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An electric car charges at a parking lot in Tsawwassen, B.C., on April, 6, 2018.JONATHAN HAYWARD/The Canadian Press

Plans for widespread adoption of electric vehicles, heat pumps and electric arc furnaces imply surging demand for electricity.

A recent report from Royal Bank of Canada predicted Canadian electricity consumption will rise by 50 per cent over the next decade alone. Earlier this year, one by the Canadian Climate Institute said the nation’s electricity generation capacity will need to grow between 2.2 and 3.4 times larger by mid-century than it is today. Last year, another report by the Institut de l’énergie Trottier – Polytechnique Montréal said electricity production from variable sources such as wind and solar must grow dramatically to achieve net-zero objectives.

The investment required to build all that capacity has been likened to wartime spending.

But Canada’s major utilities aren’t preparing for anything of the sort. Nor are major planning bodies such as Ontario’s Independent Electricity System Operator (IESO) and the Alberta Electric System Operator (AESO) telling them to. That’s the main take-away from annual reports and planning outlooks published by these organizations and reviewed by The Globe and Mail, and interviews with decision makers within these organizations.

“I don’t think you can point anywhere to any utility that is actually pursuing this in its system plans, or its capital plans,” acknowledged Jason Dion, mitigation research director at the Canadian Climate Institute, a co-author of the report his organization released in May.

This inertia offers a strong indicator of the current trajectory of electrification. Utilities and system planners, after all, bear considerable responsibility for power plants and transmission lines that actually get built, and grasp the technical and financial requirements. If they aren’t buying predictions of rapid mass electrification, it’s worth exploring their reasoning.

Canada’s electricity sector is hardly in stasis. This year, the government of Quebec and Hydro-Québec commenced what will likely be the largest wind and renewable energy procurement in the province’s history. Ontario’s IESO has a number of significant procurements under way. BC Hydro is in the midst of what it calls “one of the largest expansions of electrical infrastructure in British Columbia’s history.”

Some utilities’ pronouncements also seem to be consistent with net-zero commitments. TransAlta’s most recent annual report told shareholders the 2020s “will be a decade of massive clean energy expansion.” Ken Hartwick, chief executive of Ontario Power Generation, said in June that for Ontario to hit climate targets, its electricity system would have to “at least double” in size.

The utilities’ current capital spending budgets wouldn’t come close to achieving such outcomes, however.

In Ontario, Bruce Power and OPG are investing a combined $26-billion in refurbishing their aging nuclear reactors, and OPG has been ordered to examine the prospects of doing the same thing at its Pickering station. But that would merely extend the lives of those facilities.

The IESO, which is responsible for ensuring Ontario has sufficient electricity to meet demand, anticipates “a period of increasing electricity demand” driven partly by proliferation of EVs beginning around 2030. But it hopes existing generating facilities will continue to be available throughout the coming years – in which case it sees little need to embark on a building frenzy until the late 2030s. In October, Ontario also signalled it wants to expand existing natural gas facilities.

British Columbia is mostly content with its system, too, which largely dates from the 1960s through the 1980s. BC Hydro’s capital spending is dominated by the troubled 1.1-gigawatt Site C dam in the province’s northeast, expected to be commissioned in 2025. Looking beyond, the company forecasts load will increase only slightly between now and 2041.

TransAlta, which has well over half its installed capacity in Alberta, spent the past few years converting coal-fired plants to burn natural gas, and building new wind farms. It plans to build up to an additional 2 gigawatts of clean generation in Canada by 2025 and aims to double its renewable fleet in the second half of this decade. But TransAlta’s electricity production fell considerably in recent years as it retired coal plants.

Blain van Melle, executive vice-president at TransAlta, said the company expects Alberta’s load will grow by 1 per cent to 1.5 per cent annually – a slower pace than the province has experienced so far this century. The AESO’s view is similar: it anticipates considerable new demand from electrification, offset by slower demand growth from the oil and gas industry. Over all, it predicts load will grow by just one-quarter between now and 2041.

TransAlta CEO warns of human cost in energy transition

This summer, the AESO published a report examining scenarios for reaching a net-zero grid in Alberta by 2035. It was openly skeptical about achieving that target, noting the various scenarios explored “face significant implementation challenges,” not the least of which is that there’s just 13 years remaining. Then there’s the cost: achieving net zero would require capital investments of between $44-billion and $55-billion, it said.

To understand utilities’ skepticism, it’s worth noting that new generating plants aren’t the only way to satisfy rising demand. BC Hydro hopes to achieve significant savings through energy efficiency initiatives, along with programs that encourage users to shift consumption to times of the day when there’s more power available. That’s partly why its latest 20-year plan predicted no need for new capacity until 2037.

More importantly, though, not everyone believes buildings and vehicles will be rapidly electrified. Prof. Winfield said current government policies by no means assure that outcome. “So there’s a question on the part of the utility: is that demand growth actually really going to be realized?”

Kevin Dawson, the AESO’s director of forecasting and analytics, said his organization doesn’t think electrification will proceed as quickly as aggressive think tanks assume. “When we look at it, there’s a certain amount of inertia in the system – there’s a certain amount of cost advantage that the historical technologies have, that might take some time to overcome,” he said.

TransAlta’s Mr. van Melle questioned whether utilities could afford rapid mass electrification. “If you were to electrify everything that is now using some sort of fossil fuel, the companies that would have to do it don’t have that sheer amount of capital to invest,” he said. “I don’t think it’s possible.”

Utilities and system planners are conservative by nature. Affordability and reliability comprise the core of their mandates. And past bold expansions often ended badly.

In 2013, for instance, the government of Manitoba convened a panel to review Manitoba Hydro’s growth plans, which included two new hydro dams: Keeyask and Conawapa. The panel’s opinion was withering: “The Panel sees Manitoba Hydro’s long-term future projections as highly speculative and too uncertain.” (The Conawapa project was scrapped.)

The review panel that examined Labrador’s troubled Muskrat Falls project was similarly dismissive: “There are significant limits to the accuracy of a forecast of electrical loads 55 years into the future.”

“We have a history in Canada of provincial electricity utilities effectively bankrupting themselves by massively overbuilding supply for demand that never materializes,” Prof. Winfield observed.

It’s not that planners are incapable of imaginative thinking. Dave Devereaux, the IESO’s director of resource planning, said his organization is currently engaged in some speculative forecasting that envisions demand growing as much as threefold. But the IESO doesn’t have the luxury of incorporating such aggressive forecasts into its annual planning outlooks, which inform actual procurements.

Mr. Dawson said the AESO is also skeptical because so many other jurisdictions worldwide also vow to transform their electrical systems in the next couple of decades.

“So it seems reasonable to raise the question: How is the supply chain going to handle that global demand for solar panels, battery storage, wind farms?” he said. “If you’ve got everybody ordering this equipment all at once, there’s a high risk that availability becomes an issue, or costs are escalated.”

More traditional options such as nuclear reactors or hydro dams might also be considered. RBC’s report urged this: ”Hydro and nuclear can provide significant value by avoiding a system that relies too heavily on wind and solar power and needs to store them.” But both are notorious for delays and cost overruns.

Back in 2007, then-B.C. premier Gordon Campbell identified Site C as an option for meeting what BC Hydro predicted would be a 45-per-cent increase in demand over two decades. The utility didn’t foresee how Site C would degenerate into a morass of cost overruns and geotechnical issues that damaged the credibility of all involved.

But while Site C would seem to be a cautionary tale about the hazards of complex capital projects, for many net-zero enthusiasts it’s the opposite: a reminder of why planning new generation projects must start now. RBC warned that Ontario already faces energy shortages by 2026. Though other provinces’ problems are less acute, they will soon have to make tough and expensive decisions.

“If they get it wrong, Canada could suffer Europe’s fate of a hobbled, energy-insecure grid that leaves consumers with soaring bills,” RBC asserted. Another possibility, it added, is that higher bills will discourage consumers from adopting EVs and heat pumps.

The main take-away: For all the talk of decarbonizing the electricity sector and mass electrification, the hard work of making it happen has barely begun.

“If we’re serious about net zero, this whole conversation has to move to a different level of specificity and detail,” Prof. Winfield said.