator, there will be some adjustments as different high-voltage lines become more important and new generation sources enter the mix. But Law emphasizes that Alberta possesses both the skills and infrastructure needed to make this transition. People within the AESO and the power sector at large have been thinking about a greener grid for years. Last November’s announcement by the province was simply a sign that the government finally caught up.
“We have spent a significant amount of money over the last decade or so actually building transmission that facilitates renewables, especially in the southern part of the province and in the central-east Hanna area of the province,” Law says. “We’ve always foreseen some level of shift toward a more renewable and green grid, so while this has been a step-wise change from a government and policy perspective, it’s not a shock to an organization like the AESO.”