Yukon, N.W.T. and Nunavut differ in outlooks for renewable energy

Ratepayers and politicians alike are calling for Northern governments to produce cheaper power and to shift away from fossil fuel generation towards renewable energy. But depending on where you live in the North, that may be easier said than done.
A view of the spillway at Yukon Energy's Whitehorse generating facility. (David Croft/CBC)

Electricity — how we generate it and how much it costs — is a perpetual hot-button issue in the North. The same is true for climate change. That has ratepayers and politicians alike calling for Northern governments to produce cheaper power and to shift away from fossil fuel generation towards renewable energy. But depending on where you live in the North, that may be easier said than done.


The good news for Yukon is that it’s almost at 100 per cent renewable energy already. In 2013, Yukon Energy generated 99.5 per cent of its electricity via hydroelectric dams and wind. Diesel generators are used almost exclusively for backup in the winter when demands rise and hydro generation declines.

Even so, Yukon Energy still wants to reduce the amount of diesel it relies on. That’s why it’s building a new backup generator, fired by liquified natural gas, to replace two aging diesel gensets in Whitehorse.

The cost was originally pegged at around $39 million, but Yukon Energy spokeswoman Janet Patterson said changes to the project mandated by the Yukon Environmental and Socio-economic Assessment Board have thrown that figure into flux.

Yukon Energy estimates the new LNG generators would save the utility $2.2 million per year and slash carbon emissions.

“The reduction of life-cycle emissions in terms of greenhouse gas emissions would be 26 per cent,” Patterson said.

Critics of the project argue it puts of further investments in renewable energy and serves as a trojan horse to bring fracking for natural gas to Yukon (the current plan is to truck LNG in from British Columbia). But Patterson argues the current state of wind and solar power make them unsuited to producing power on demand when temperatures drop and loads increase, and a transmission line connection to B.C. would cost around $1.5 billion, a bill that’s too steep to pass on to ratepayers.

“Let’s say there’s a power outage and it’s -40 C. We can’t just call up our neighbour and say ‘We need more power.’ We have to come up with it ourselves and… it has to always be available to us.”


The Northwest Territories, ever the middle child in Northern affairs, produces about 80 per cent of its electricity with hydro. Like Yukon, it isn’t connected to the southern grid, meaning it can’t import cheaper southern power.

Low water levels in the N.W.T. this summer affected the Snare hydro system's electricity output. This photo, taken Aug. 14, 2014 shows the low water levels at one of the dams in the Snare system. (Northwest Territories Power Corporation)
The N.W.T.’s own system, with the Snare hydro near Yellowknife, and the Talston hydro dam near Fort Smith, effectively comprises two separate grids. And even hydro isn’t immune to fluctuations in supply: dry weather this summer required the Northwest Territories Power Corporation to burn about $20 million in extra diesel to keep up with demand. That’s on top of the $25 million in diesel NTPC burns every year for backup and in off-grid communities.

In the past decade, the GNWT has spent around $21 million on various studies for renewable energy and transmission line projects for smaller communities, including solar, hydro and geothermal. But the N.W.T. is a long way from fully renewable power, said Andrew Stewart, the director of business development for NT Energy, NTPC’s renewable energy sister company.

“It will eventually be possible – some would say even required, as fossil fuel supplies dwindle – but that is decades away,” Stewart wrote in an email. “There is also the view that with enough money, anything is possible today.”

The government is backing away from its original plan to link the N.W.T.’s two grids to one another and to the south. Original estimates put the project cost at around $700 million, but new estimates are closer to $1.2 billion, which is more than the territory can afford, said finance minister Michael Miltenberger. 

Meanwhile, the GNWT has an energy charrette, a planning meeting, which will hear from experts, governments and industry scheduled for early November.

“There is a strong [financial] commitment coming as a result of the meetings,” said a senior government source. That likely means a major push on renewable energy.


Nunavut is a long, long way from generating more than a token amount of renewable energy. The territory is almost entirely dependent on diesel-generated power, apart from tiny amounts of wind and solar power.

Qulliq Energy, Nunavut’s utility, imports around 45 million litres of diesel fuel every year into the territory.
At last count, diesel produced 99.94 per cent of Nunavut’s electricity. There’s no grid at all: each community is served by its own diesel-fired power plant. Many of those plants are at or near the end of their design lives.

While Qulliq Energy, Nunavut’s utility, has upgraded several plants over the last few years, including a $30-million upgrade to diesel generators in Iqaluit that added 10 megawatts of new capacity, it still imports around 45 million litres of diesel fuel every year.

In 2010, according to Alberta Oil magazine, Nunavut spent $39 million on diesel. According to Qulliq’s most recent application to the Utility Rates Review Council, that figure has climbed by $12 million since, meaning Nunavut now spends more than $50 million per year to keep the lights on.

While hydro offers a cheaper source of power over the long term, Nunavut lacks the cash to pay for the expensive upfront capital costs of a hydro dam. Qulliq has had plans for a hydroelectric plant that would generate between 16 and 25 megawatts near Iqaluit for nearly a decade, but progress has been slow. Cost estimates for the project are around $450 million. And in 2008, QEC conducted a desktop study for hydro power at various sites in the Kivalliq region, with an estimated price tag of $380 million.

Alain Barriault, QEC’s newly-appointed president, said there’s been no further work done on the Kivalliq project. He said the Hudson Bay Neighbours Regional Roundtable, made up of leaders from Nunavut and Manitoba, has recently struck a working group to take a new look at old plans to build a transmission line that would bring hydro power from Manitoba into the rapidly-growing Kivalliq region.

“How that turns out, we’ll have to wait and see,” he said.

Barriault said QEC is serious about pursuing “alternate funding” for the Iqaluit hydro project, including public-private partnerships and deals with the Qikiqtani Inuit Association.

“There are partnerships that we can strike to make this more affordable,” Barriault said. “Other people have an interest in providing affordable energy and can invest in it…. We’re looking at proving a business case so the power we provide is going to be affordable to our ratepayers.”


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