First Clean Energy Community Officially Designated

BC Hydro Ice Storm Response to Fraser Valley power outages highlights freezing rain impacts, round the clock crews, infrastructure challenges, and climate change risks across the Lower Mainland during winter weather and restoration efforts.

Key Points

A plan for freezing rain events that prioritizes safety, rapid repairs, and clear communication to restore power.

✅ Prioritizes hazards, critical loads, and public safety first

✅ Deploys crews, contractors, and equipment across affected areas

✅ Addresses climate risks without costly undergrounding expansion

Call it the straw that broke the llama's back.

The loss of power during recent Fraser Valley ice storms meant Jennifer Quick, who lives on a Mission farm, had no running water, couldn't cook with appliances and still had to tend to a daughter sick with stomach flu.

As if that wasn't enough, she had to endure the sight of her shivering llamas.

"I brought them outside at one point and when I brought them back in, they had icicles on their fur," she said, adding the animals stayed in the warmth of their barn from then on.

For three and a half days, Quick and her family were among more than 160,000 BC Hydro customers in the Fraser Valley left in the dark after ice storms whipped through the region.

BC Hydro expects to get all customers back online Tuesday, five days after the storm hit.

And with another storm possibly on the horizon, the utility is defending its response to the treacherous weather, noting that windstorm power outages can be widespread.

BC Hydro spokesperson Mora Scott said the utility has a "best in class" storm response system, similar to PG&E winter storm prep in the U.S.

"In a typical storm situation we normally have 95 per cent of our customers back up within 24 hours. Ice storms are different and obviously this was an atypical storm for us," she said.

Scott said that in this case, the utility got power back on for 75 per cent of customers within 24 hours. It took the work of 450 employees called in from around B.C., working around the clock, a mobilization echoed by Sudbury Hydro crews after a storm, she said.

The work was complicated by trees falling near crews, icy roads, low visibility and even substations so frozen over the ice had to be melted off with blowtorches.

She said that in the long term, BC Hydro has no plans to make changes to how it responds to extreme ice storms or how infrastructure is built.

"Seeing ice build up in the Lower Mainland like this is a rare event," she said. "So to build for extremes like that probably doesn't make a lot of sense."

Climate change will bring storms

But CBC meteorologist Johanna Wagstaffe said that might not always be the case as climate change continues to impact our planet.

"The less severe winter events, like light snowfall, will happen less often," she said. "But the disruptive events — like last week's storm — will actually happen more often and we are already seeing this shift happen."

Marc Eliesen, a former CEO of BC Hydro in the early 1990s, said the utility needs to keep that in mind when planning for worst-case scenarios.

"This [storm] is a condition characteristic of the weather in the east, particularly in Ontario and Quebec, where freezing rain outages in Quebec are more common, which is organized to deal with freezing rain and heavy snow on the lines," he said. "This is a new phenomenon for British Columbia."

Eliesen questions whether BC Hydro has adequate equipment and crew training to deal with ice storms if they become more frequent, pointing to Hydro One storm restoration in Ontario as a comparison.

'Always something we can learn'

Scott disagrees with some of Eliesen's points.

She said some of the crews called in to deal with the recent storm come from northern B.C. and the Interior and have plenty of experience with snow.

"There's always something we can learn in every major storm situation," she said.

The idea of putting power lines underground was raised by some CBC readers and listeners, but Scott said running underground lines is five to 10 times the cost of running lines on pole, so it is done sparingly. Besides, equipment like substations and transmission lines need to be kept aboveground.

Meanwhile, Wagstaffe said that beginning Thursday, wintry weather could return to the Lower Mainland.

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Manitoba Hydro rate hikes face public hearings over electricity rates, utility bills, and debt, with impacts on low-income households, Indigenous communities, and Winnipeg services amid credit rating pressure and rising energy costs.

Key Points

Manitoba Hydro seeks 7.9% annual increases to stabilize finances and debt, impacting electricity costs for households.

✅ Proposed hikes: 7.9% yearly through 2023/24

✅ Driven by debt, credit rating declines, rising interest

✅ Disproportionate impact on low-income and Indigenous communities

Hearings began Monday into Manitoba Hydro’s request for consecutive annual rate hikes of 7.9 per cent.  The crown corporation is asking for the steep hikes to commence April 1, 2018.

The increases would continue through 2023/2024, under a multi-year rate plan before dropping to what Hydro calls “sustainable” levels.

Patti Ramage, legal counsel for Hydro, said while she understands no one welcomes the “exceptional” rate increases, the company is dealing with exceptional circumstances.

It’s the largest rate increase Hydro has ever asked for, though a scaled-back increase was discussed later, saying rising debt and declining credit ratings are affecting its financial stability.

President and CEO Kelvin Shepherd said Hydro is borrowing money to fund its interest payments, and acknowledged that isn’t an effective business model.

Hydro’s application states that it will be spending up to 63 per cent of its revenue on paying financial expenses if the current request for rate hikes is not approved.

If it does get the increase it wants, that number could shrink to 45 per cent – which Ramage says is still quite high, but preferable to the alternative.

She cited the need to take immediate action to fix Hydro’s finances instead of simply hoping for the best.

“The worst thing we can do is defer action… that’s why we need to get this right,” Ramage said.

A number of intervenors presented varying responses to Hydro’s push for increased rates, with many focusing on how the hikes would affect Manitobans with lower incomes.

Senwung Luk spoke on behalf of the Assembly of Manitoba Chiefs, and said the proposed rates would hit First Nations reserves particularly hard.

He noted that 44.2 per cent of housing on reserves in the province needs significant improvement, which means electricity use tends to be higher to compensate for the lower quality of infrastructure.

Luk says this problem is compounded by the higher rates of poverty in Indigenous populations, with 76 per cent of children on reserves in Manitoba living below the poverty line.

If the increase goes forward, he said the AMC hopes to see a reduced rate for those living on reserves, despite a recent appeal court ruling on such pricing.

Byron Williams, speaking on behalf of the Consumers Coalition, said the 7.9 per cent increase unreasonably favours the interests of Hydro, and is unjustly biased against virtually everyone else.

In Saskatchewan, the NDP criticized an SaskPower 8 per cent rate hike as unfair to customers, highlighting regional concerns.

Williams said customers using electric space heating would be more heavily targeted by the rate increase, facing an extra $13.14 a month as opposed to the $6.88 that would be tacked onto the bills of those not using electric space heating.

Williams also called Hydro’s financial forecasts unreliable, bringing the 7.9 per cent figure into question.

Lawyer George Orle, speaking for the Manitoba Keewatinowi Okimakanak, said the proposed rate hikes would “make a mockery” of the sacrifices made by First Nations across the province, given that so much of Hydro’s infrastructure is on Indigenous land.

The city of Winnipeg also spoke out against the jump, saying property taxes could rise or services could be cut if the hikes go ahead to compensate for increased, unsustainable electricity costs.

In British Columbia, a BC Hydro 3 per cent increase also moved forward, drawing attention to affordability.

A common theme at the hearing was that Hydro’s request was not backed by facts, and that it was heading towards fear-mongering.

Manitoba Hydro’s CEO begged to differ as he plead his case during the first hearing of a process that is expected to take 10 weeks.

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ComEd Hosting Capacity Map helps Illinois communities assess photovoltaic capacity, distributed energy resources, interconnection limits, and grid planning needs, guiding developers and policymakers on siting solar, net metering feasibility, and RPS-aligned deployment by circuit.

Key Points

An online tool showing circuit-level DER capacity, PV limits, and interconnection readiness across ComEd.

✅ Circuit-level estimates of solar hosting capacity

✅ Guides siting, interconnection, and net metering

✅ Supports RPS goals with grid planning insights

As the Illinois solar market grows from the Future Energy Jobs Act, the largest utility in the state has posted a planning tool to identify potential PV capacity in their service territory. ComEd, a Northern Illinois subsidiary of Exelon, has a hosting capacity website for its communities indicating how much photovoltaic capacity can be sited in given areas, based on the existing electrical infrastructure, as utilities pilot virtual power plant programs that leverage distributed resources.

According to ComEd’s description, “Hosting Capacity is an estimate of the amount of DER [distributed energy resources] that may be accommodated under current configurations at the overall circuit level without significant system upgrades to address adverse impacts to power quality or reliability.” This website will enable developers and local decision makers to estimate how much solar could be installed by township, sections and fractions of sections as small as ½ mile by ½ mile and to gauge EV charging impacts with NREL's projection tool for distribution planning. The map sections indicate potential capacity by AC kilowatts with a link to to ComEd’s recently upgraded Interconnection and Net Metering homepage.

The Hosting Map can provide insight into how much solar can be installed in which locations in order to help solar reach a significant portion of the Illinois Renewable Portfolio Standard (RPS) of 25% electricity from renewable sources by 2025, and to plan for transportation electrification as EV charging infrastructure scales across utility territories. For example, the 18 sections of Oak Park Township capacity range from 612 to 909 kW, and total 13,260 kW of photovoltaic power. That could potentially generate around 20 million kWh, and policy actions such as the CPUC-approved PG&E EV program illustrate how electrification initiatives may influence future demand. Oak Park, according to the PlanItGreen Report Card, a joint project of the Oak Park River Forest Community Foundation and Seven Generations Ahead, uses about 325 million kWh.

Based on ComEd’s Hosting Capacity, Oak Park could generate about 6% of its electricity from solar power located within its borders. Going significantly beyond this amount would likely require a combination of upgrades by ComEd’s infrastructure, potentially higher interconnection costs and deployment of technologies like energy storage solutions. What this does indicate is that a densely populated community like Oak Park would most likely have to get the majority of its solar and renewable electricity from outside its boundaries to reach the statewide RPS goal of 25%. The Hosting Capacity Map shows a considerable disparity among communities in ½ mile by ½ mile sections with some able to host only 100-200 kWs to some with capacities of over 3,000 kW.

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Canada Clean Energy Transition accelerates via carbon pricing, renewables, EV incentives, energy efficiency upgrades, smart grids, interprovincial transmission, and innovation in hydro, wind, solar, and storage to cut emissions and power sustainable growth.

Key Points

Canada Clean Energy Transition is a shift to renewables, EVs and efficiency powered by smart policy and innovation.

✅ Carbon pricing and EV incentives accelerate adoption

✅ Grid upgrades, storage, and transmission expand renewables

✅ Industry efficiency and smart tech cut energy waste

So, how do we get there?

We're already on our way.

The final weeks of 2016 delivered some progress, as Prime Minister Justin Trudeau and premiers of 11 of the 13 provinces and territories negotiated a new national climate plan. The deal is a game changer. It marks the moment that Canada stopped arguing about whether to tackle climate change and started figuring out how we're going to get there.

We can each be part of the solution by reducing the amount of energy we use, making sure our homes and workplaces are well insulated and choosing energy efficient appliances. When the time comes to upgrade our cars, washing machines and refrigerators, we can take advantage of rebates that cut the cost of electric models. In our homes, we can install smart technology — like automated thermostats — to cut down on energy waste and reduce power bills.

Even industries that use a lot of energy, like mining and manufacturing, could become leaders in sustainability. It would mean investing in energy saving technology, making their operations more efficient and running conveyor belts, robots and other equipment off locally produced renewable electricity.

Meanwhile, laboratories and factories in Ontario, Quebec and British Columbia are making breakthroughs in areas like energy storage, while renewable energy growth in the Prairie Provinces gathers momentum, which will make it possible to access clean power even when the sun isn't shining and the wind isn't blowing.

Liberal leader Justin Trudeau holds a copy of his environmental platform after announcing details of it at Jericho Beach Park in Vancouver, B.C., on Monday June 29, 2015. (Darryl Dyck/Canadian Press)

The scale and speed of Canada's transition to clean energy depends on provincial and federal policies that do things like tax carbon pollution, build interprovincial electricity transmission lines, invest in renewable energy and grid modernization projects that strengthen the system, and increase incentives for electric vehicles. 

Of course, even the best policies won't produce lasting results unless Canadians fight for them and take ownership for our role in the energy transition. Global momentum toward clean energy may be "irreversible," as former U.S. President Barack Obama recently wrote in the journal Science — but it's up to us whether Canada catches that wave or misses out.

Fortunately, clean energy has always been part of Canada's DNA.

We can learn from the past

In remote corners of the newly minted Dominion of Canada, rushing rivers turned the waterwheels that powered the lumber mills that built the places we inhabit today. The first electric lights were switched on in Winnipeg shortly after Confederation. By the turn of the 20th century, hydro power was lighting up towns and cities from coast to coast.  

Our country is home to some of the world's best clean energy resources, and experts note that zero-emissions electricity by 2035 is possible given our strengths, and fully two-thirds of our power is generated from renewable sources like hydro, wind and solar.

Looking to our heritage, we can make clean growth the next chapter in Canada's history

Recent commitments to phase out coal and invest in clean energy infrastructure mean the share of renewable power in Canada's energy mix is poised to grow. The global shift from fossil fuels to clean energy is opening up huge opportunities and Canada's opportunity in the global electricity market is growing as the country has the expertise to deliver solutions around the world.

Looking to our heritage, we can make clean growth the next chapter in Canada's history — building a nation that's electric, connected and on a practical, profitable path to 2035 zero-emission power for households and industry, stronger than ever.

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Nuclear Power Construction Milestones spotlight EPR builds, Hualong One steam generators, APR-1400 grid integration, and VVER startups, with hot functional testing, hydrostatic checks, and commissioning advancing toward fuel loading and commercial operation.

Key Points

Key reactor project steps, from testing and grid readiness to startup, marking progress toward safe commercial operation.

✅ EPR units advance through cold and hot functional testing

✅ Hualong One installs 365-ton steam generators at Fuqing 5

✅ APR-1400 and VVER projects progress toward grid connection

The world’s nuclear power industry has been busy in the new year, with several construction projects, including U.S. reactor builds, reaching key milestones as 2018 began.

EPR Units Making Progress

Four EPR nuclear units are under construction in three countries: Olkiluoto 3 in Finland began construction in August 2005, Flamanville 3 in France began construction in December 2007, and Taishan 1 and 2 in China began construction in November 2009. Each of the new units is behind schedule and over budget, but recent progress may signal an end to some of the construction difficulties.

EDF reported that cold functional tests were completed at Flamanville 3 on January 6. The main purpose of the testing was to confirm the integrity of primary systems, and verify that components important to reactor safety were properly installed and ready to operate. More than 500 welds were inspected while pressure was held greater than 240 bar (3,480 psi) during the hydrostatic testing, which was conducted under the supervision of the French Nuclear Safety Authority.

With cold testing successfully completed, EDF can now begin preparing for hot functional tests, which verify equipment performance under normal operating temperatures and pressures. Hot testing is expected to begin in July, with fuel loading and reactor startup possible by year end. The company also reported that the total cost for the unit is projected to be €10.5 billion (in 2015 Euros, excluding interim interest).

Olkiluoto 3 began hot functional testing in December. Teollisuuden Voima Oyj—owner and operator of the site—expects the unit to produce its first power by the end of this year, with commercial operation now slated to begin in May 2019.

Although work on Taishan 1 began years after Olkiluoto 3 and Flamanville 3, it is the furthest along of the EPR units. Reports surfaced on January 2 that China General Nuclear (CGN) had completed hot functional testing on Taishan 1, and that the company expects the unit to be the first EPR to startup. CGN said Taishan 1 would begin commercial operation later this year, with Taishan 2 following in 2019.

Hualong One Steam Generators Installed

Another Chinese project reached a notable milestone on January 8. China National Nuclear Corp. announced the third of three steam generators had been installed at the Hualong One demonstration project, which is being constructed as Unit 5 at the Fuqing nuclear power plant.

The Hualong One pressurized water reactor unit, also known as the HPR 1000, is a domestically developed design, part of China’s nuclear program, based on a French predecessor. It has a 1,090 MW capacity. The steam generators reportedly weigh 365 metric tons and stand more than 21 meters tall. The first steam generator was installed at Fuqing 5 on November 10, with the second placed on Christmas Eve.

Barakah Switchyard Energized

In the United Arab Emirates, more progress has been made on the four South Korean–designed APR-1400 units under construction at the Barakah nuclear power plant. On January 4, Emirates Nuclear Energy Corp. (ENEC) announced that the switchyard for Units 3 and 4 had been energized and connected to the power grid, a crucial step in Abu Dhabi toward completion. Unit 2’s main power transformer, excitation transformer, and auxiliary power transformer were also energized in preparation for hot functional testing on that unit.

“These milestones are a result of our extensive collaboration with our Prime Contractor and Joint Venture partner, the Korea Electric Power Corporation (KEPCO),” ENEC CEO Mohamed Al Hammadi said in a press release. “Working together and benefitting from the experience gained when conducting the same work on Unit 1, the teams continue to make significant progress while continuing to implement the highest international standards of safety, security and quality.”

In 2017, ENEC and KEPCO achieved several construction milestones including installation and concrete pouring for the reactor containment building liner dome section on Unit 3, and installation of the reactor containment liner plate rings, reactor vessel, steam generators, and condenser on Unit 4.

Construction began on the four units (Figure 1) in July 2012, May 2013, September 2014, and September 2015, respectively. Unit 1 is currently undergoing commissioning and testing activities while awaiting regulatory review and receipt of the unit’s operating license from the Federal Authority for Nuclear Regulation, before achieving 100% power in a later phase. According to ENEC, Unit 2 is 90% complete, Unit 3 is 79% complete, and Unit 4 is 60% complete.

VVER Units Power Up

On December 29, Russia’s latest reactor to commence operation—Rostov 4 near the city of Volgodonsk—reached criticality, as other projects like Leningrad II-1 advance across the fleet, and was operated at its minimum controlled reactor power (MCRP). Criticality is a term used in the nuclear industry to indicate that each fission event in the reactor is releasing a sufficient number of neutrons to sustain an ongoing series of reactions, which means the neutron population is constant and the chain reaction is stable.

“The transfer to the MCRP allows [specialists] to carry out all necessary physical experiments in the critical condition of [the] reactor unit (RU) to prove its design criteria,” Aleksey Deriy, vice president of Russian projects for ASE Engineering Co., said in a press release. “Upon the results of the experiments the specialists will decide on the RU powerup.”

Rostov 4 is a VVER-1000 reactor with a capacity of 1,000 MW. The site is home to three other VVER units: Unit 1 began commercial operation in 2001, Unit 2 in 2010, and Unit 3 in 2015.

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US Electricity Sales Decline amid population growth and GDP gains, as DOE links reduced per capita consumption to energy efficiency, warmer winters, appliances, and bulbs, while hotter summers and rising AC demand may offset savings.

Key Points

US electricity sales fell 3% since 2010 despite population and GDP growth, driven by efficiency gains and warmer winters.

✅ DOE links drops to efficiency and warmer winters

✅ Per capita residential use fell about 7% since 2010

✅ Rising AC demand may offset winter heating savings

Since 2010, the United States has grown by 17 million people, and the gross domestic product (GDP) has increased by $3.6 trillion. Yet in that same time span, electricity sales in the United States actually declined by 3%, according to data released by the U.S. Department of Energy (DOE), even as electricity prices rose at a 41-year pace nationwide.

The U.S. decline in electricity sales is remarkable given that the U.S. population increased by 5.8% in that same time span. This means that per capita electricity use fell even more than that; indeed, the Department of Energy pegs residential electricity sales per capita as having declined by 7%, even as inflation-adjusted residential bills rose 5% in 2022 nationwide.

There are likely multiple reasons for this decline in electricity sales. Department of Energy analysts suggest that, at least in part, it is due to increased adoption of energy-efficient appliances and bulbs, like compact fluorescents. Indeed, the DOE notes that there is a correlation between consumer spending on “energy efficiency” and a reduction in per capita electricity sales, while utilities invest more in delivery infrastructure to modernize the grid.

Yet the DOE also notes that states with a greater increase in warm weather days had a corresponding decrease in electricity sales, as milder weather can reduce power demand across years. In southern states, the effect was most dramatic: for instance, from 2010 to 2016, Florida had a 56% decrease in cold weather days that would require heating and as a result, saw a 9% decrease in per capita electricity sales.

The moral is that warm winters save on electricity. But if global temperatures continue to rise, and summers become hotter, too, this decrease in winter heating spending may be offset by the increased need to run air conditioning in the summer, and given how electricity and natural gas prices interact, overall energy costs could shift. Indeed, it takes far more energy to cool a room than it does to heat it, for reasons related to the basic laws of thermodynamics. 

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