EPA Policy to limit telework emerges during pandemic

BC Hydro Cryptocurrency Mining Suspension pauses new grid connections for Bitcoin data centers, preserving electricity for EVs, heat pumps, and industry electrification, as Site C capacity and megawatt demand trigger provincial energy policy review.

Key Points

An 18-month pause on new crypto-mining grid hookups to preserve electricity for EVs, heat pumps, and electrification.

✅ 18-month moratorium on new BC Hydro crypto connections

✅ Preserves capacity for EVs, heat pumps, and industry

✅ 21 pending mines sought 1,403 MW; Site C adds 1,100 MW

New cryptocurrency mining businesses in British Columbia are now temporarily banned from being hooked up to BC Hydro’s electrical grid.

The 18-month suspension on new electricity-connection requests is intended to provide the electrical utility and provincial government with the time needed, a move similar to N.B. Power's pause during a crypto review, to create a permanent framework for any future additional cryptocurrency mining operations.

Currently, BC Hydro already provides electricity to seven cryptocurrency mining operations, and six more are in advanced stages of being connected to the grid, with a combined total power consumption of 273 megawatts. These existing operations, unlike the Siwash Creek project now in limbo, will not be affected by the temporary ban.

The electrical utility’s suspension comes at a time when there are 21 applications to open cryptocurrency mining businesses in BC, even as electricity imports supplement the grid during peaks, which would have a combined total power consumption of 1,403 megawatts — equivalent to the electricity needed for 570,000 homes or 2.3 million battery-electric vehicles annually.

In fact, the 21 cryptocurrency mining businesses would completely wipe out the new electrical capacity gained by building the $16 billion Site C hydroelectric dam, alongside two newly commissioned stations that add supply, which has an output capacity of 1,100 megawatts or enough power for the equivalent of 450,000 homes. Site C is expected to be operational by 2025.

Cryptocurrency mining, such as Bitcoin, use a very substantial amount of electricity to operate high-powered computers around the clock, which perform complex cryptographic and math problems to verify transactions. High electricity needs are the result of not only to run the racks of computers, but to provide extreme cooling given the significant heat produced.

“We are suspending electricity connection requests from cryptocurrency mining operators to preserve our electricity supply for people who are switching to electric vehicles, amid BC Hydro's first call for power in 15 years, and heat pumps, and for businesses and industries that are undertaking electrification projects that reduce carbon emissions and generate jobs and economic opportunities,” said Josie Osborne, the BC minister of energy, mines and low carbon innovation, adding that cryptocurrency mining creates very few jobs for the local economy.

Such businesses are attracted to BC due to the availability of its clean, plentiful, and cheap hydroelectricity, which LNG companies continue to seek for their operations as well.

If left unchecked, the provincial government suggests BC Hydro’s long-term electrical capacity could be wiped out by cryptocurrency mining operations, even as debates over going nuclear persist among residents across the province.

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Power Grid Climate Resilience demands storm hardening, underground power lines, microgrids, batteries, and renewable energy as regulators and utilities confront climate change, sea level rise, and extreme weather to reduce outages and protect vulnerable communities.

Key Points

It is the grid capacity to resist and recover from climate hazards using buried lines, microgrids, and batteries.

✅ Underground lines reduce wind outages and wildfire ignition risk.

✅ Microgrids with solar and batteries sustain critical services.

✅ Regulators balance cost, resilience, equity, and reliability.

Every time a storm lashes the Carolina coast, the power lines on Tonye Gray’s street go down, cutting her lights and air conditioning. After Hurricane Florence in 2018, Gray went three days with no way to refrigerate medicine for her multiple sclerosis or pump the floodwater out of her basement.

What you need to know about the U.N. climate summit — and why it matters
“Florence was hell,” said Gray, 61, a marketing account manager and Wilmington native who finds herself increasingly frustrated by the city’s vulnerability.

“We’ve had storms long enough in Wilmington and this particular area that all power lines should have been underground by now. We know we’re going to get hit.”

Across the nation, severe weather fueled by climate change is pushing aging electrical systems past their limits, often with deadly results. Last year, amid increasing nationwide blackouts, the average American home endured more than eight hours without power, according to the U.S. Energy Information Administration — more than double the outage time five years ago.

This year alone, a wave of abnormally severe winter storms caused a disastrous power failure in Texas, leaving millions of homes in the dark, sometimes for days, and at least 200 dead. Power outages caused by Hurricane Ida contributed to at least 14 deaths in Louisiana, as some of the poorest parts of the state suffered through weeks of 90-degree heat without air conditioning.

As storms grow fiercer and more frequent, environmental groups are pushing states to completely reimagine the electrical grid, incorporating more grid-scale batteries, renewable energy sources and localized systems known as “microgrids,” which they say could reduce the incidence of wide-scale outages. Utility companies have proposed their own storm-proofing measures, including burying power lines underground.

But state regulators largely have rejected these ideas, citing pressure to keep energy rates affordable. Of $15.7 billion in grid improvements under consideration last year, regulators approved only $3.4 billion, according to a national survey by the NC Clean Energy Technology Center — about one-fifth, highlighting persistent vulnerabilities in the grid nationwide.

After a weather disaster, “everybody’s standing around saying, ‘Why didn’t you spend more to keep the lights on?’ ” Ted Thomas, chairman of the Arkansas Public Service Commission, said in an interview with The Washington Post. “But when you try to spend more when the system is working, it’s a tough sell.”

A major impediment is the failure by state regulators and the utility industry to consider the consequences of a more volatile climate — and to come up with better tools to prepare for it. For example, a Berkeley Lab study last year of outages caused by major weather events in six states found that neither state officials nor utility executives attempted to calculate the social and economic costs of longer and more frequent outages, such as food spoilage, business closures, supply chain disruptions and medical problems.

“There is no question that climatic changes are happening that directly affect the operation of the power grid,” said Justin Gundlach, a senior attorney at the Institute for Policy Integrity, a think tank at New York University Law School. “What you still haven’t seen … is a [state] commission saying: 'Isn’t climate the through line in all of this? Let’s examine it in an open-ended way. Let’s figure out where the information takes us and make some decisions.’ ”

In interviews, several state commissioners acknowledged that failure.

“Our electric grid was not built to handle the storms that are coming this next century,” said Tremaine L. Phillips, a commissioner on the Michigan Public Service Commission, which in August held an emergency meeting to discuss the problem of power outages. “We need to come up with a broader set of metrics in order to better understand the success of future improvements.”

Five disasters in four years
The need is especially urgent in North Carolina, where experts warn Atlantic grids and coastlines need a rethink as the state has declared a federal disaster from a hurricane or tropical storm five times in the past four years. Among them was Hurricane Florence, which brought torrential rain, catastrophic flooding and the state’s worst outage in over a decade in September 2018.

More than 1 million residents were left disconnected from refrigerators, air conditioners, ventilators and other essential machines, some for up to two weeks. Elderly residents dependent on oxygen were evacuated from nursing homes. Relief teams flew medical supplies to hospitals cut off by flooded roads. Desperate people facing closed stores and rotting food looted a Wilmington Family Dollar.

“I have PTSD from Hurricane Florence, not because of the actual storm but the aftermath,” said Evelyn Bryant, a community organizer who took part in the Wilmington response.

The storm reignited debate over a $13 billion proposal by Duke Energy, one of the largest power companies in the nation, to reinforce the state’s power grid. A few months earlier, the state had rejected Duke’s request for full repayment of those costs, determining that protecting the grid against weather is a normal part of doing business and not eligible for the type of reimbursement the company had sought.

After Florence, Duke offered a smaller, $2.5 billion plan, along with the argument that severe weather events are one of seven “megatrends” (including cyberthreats and population growth) that require greater investment, according to a PowerPoint presentation included in testimony to the state. The company owns the two largest utilities in North Carolina, Duke Energy Carolinas and Duke Energy Progress.

Vote Solar, a nonprofit climate advocacy group, objected to Duke’s plan, saying the utility had failed to study the risks of climate impacts. Duke’s flood maps, for example, had not been updated to reflect the latest projections for sea level rise, they said. In testimony, Vote Solar claimed Duke was using environmental trends to justify investments “it had already decided to pursue.”

The United States is one of the few countries where regulated utilities are usually guaranteed a rate of return on capital investments, even as studies show the U.S. experiences more blackouts than much of the developed world. That business model incentivizes spending regardless of how well it solves problems for customers and inspires skepticism. Ric O’Connell, executive director of GridLab, a nonprofit group that assists state and regional policymakers on electrical grid issues, said utilities in many states “are waving their hands and saying hurricanes” to justify spending that would do little to improve climate resilience.

In North Carolina, hurricanes convinced Republicans that climate change is real

Duke Energy spokesman Jeff Brooks acknowledged that the company had not conducted a climate risk study but pointed out that this type of analysis is still relatively new for the industry. He said Duke’s grid improvement plan “inherently was designed to think about future needs,” including reinforced substations with walls that rise several feet above the previous high watermark for flooding, and partly relied on federal flood maps to determine which stations are at most risk.

Brooks said Duke is not using weather events to justify routine projects, noting that the company had spent more than a year meeting with community stakeholders and using their feedback to make significant changes to its grid improvement plan.

This year, the North Carolina Utilities Commission finally approved a set of grid improvements that will cost customers $1.2 billion. But the commission reserved the right to deny Duke reimbursement of those costs if it cannot prove they are prudent and reasonable. The commission’s general counsel, Sam Watson, declined to discuss the decision, saying the commission can comment on specific cases only in public orders.

The utility is now burying power lines in “several neighborhoods across the state” that are most vulnerable to wide-scale outages, Brooks said. It is also fitting aboveground power lines with “self-healing” technology, a network of sensors that diverts electricity away from equipment failures to minimize the number of customers affected by an outage.

As part of a settlement with Vote Solar, Duke Energy last year agreed to work with state officials and local leaders to further evaluate the potential impacts of climate change, a process that Brooks said is expected to take two to three years.

High costs create hurdles
The debate in North Carolina is being echoed in states across the nation, where burying power lines has emerged as one of the most common proposals for insulating the grid from high winds, fires and flooding. But opponents have balked at the cost, which can run in the millions of dollars per mile.

In California, for example, Pacific Gas & Electric wants to bury 10,000 miles of power lines, both to make the grid more resilient and to reduce the risk of sparking wildfires. Its power equipment has contributed to multiple deadly wildfires in the past decade, including the 2018 Camp Fire that killed at least 85 people.

PG&E’s proposal has drawn scorn from critics, including San Jose Mayor Sam Liccardo, who say it would be too slow and expensive. But Patricia Poppe, the company’s CEO, told reporters that doing nothing would cost California even more in lost lives and property while struggling to keep the lights on during wildfires. The plan has yet to be submitted to the state, but Terrie Prosper, a spokeswoman for the California Public Utilities Commission, said the commission has supported underground lines as a wildfire mitigation strategy.

Another oft-floated solution is microgrids, small electrical systems that provide power to a single neighborhood, university or medical center. Most of the time, they are connected to a larger utility system. But in the event of an outage, microgrids can operate on their own, with the aid of solar energy stored in batteries.

In Florida, regulators recently approved a four-year microgrid pilot project, but the technology remains expensive and unproven. In Maryland, regulators in 2016 rejected a plan to spend about $16 million for two microgrids in Baltimore, in part because the local utility made no attempt to quantify “the tangible benefits to its customer base.”

Amid shut-off woes, a beacon of energy

In Texas, where officials have largely abandoned state regulation in favor of the free market, the results have been no more encouraging. Without requirements, as exist elsewhere, for building extra capacity for times of high demand or stress, the state was ill-equipped to handle an abnormal deep freeze in February that knocked out power to 4 million customers for days.

Since then, Berkshire Hathaway Energy and Starwood Energy Group each proposed spending $8 billion to build new power plants to provide backup capacity, with guaranteed returns on the investment of 9 percent, but the Texas legislature has not acted on either plan.

New York is one of the few states where regulators have assessed the risks of climate change and pushed utilities to invest in solutions. After 800,000 New Yorkers lost power for 10 days in 2012 in the wake of Hurricane Sandy, state regulators ordered utility giant Con Edison to evaluate the state’s vulnerability to weather events.

The resulting report, which estimated climate risks could cost the company as much as $5.2 billion by 2050, gave ConEd data to inform its investments in storm hardening measures, including new storm walls and submersible equipment in areas at risk of flooding.

Meanwhile, the New York Public Service Commission has aggressively enforced requirements that utility companies keep the lights on during big storms, fining utility providers nearly $190 million for violations including inadequate staffing during Tropical Storm Isaias in 2020.

“At the end of the day, we do not want New Yorkers to be at the mercy of outdated infrastructure,” said Rory M. Christian, who last month was appointed chair of the New York commission.

The price of inaction
In North Carolina, as Duke Energy slowly works to harden the grid, some are pursuing other means of fostering climate-resilient communities.

Beth Schrader, the recovery and resilience director for New Hanover County, which includes Wilmington, said some of the people who went the longest without power after Florence had no vehicles, no access to nearby grocery stores and no means of getting to relief centers set up around the city.

For example, Quanesha Mullins, a 37-year-old mother of three, went eight days without power in her housing project on Wilmington’s east side. Her family got by on food from the Red Cross and walked a mile to charge their phones at McDonald’s. With no air conditioning, they slept with the windows open in a neighborhood with a history of violent crime.

Schrader is working with researchers at the University of North Carolina in Charlotte to estimate the cost of helping people like Mullins. The researchers estimate that it would have cost about $572,000 to provide shelter, meals and emergency food stamp benefits to 100 families for two weeks, said Robert Cox, an engineering professor who researches power systems at UNC-Charlotte.

Such calculations could help spur local governments to do more to help vulnerable communities, for example by providing “resilience outposts” with backup power generators, heating or cooling rooms, Internet access and other resources, Schrader said. But they also are intended to show the costs of failing to shore up the grid.

“The regulators need to be moved along,” Cox said.

In the meantime, Tonye Gray finds herself worrying about what happens when the next storm hits. While Duke Energy says it is burying power lines in the most outage-prone areas, she has yet to see its yellow-vested crews turn up in her neighborhood.

“We feel,” she said, “that we’re at the end of the line.”

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AIDAsol shore power Rostock-Warnemfcnde delivers cold ironing for cruise ships, up to 20 MVA at berths P7 and P8, cutting port emissions during berthing and advancing AIDA's green cruising strategy across European ports.

Key Points

Rostock-Warnemfcnde shore power supplies two cruise ships up to 20 MVA, enabling cold ironing and cutting emissions.

✅ Up to 20 MVA; powers two cruise ships at berths P7 and P8

✅ Enables cold ironing for AIDA fleet to reduce berth emissions

✅ Part of AIDA green cruising with fuel cells and batteries

In a ceremony held in Rostock-Warnemünde yesterday during Germany’s 12th National Maritime Conference, the 2,174-passenger cruise ship AIDAsol inaugurated Europe’s largest shore power plants for ships.

The power plant has been established under a joint agreement between AIDA Cruises, a unit of Carnival Corporation & plc (NYSE/LSE: CCL; NYSE: CUK), the state government of Mecklenburg-Western Pomerania, the city of Rostock and the Port of Rostock.

“With our green cruising strategy, we have been investing in a sustainable cruise market for many years,” said AIDA Cruises President Felix Eichhorn. “The shore power plant in Rostock-Warnemünde is another important step — after the facility in Hamburg — on our way to an emission-neutral cruise that we want to achieve with our fleet. I would like to thank the state government of Mecklenburg-Western Pomerania and all partners involved for the good and trusting cooperation. Together, we are sending out an important signal, not just in Germany, but throughout Europe.”

CAN POWER TWO CRUISE SHIPS AT A TIME
The shore power plant, which was completed in summer 2020, is currently the largest in Europe and aligns with port electrification efforts such as the all-electric berth at London Gateway in the UK. With an output of up to 20 megavolt amperes (MVA), two cruise ships can be supplied with electricity at the same time at berths P7 and P8 in Warnemünde.

In regular passenger operation AIDAsol needs up to 4.5 megawatts per hour (MWh) of electricity.

The use of shore power to supply ships with energy is a decisive step in AIDA Cruises’ plans to reduce local emissions to zero during berthing, complementing recent progress with electric ships on the B.C. coast, as a cruise ship typically stays in port around 40% of its operating time.

As early as 2004, when the order for the construction of AIDAdiva was placed, and for all other ships put into service in subsequent years, the company has considered the use of shore power as an option for environmentally friendly ship operation.

Since 2017, AIDA Cruises has been using Europe’s first shore power plant in Hamburg-Altona, where AIDAsol is in regular operation, while operators like BC Ferries add hybrid ferries to expand low-emission service in Canada. Currently, 10 ships in the AIDA fleet can either use shore power where available or are technically prepared for it.

The aim is to convert all ships built from 2000 onwards, supporting future solutions like offshore charging with wind power.

With AIDA Cruises starting a cruise season from Kiel, Germany, on May 22, AIDAsol will also be the first cruise ship to complete the final tests on a newly built shore power plant there, as innovations such as Berlin’s electric flying ferry highlight the broader shift toward electrified waterways. Construction of that plant is the result of a joint initiative by the state government of Schleswig-Holstein, the city and the port of Kiel and AIDA Cruises. AIDAsol is scheduled to arrive in Kiel on the afternoon of May 13.

As part of its green cruising strategy, AIDA Cruises has been investing in a sustainable cruise operation for many years, paralleling urban shifts toward zero-emission bus fleets in Berlin. Other steps on the path to the zero emission ship of the future are already in preparation. This year, AIDAnova will receive the first fuel cell to be used on an ocean-going cruise ship. In 2022, the largest battery storage system to date in cruise shipping will go into operation on board an AIDA ship, similar to advances in battery-electric ferries in the U.S. In addition, the company is already addressing the question of how renewable fuels can be used on board cruise ships in the future.

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UK Electricity Interconnectors secure capacity market subsidies, supporting winter reliability with seabed cables to France and Belgium via the Channel Tunnel, lowering consumer costs, squeezing coal, and challenging new gas plants through cross-border energy trading.

Key Points

High-voltage cables linking Britain to Europe, securing backup capacity, cutting costs and boosting winter reliability.

✅ Won capacity market contracts at record-low prices

✅ Cables to France and Belgium via Channel Tunnel, seabed routes

✅ Squeezes coal, challenges new gas; renewables may join market

New electricity cables across the Channel to France and Belgium will be a key part of keeping Britain’s lights on during winter amid record electricity prices across Europe in the early 2020s, after their owners won backup power subsidies in a government auction this week.

For the first time, interconnector operators successfully bid for a slice of hundreds of millions’ worth of contracts in the capacity market. That will help cut costs for consumers, given how electricity is priced in Europe today, and squeeze out old coal power plants.

Three new interconnectors are currently being built to Europe, almost doubling existing capacity, with one along the Channel Tunnel and two on the seabed: one between Kent and Zeebrugge and one from Hampshire to Normandy. 

The interconnectors were success stories in this week’s capacity auction, which saw power firms bid to provide backup electricity in the winter of 2021/22. Prices for the four-year contracts hit a record low of £8.40 per kilowatt per year, which analysts described as a shock and well below expectations.

One industry source said the figure was “miles away” from what is needed to encourage companies to build big new gas power stations, which some argue are necessary to fill the gap when the UK’s ageing nuclear reactors close as Europe loses nuclear power across the region over the next decade.

While bad news for those firms, the low price is good for consumers. The subsidies will add about £525m to energy bills, or £5.68 for the average household, compared with £11 for the year before, according to analysts Cornwall Insight.

Existing gas power stations scooped up most of the contracts, but new gas ones lost out, as did several coal plants. Battery storage plants, a standout success in the last auction, fared comparatively poorly after changes to the rules.

Experts at Bernstein bank said the the misses by coal meant that around half the UK’s remaining coal power capacity could close from October 2019, when existing capacity market contracts run out. Chaitanya Kumar, policy adviser at thinktank Green Alliance, said: “Coal’s exit from the UK’s energy system just moved a step closer as coal contracts fell by half compared with last year.”

Tom Edwards, an analyst at Cornwall Insight, said that more interconnectors were likely to bid into future rounds of the capacity market, such as the cable being laid between Norway and the UK. Relying on foreign power supplies was fine, he said, provided Brexit did not make energy trading more difficult and the interconnectors delivered at times of need, where events like Irish grid price spikes illustrate the stress points.

However, one industry source, who wants to see new gas plants built in the UK, said the results showed that the system was not working, amid UK peak power prices that have climbed in recent trading. “That self-sufficiency doesn’t seem to be a priority at a time when we’re breaking away from Europe is a bit weird,” they said.

But the prospects for new gas plants in future rounds of the capacity market look bleak. They will very likely face a new source of competition next year, if energy regulator Ofgem approves a proposal to allow renewables to compete too.

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Nova Scotia Power Rate Increase 2023-2024 approved by the UARB lifts electricity rates 14 percent, citing fuel costs and investments, despite Bill 212; includes ROE 9 percent, decarbonization deferral, and a storm cost recovery rider.

Key Points

An approved UARB rate case raising electricity bills about 14% over 2023-2024, with ROE 9% and cost recovery tools.

✅ UARB approves average 6.9% annual increases for 2023 and 2024.

✅ Maintains 9% ROE; sets storm cost rider trial and decarbonization deferral.

✅ Government opposed via Bill 212, but settlement mostly upheld.

Nova Scotia regulators approved a 14 per cent electricity rate hike on Thursday, defying calls by Premier Tim Houston to reject the increase.

Rates will rise on average by 6.9 per cent each year in 2023 and 2024.

In Newfoundland and Labrador, the NL Consumer Advocate called an 18 per cent electricity rate hike unacceptable amid affordability concerns.

The Nova Scotia Utility and Review Board (UARB) issued a 203-page decision ratifying most of the elements in a settlement agreement reached between Nova Scotia Power and customer groups after Houston's government legislated a rate, spending and profit cap on the utility in November.

The board said approval was in the public interest and the increase is "reasonable and appropriate."

"The board cannot simply disallow N.S. Power's reasonable costs to make rates more affordable. These principles ensure fair rates and the financial health of a utility so it can continue to invest in the system providing services to its customers," the three-member panel wrote.

"While the board can (and has) disallowed costs found to be imprudent or unreasonable, absent such a finding, N.S. Power's costs must be reflected in the rates."

In addition to the 14 per cent hike, the board maintained Nova Scotia Power's current return on equity of 9 per cent, with an earnings band of 8.75 to 9.25 per cent. It agreed in principle to establish a decarbonization deferral account to pay for the retirement of coal plants and related decommissioning costs, and implemented a storm cost recovery rider for a three-year trial period.

The board rejected several items in the agreement, including rolling some Maritime Link transmission capital projects into consumers' rates.

Nova Scotia Power welcomed the ruling in a statement, describing it as "the culmination of an extensive and transparent regulatory process over the past year."

Natural Resources and Renewables Minister Tory Rushton, who has said the government cannot order lower power rates in Nova Scotia, stated the UARB decision was not what the government wanted, but he did not indicate the government has any plans to bring forward legislation to overturn it. 

"We're disappointed by the decision today. We've always been very clear that we were standing by ratepayers right from the get-go but we also respect the independent body of the UARB and their decision today."

Pressure from the province
Houston claimed the settlement breached his government's legislation, known as Bill 212 in Nova Scotia, which he said was intended to protect ratepayers. It capped rates to cover non-fuel costs by 1.8 per cent. It did not cap rates to cover fuel costs or energy efficiency programs.

Bill 212 was passed after the board concluded weeks of public hearings into Nova Scotia Power's request for an electricity rate increase, its first general rate application in 10 years. Nova Scotia Power is a subsidiary of Halifax-based Emera, which is a publicly traded company.

The legislation triggered credit downgrades from two credit rating agencies who said it compromised the independence of the Nova Scotia Utility and Review Board.

In Newfoundland and Labrador, electricity users have begun paying for Muskrat Falls as project costs flow through rates, highlighting broader pressures on Atlantic Canada utilities.

In its decision, the board accepted that legislation was intended to protect ratepayers but did not preclude increases in rates.

"Given the exclusion of fuel and purchased power costs when these were expected to cause significant upward pressure on rates, it also did not preclude large increases in rates. Instead, the protection afforded by the Public Utilities Act amendments appears to be focused on N.S. Power's non-fuel costs, with several amendments targeting N.S. Power's cost of capital and earnings."

The board noted the province was the only intervenor in the rate case to object to the settlement.

Opposition reaction
Rushton said despite the outcome, Bill 212 achieved its goal, which was to protect ratepayers.

"Without Bill 212 the rates would have actually been higher," he said. "It would have double-digit rates for this year and next year and now it's single digits."

NDP Leader Claudia Chender said the end result is that Nova Scotians are still facing "incredibly unaffordable power."

Similar criticism emerged in Saskatchewan after an 8 per cent SaskPower increase, which the NDP opposed during provincial debates.

"It's really unfortunate for a lot of Nova Scotians who are heading into a freezing weekend where heat is not optional."

Chender said a different legislative approach is needed to change the regulatory system, and more needs to be done to help people pay their electricity bills.

Liberal MLA Kelly Regan echoed that sentiment.

"There are lots of people who can absorb this. There are a lot of people who cannot, and those are the people that we should be worried about right now. This is why we've been saying all along the government needs to actually give money directly to Nova Scotians who need help with power rates."

Rushton said the government has introduced programs to help Nova Scotians pay for heat, including raising the income threshold to access the Heating Assistance Rebate Program and creating incentives to install heat pumps.

Elsewhere, some governments have provided a lump-sum credit on electricity bills to ease short-term costs for households.

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TransLink Electric Bus Pilot launches zero-emission service in Metro Vancouver, cutting greenhouse gas emissions with fast-charging stations on Route 100, supporting renewable energy goals alongside trolley buses, CNG, and hybrid fleets.

Key Points

TransLink's Metro Vancouver program deploying charging, zero-emission buses on Route 100 to cut emissions and fuel costs.

✅ Cuts ~100 tonnes GHG and saves $40k per bus annually

✅ Five-minute on-route charging at terminals on Route 100

✅ Pilot data to guide zero-emission fleet transition by 2050

TransLink's first battery-electric buses are taking to the roads in Metro Vancouver as part of a pilot project to reduce emissions, joining other initiatives like electric school buses in B.C. that aim to cut pollution in transportation.

The first four zero-emission buses picked up commuters in Vancouver, Burnaby and  New Westminster on Wednesday. Six more are expected to be brought in, and similar launches like Edmonton's first electric bus are underway across Canada.

"With so many people taking transit in Vancouver today, electric buses will make a real difference," said Merran Smith, executive director of Clean Energy Canada, a think tank at Simon Fraser University, in a release.

According to TransLink, each bus is expected to reduce 100 tonnes of greenhouse gas emissions and save $40,000 in fuel costs per year compared to a conventional diesel bus.

"Buses already help tackle climate change by getting people out of cars, and Vancouver is ahead of the game with its electric trolleys," Smith said.

She added there is still more work to be done to get every bus off diesel, as seen with the TTC's battery-electric buses rollout in Toronto.

The buses will run along the No. 100 route connecting Vancouver and New Westminster. They recharge — it takes about five minutes — at new charging stations installed at both ends of the route while passengers load and unload or while the driver has a short break. 

Right now, more than half of TransLink's fleet currently operates with clean technology, offering insights alongside Toronto's large battery-electric fleet for other cities. 

In addition to the four new battery-electric buses, the fleet also includes hundreds of zero-emission electric trolley buses, compressed natural gas buses and hybrid diesel-electric buses, while cities like Montreal's first STM electric buses continue to expand adoption.

"Our iconic trolley buses have been running on electricity since 1948 and we're proud to integrate the first battery-electric buses to our fleet," said TransLink CEO Kevin Desmond in a press release.

TransLink has made it a goal to operate its fleet with 100 per cent renewable energy in all operations by 2050. Desmond says, the new buses are one step closer to meeting that goal.

The new battery-electric buses are part of a two-and-a-half year pilot project that looks at the performance, maintenance, and customer experience of making the switch to electric, complementing BC Hydro's vehicle-to-grid pilot initiative underway in the province.

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