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Manitoba Electrification History charts arc lights, hydroelectric dams, Winnipeg utilities, transmission lines, rural electrification, and Manitoba Hydro to today's wind, solar, and EV transition across the provincial power grid, driving modernization and reliability.

Key Points

Manitoba's power evolution from arc lights to hydro and rural electrification, advancing wind and solar on a modern grid.

✅ 1873 Winnipeg arc light predates Edison and Bell.

✅ 1919 Act built transmission lines, rural electrification.

✅ Hydroelectric dams reshaped lands and affected First Nations.

The first electric light in Manitoba was turned on in Winnipeg in 1873, but it was a century ago this year that the switch was flipped on a decision that would bring power to the fingertips of people across the province.

On March 12, 1873, Robert Davis — who owned the Davis House hotel on Main Street, about a block from Portage Avenue — used an electric arc light to illuminate the front of his building, according to A History of Electric Power in Manitoba, published by Manitoba Hydro.

That type of light used an an inert gas in a glass container to create an electric arc between two metal electrodes.

"The lamp in front of the Davis Hotel is quite an institution," a Manitoba Free Press report from the day said. "It looks well and guides the weary traveller to a haven of rest, billiards and hot drinks."

A ladder crew from the Winnipeg Electric Street Railway Company working on an electric trolley line in 1905. (I.F. Allen/Manitoba Hydro archives)

The event took place six years before Thomas Edison's first incandescent lamp was invented and three years before the first complete sentence was spoken over the telephone by Alexander Graham Bell.

"Electrification probably had a bigger influence on the lives of Manitobans than virtually anything else," said Gordon Goldsborough, head researcher with the Manitoba Historical Society.

"It's one of the most significant changes in the lives of Manitobans ever, because basically it transformed so many aspects of their lives. It wasn't just one thing — it touched pretty much every aspect of life."

Winnipeg gets its 1st street lamps

In the pioneer days of lighting and street railway transportation in Winnipeg, multiple companies formed in an effort to take advantage of the new utility: Winnipeg Gas Company, Winnipeg General Power Company, Manitoba Electric and Gas Light Company, and The North West Electric Light and Power Company.

In October 1882, the first four street lamps, using electric arc lights, were turned on along Main Street from Broadway to the CPR crossing over the Assiniboine River.

They were installed privately by P.V. Carroll, who came from New York to establish the Manitoba Electric Light & Power Company and try to win a contract for illuminating the rest of the city's streets.

He didn't get it. Newspaper reports from the time noted many outages and other problems and general disappointment in the quality of the light.

Instead, the North West Electric Light and Power Company won that contract and in June 1883 it lit up the streets.

Workers erect a wooden hydro pole beside the Belmont Hotel in 1936. Belmont is a small community southeast of Brandon. (Manitoba Hydro archives)

Over the years, other companies would bring power to the city as it became more reliable, including the Winnipeg Electric Street Railway Company (WERCo), which built the streetcar system and sold electric heat, light and power.

But it was the Brandon Electric Light Company that first tapped into a new source of power — hydro. In 1900, a dam was built across the Minnedosa River (now known as the Little Saskatchewan River) in western Manitoba, and the province's first hydroelectric generating station was created.

The first transmission line was also built, connecting the station with Brandon.

By 1906, WERCo had taken over the Winnipeg General Power Company and the Manitoba Electric and Gas Light Company, and changed its name to the Winnipeg Electric Railway Company. Later, it became the Winnipeg Electric Company, or WECo.

It also took a cue from Brandon, building a hydroelectric plant to provide more power. The Pinawa dam site operated until 1951 and is now a provincial park.

The Minnedosa River plant was the first hydroelectric generating station in Manitoba. (Manitoba Hydro archives)

The City of Winnipeg Hydroelectric System was also formed in 1906 as a public utility to combat the growing power monopoly held by WECo, and to get cheaper power. The city had been buying its supply from the private company "and the City of Winnipeg didn't quite like that price," said Bruce Owen, spokesman for Manitoba Hydro.

So the city funded and built its own dam and generating station site on the Winnipeg River in Pointe du Bois — about 125 kilometres northeast of Winnipeg — which is still in operation today.

"All of a sudden, not only did we have street lights … businesses had lights, power was supplied to homes, people no longer had to cook on wood stoves or walk around with kerosene lanterns. This city took off," said Owen.

"It helped industry grow in the city of Winnipeg. Within a few short years, a second plant had to be built, at Slave Falls."

Lighting up rural Manitoba

While the province's two biggest cities enjoyed the luxury of electricity and the conveniences it brought, the patchwork of power suppliers had also created a jumble of contracts with differing rates and terms, spurring periodic calls for a western Canadian electricity grid to improve coordination.

Meanwhile, most of rural Manitoba remained in the dark.

The Pinawa Dam was built by the Winnipeg Electric Street Railway Company in 1906 and operated until 1951. (Manitoba Hydro archives)

The Pinawa Dam site now, looking like some old Roman ruins. (Darren Bernhardt/CBC)

That began to change in 1919 when the Manitoba government passed the Electric Power Transmission Act, with the aim of supplying rural Manitoba with electrical power. The act enabled the construction of transmission lines to carry electricity from the Winnipeg River generating stations to communities all over southern Manitoba.

It also created the Manitoba Power Commission, predecessor to today's Manitoba Hydro, to purchase power from the City of Winnipeg — and later WECo — to supply to those other communities.

The first transmission line, a 97-kilometre link between Winnipeg and Portage la Prairie, opened in late 1919, and modern interprovincial projects like Manitoba-Saskatchewan power line funding continue that legacy today. The power came from Pointe du Bois to a Winnipeg converter station that still stands at the corner of Stafford Street and Scotland Avenue, then went on to Portage la Prairie.

"That's the remarkable thing that started in 1919," said Goldsborough.

Every year after that, the list of towns connected to the power grid became longer "and gradually, over the early 20th century, the province became electrified," Goldsborough said.

"You'd see these maps that would spider out across the province showing the [lines] that connected each of these communities — a precursor to ideas like macrogrids — to each other, and it was really quite remarkable."

By 1928, 33 towns were connected to the Manitoba Power Commission grid. That rose to 44 by 1930 and 140 by 1939, according to the Manitoba Historical Society.

Power on the farm

Still, one group who could greatly use electricity for their operations — farmers — were still using lanterns, steam and coal for light, heat and power.

"The power that came to the [nearest] town didn't extend to them," said Goldsborough.

It was during the Second World War, as manual labour was hard to come by on farms, that the Manitoba Power Commission recognized the gap in its grid.

It met with farmers to explain the benefits electricity could bring and surveyed their interest. When the war ended in 1945, the farm electrification process got underway.

Employees, their spouses, and children pose for a photo outside of Great Falls generating station in 1923. (Manitoba Hydro archives)

Farmers were taught wiring techniques and about the use of motors for farm equipment, as well as about electric appliances and other devices to ease the burden of domestic life.

"The electrification of the 1940s and '50s absolutely revolutionized rural life," said Goldsborough.

"Farmers had to provide water for all those animals and in a lot of cases [prior to electrification] they would just use a hand pump, or sometimes they'd have a windmill. But these were devices that weren't especially reliable and they weren't high capacity."

Electric motors changed everything, from pumping water to handling grain, while electric heat provided comfort to both people and animals.

Workers build a hydro transmission line tower in an undated photo from Manitoba Hydro. (Manitoba Hydro archives)

"Now you could have heat lamps for your baby chickens. They would lose a lot of chickens normally, because they would simply be too cold," Goldsborough said.

Keeping things warm was important, but so too was refrigeration. In addition to being able to store meat in summer, it was "something to prolong the life of dairy products, eggs, anything," said Manitoba Hydro's Owen.

"It's all the things we take for granted — a flick of a switch to turn the lights on instead of walking around with a lantern, being able to have maybe a bit longer day to do routine work because you have light."

Agriculture was the backbone of the province but it was limited without electricity, said Owen.

Connecting it to the grid "brought it into the modern age and truly kick-started it to make it a viable part of our economy," he said. "And we still see that today."

In 1954, when the farm electrification program ended, Manitoba was the most wired of the western provinces, with 75 per cent of farms and 100,000 customers connected.

The success of the farm electrification program, combined with the post-war boom, brought new challenges, as the existing power generation could not support the new demand.

The three largest players — City Hydro, WECo and the Manitoba Power Commission, along with the provincial government  — created the Manitoba Hydro-Electric Board in 1949 to co-ordinate generation and distribution of power.

A float in a Second World War victory parade represents a hydroelectric dam and the electricity it generates to power cities. (Manitoba Hydro archives)

More hydroelectric generating stations were built and more reorganizations took place. WECo was absorbed by the board and its assets split into separate companies — Greater Winnipeg Gas and Greater Winnipeg Transit.

Its electricity distribution properties were sold to City Hydro, which became the sole distributor in central Winnipeg. The Manitoba Power Commission became sole distributor of electricity in the suburbs and the rest of Manitoba.

Impacts on First Nations

Even as the lives of many people in the province were made easier by the supply of electricity, many others suffered from negative impacts in the rush of progress.

Many First Nations were displaced by hydro dams, which flooded their ancestral lands and destroyed their traditional ways of life.

"And we hear stories about the potential abuses that occurred," said Goldsborough. "So you know, there are there pluses but there are definitely minuses."

In the late 1950s, the Manitoba Power Commission continued to grow and expand its reach, this time moving into the north by buying up private utilities in The Pas and Cranberry Portage.

In 1961, the provincial government merged the commission with the Manitoba Hydro-Electric Board to create Manitoba Hydro.

In 1973, 100 years after the first light went on at that Main Street hotel, the last of the independent power utilities in the province — the Northern Manitoba Power Company Ltd. — was taken over by Hydro.

Winnipeg Hydro, previously called City Hydro, joined the fold in 2002.

Today, Manitoba Hydro operates 15 generating stations and serves 580,262 electric power customers in the province, as well as 281,990 natural gas customers.

New era

And now, as happened in 1919, a new era in electricity distribution is emerging as alternative sources of power — wind and solar — grow in popularity, and as communities like Fort Frances explore integrated microgrids for resilience.

"There's a bit of a clean energy shift happening," said Owen, adding use of biomass energy — energy production from plant or animal material — is also expanding.

"And there's a technological change going on and that's the electrification of vehicles. There are only really several hundred [electric vehicles] in Manitoba on the streets right now. But we know at some point, with affordability and reliability, there'll be a switch over and the gas-powered internal combustion engine will start to disappear."

'We're just a little behind here': Manitoba electric vehicle owners call for more charging stations

That means electrical utilities around the world are re-examining their capabilities, as climate change increasingly stresses grids, said Owen.

"It's coming [and we need to know], are we in a position to meet it? What will be the demands on the system on a path to a net-zero grid by 2050 nationwide?" he said.

"It may not come in my lifetime, but it is coming."

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Millstone COVID-19 safety concerns center on a nuclear refueling outage in Connecticut, temporary workers, OSHA complaints, PPE shortages, and disinfecting protocols, as Dominion Energy addresses virus precautions, staffing, and cybersecurity for safe voting infrastructure.

Key Points

Employee and union claims about PPE, cleaning, and OSHA compliance during a refueling outage at the nuclear plant.

✅ 10 positive cases; 750 temporary workers during refueling outage

✅ Union cites PPE gaps, partitions, and disinfectant effectiveness

✅ Dominion Energy notes increased cleaning, communication, staffing

Workers at Connecticut's only nuclear power plant worry that managers are not taking enough precautions against the coronavirus, as some utilities weigh on-site staffing measures to maintain operations, after 750 temporary employees were brought in to help refuel one of the two active reactors.

Ten employees at the Millstone Power Station in Waterford have tested positive for the virus, and, amid a U.S. grid pandemic warning, the arrival of the temporary workers alarms some of the permanent employees, The Day newspaper reported Sunday.

"Speaking specifically for the guard force, there's a lot of frustration, there's a lot of concern, and I would say there's anger," said Millstone security officer Jim Foley.

Foley, vice president of the local chapter of the United Government Security Officers of America, noted broader labor concerns such as unpaid wages for Kentucky miners while saying security personnel have had to fight for personal protective equipment and for partitions at access points to separate staff from security.

Foley also has filed a complaint with the Occupational Safety and Health Administration saying Millstone staff are using ineffective cleaning materials and citing a lack of cleaning and sanitizing, as telework limits at the EPA drew scrutiny during the pandemic, he said.

Officials at Millstone, owned by Dominion Energy, have not heard internal criticism about the plant's virus precautions, Millstone spokesman Kenneth Holt said.

"We've actually gotten a lot of compliments from employees on the steps we've taken," he said. "We've stepped up communications with employees to let them know what's going on."

As another example of communication efforts, COVID-19 updates at Site C have been published to keep workers informed.

Millstone recently increased cleaning staff on the weekends, Holt said, and there is regular disinfecting at the plant.

Separately, utility resilience remains a concern, as extended outages for tornado survivors in Kentucky may last weeks, affecting essential services.

Responding to the complaint about ineffective cleaning materials, Holt said staff members early in the pandemic went to a Home Depot and got a bottle of disinfectant that wasn't approved by the federal government as effective against the coronavirus. An approved disinfectant was brought in the next day, he said.

The deaths of nearly 2,500 Connecticut residents have been linked to COVID-19, the disease caused by the virus. More than 29,000 state residents have tested positive. As of Sunday, hospitalizations had declined for 11 consecutive days, to over 1,480.

With more people working remotely, utilities have reported higher residential electricity use during the pandemic, affecting household bills.

For most people, the coronavirus causes mild or moderate symptoms, such as fever and cough, that clear up in two to three weeks. For some, especially older adults and people with existing health problems, it can cause more severe illness, including pneumonia, and death.

In other developments related to the coronavirus:

SAFE VOTING

Secretary of the State Denise Merrill released a plan Monday aimed at making voting safe during the Aug. 11 primary and Nov. 3 general election.

Merrill said her office is requiring all cities and towns in the state to submit plans for the two elections that include a list of cleaning and safety products to be used, a list of polling locations, staffing levels at each polling location, and the names of polling workers and moderators.

Municipalities will be eligible for grants to cover the extra costs of holding elections during a pandemic, including expenses for cleaning products and increased staffing.

Merrill also announced her office and the Connecticut National Guard will perform a high-level cybersecurity assessment of the election infrastructure of all 169 towns in the state to guard against malicious actors.

Merrill's office also will provide network upgrades to the election infrastructures of 20 towns that have had chronic problems with connecting to the elections system.

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UK Energy Price Cap Cut 2024 signals relief as wholesale gas prices fall; Ofgem price cap drops per Cornwall Insight, aided by LNG supply, mild winter, despite Red Sea tensions and Ukraine conflict impacts.

Key Points

A forecast cut to Great Britain's Ofgem price cap as wholesale gas falls, easing typical annual household bills in 2024.

✅ Cap falls from £1,928 to £1,620 in April 2024

✅ Forecast £1,497 in July, then about £1,541 from October

✅ Drivers: lower wholesale gas, LNG supply, mild winter

Households in Great Britain are set to experience a significant reduction in energy costs this spring, with bills projected to drop by over £300 annually. This decrease is primarily due to a decline in wholesale gas prices, offering some respite to those grappling with the cost of living crisis.

Cornwall Insight, a well-regarded industry analyst, predicts a 16% reduction in average bills from the previous quarter, potentially reaching the lowest levels since the onset of the Ukraine conflict.

The industry’s price cap, indicative of the average annual bill for a typical household, is expected to decrease from the current £1,928, set earlier this month, to £1,620 in April – a reduction of £308 and £40 less than previously forecasted in December, as ministers consider ending the gas-electricity price link to improve market resilience.

Concerns about escalating tensions in the Red Sea, where Houthi rebels have disrupted global shipping, initially led analysts to fear an increase in wholesale oil prices and subsequent impact on household energy costs.

Contrary to these concerns, oil prices have remained relatively stable, and European gas reserves have been higher than anticipated during a mild winter, with European gas prices returning to pre-Ukraine war levels since November.

Cornwall Insight anticipates that energy prices will continue to be comparatively low through 2024. They predict a further decline to £1,497 for a typical annual bill from July, followed by a slight increase to £1,541 starting in October.

This forecast is a welcome development for Britons who have been dealing with increased expenses across various sectors, from food to utilities, amidst persistently high inflation rates, with energy-driven EU inflation hitting lower-income households hardest across member states.

Energy bills saw a steep rise in 2021, which escalated further due to the Ukraine conflict in 2022, driving up wholesale gas prices. This surge prompted government intervention to subsidize bills, with the UK price cap estimated to cost around £89bn to the public purse, capping costs to a typical household at £2,500.

Cornwall Insight noted that the supply of liquified natural gas to Europe had not been as adversely affected by the Red Sea disruptions as initially feared. Moreover, the UK has been well-supplied with gas from the US, which has become a more significant supplier since the Ukraine war, even as US electricity prices have risen to multi-decade highs. Contributing factors also include lower gas prices in Asia, mild weather, and robust gas availability.

Craig Lowrey, a principal consultant at Cornwall Insight, remarked that concerns about Red Sea events driving up energy prices have not materialized, allowing households to expect a reduction in prices.

On Monday, the next-month wholesale gas price dropped by 4% to 65p a therm.

However, Lowrey cautioned that a complete return to pre-crisis energy bill levels remains unlikely due to ongoing market impacts from shifting away from Russian energy sources and persistent geopolitical tensions, as well as policy changes such as Britain’s Energy Security Bill shaping market reforms.

Richard Neudegg, director of regulation at Uswitch, welcomed the potential further reduction of the price cap in April. However, he pointed out that this offers little solace to households currently struggling with high winter energy costs during the winter. Neudegg urged Ofgem, the energy regulator, to prompt suppliers to reintroduce more competitive and affordable fixed-price deals.

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Ontario Hydro Crisis highlights soaring electricity rates, costly subsidies, nuclear refurbishments, and stalled renewables in Ontario. Policy missteps, weak planning, and rising natural gas emissions burden ratepayers while energy efficiency and storage remain underused.

Key Points

High power costs and subsidies from policy errors, nuclear refurbishments, stalled efficiency and renewables in Ontario.

✅ $5.6B yearly subsidy masks electricity rates and deficits

✅ Nuclear refurbishments embed rising costs for decades

✅ Efficiency, storage, and DERs stalled amid weak planning

By Mark Winfield

While the troubled Site C and Muskrat Falls hydroelectric dam projects in B.C. and Newfoundland and Labrador have drawn a great deal of national attention over the past few months, Ontario has quietly been having a hydro crisis of its own.

One of the central promises in the 2018 platform of the Ontario Progressive Conservative party was to “clean up the hydro mess,” and then-PC leader Doug Ford vowed to fire Hydro One's leadership as part of that effort. There certainly is a mess, with the costs of subsidies taken from general provincial revenues to artificially lower hydro rates nearing $7 billion annually. That is a level approaching the province’s total pre-COVID-19 annual deficit. After only two years, that will also exceed total expected cost overruns of the Site C and Muskrat Falls projects, currently estimated at $12 billion ($6 billion each).

There is no doubt that Doug Ford’s government inherited a significant mess around the province’s electricity system from the previous Liberal governments of former premiers Dalton McGuinty and Kathleen Wynne. But the Ford government has also demonstrated a remarkable capacity for undoing the things its predecessors had managed to get right while doubling down on their mistakes.

The Liberals did have some significant achievements. Most notably: coal-fired electricity generation, which constituted 25 per cent of the province’s electricity supply in the early 2000s, was phased out in 2014. The phaseout dramatically improved air quality in the province. There was also a significant growth in renewable energy production. From  virtually zero in 2003, the province installed 4,500 MW of wind-powered generation, and 450 MW of solar photovoltaic by 2018, a total capacity more than double that of the Sir Adam Beck Generating Stations at Niagara Falls.

At the same time, public concerns over rising hydro rates flowing from a major reconstruction of the province’s electricity system from 2003 onwards became a central political issue in the province. But rather than reconsider the role of the key drivers of the continuing rate increases – namely the massively expensive and risky refurbishments of the Darlington and Bruce nuclear facilities, the Liberals adopted a financially ruinous Fair Hydro Plan. The central feature of the 2017 plan was a short-term 25 per cent reduction in hydro rates, financed by removing the provincial portion of the HST from hydro bills, and by extending the amortization period for capital projects within the system. The total cost of the plan in terms of lost revenues and financing costs has been estimated in excess of $40 billion over 29 years, with the burden largely falling on future ratepayers and taxpayers.

Decision-making around the electricity system became deeply politicized, and a secret cabinet forecast of soaring prices intensified public debate across Ontario. Legislation adopted by the Wynne government in 2016 eliminated the requirement for the development of system plans to be subject to any form of meaningful regulatory oversight or review. Instead, the system was guided through directives from the provincial cabinet. Major investments like the Darlington and Bruce refurbishments proceeded without meaningful, public, external reviews of their feasibility, costs or alternatives.

The Ford government proceeded to add more layers to these troubles. The province’s relatively comprehensive framework for energy efficiency was effectively dismantled in March, 2019, with little meaningful replacement. That was despite strong evidence that energy efficiency offered the most cost-effective strategy for reducing greenhouse gas emissions and electricity costs.

The Ford government basically retained the Fair Hydro Plan and promised further rate reductions, later tabling legislation to lower electricity rates as well. To its credit, the government did take steps to clarify real costs of the plan. Last year, these were revealed to amount to a de facto $5.6 billion-per-year subsidy coming from general revenues, and rising. That constituted the major portion of the province’s $7.4 billion pre-COVID-19 deficit. The financial hole was deepened further through November’s financial statement, with the addition of a further $1.3 billion subsidy to commercial and industrial consumers. The numbers can only get worse as the costs of the Darlington and Bruce refurbishments become embedded more fully into electricity rates.

The government also quietly dispensed with the last public vestige of an energy planning framework, relieving itself of the requirement to produce a Long-Term Energy Plan every three years. The next plan would normally have been due next month, in February.

Even the gains from the 2014 phaseout of coal-fired electricity are at risk. Major increases are projected in emissions of greenhouse gases, smog-causing nitrogen oxides and particulate matter from natural gas-fired power plants as the plants are run to cover electricity needs during the Bruce and Darlington refurbishments over the next decade. These developments could erode as much as 40 per cent of the improvements in air quality and greenhouse gas emission gained through the coal phaseout.

The province’s activities around renewable energy, energy storage and distributed energy resources are at a standstill, with exception of a few experimental “sandbox” projects, while other jurisdictions face profound electricity-sector change and adapt. Globally, these technologies are seen as the leading edge of energy-system development and decarbonization. Ontario seems to have chosen to make itself an energy innovation wasteland instead.

The overall result is a system with little or no space for innovation that is embedding ever-higher costs while trying to disguise those costs at enormous expense to the provincial treasury and still failing to provide effective relief to low-income electricity consumers.

The decline in electricity demand associated with the COVID-19 pandemic, along with the introduction of a temporary recovery rate for electricity, gives the province an opportunity to step back and consider its next steps with the electricity system. A phaseout of the Fair Hydro Plan electricity-rate reduction and its replacement with a more cost-effective strategy of targeted relief aimed at those most heavily burdened by rising hydro rates, particularly rural and low-income consumers, as reconnection efforts for nonpayment have underscored the hardship faced by many households, would be a good place to start.

Next, the province needs to conduct a comprehensive, public review of electricity options available to it, including additional renewables – the costs of which have fallen dramatically over the past decade – distributed energy resources, hydro imports from Quebec and energy efficiency before proceeding with further nuclear refurbishments.

In the longer term, a transparent, evidence-based process for electricity system planning needs to be established – one that is subject to substantive public and regulatory oversight and review. Finally, the province needs to establish a new organization to be called Energy Efficiency Ontario to revive its efforts around energy efficiency, developing a comprehensive energy-efficiency strategy for the province, covering electricity and natural gas use, and addressing the needs of marginalized communities.

Without these kinds of steps, the province seems destined to continue to lurch from contradictory decision after contradictory decision as the economic and environmental costs of the system’s existing trajectory continue to rise.

Mark Winfield is a professor of environmental studies at York University and co-chair of the university’s Sustainable Energy Initiative.

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Port of Vancouver Wind Turbine Blades arrive from China for a Saskatchewan wind farm, showcasing record oversized cargo logistics, tandem crane handling, renewable energy capacity, and North America's longest blades from Goldwind.

Key Points

Record-length blades for a Canadian wind farm, boosting renewable energy and requiring heavy-lift logistics at the port.

✅ 27 blades unloaded via tandem cranes with cage supports

✅ 50 turbines headed to Assiniboia over 21 weeks

✅ Largest 250 ft blades to arrive; reduced CO2 vs coal

A set of 220-foot-long wind turbine blades arrived at the Port of Vancouver from China over the weekend as part a shipment bound for a wind farm in Canada, alongside BC generating stations coming online in the region.

They’re the largest blades ever handled by the port, and this summer, even larger blades will arrive as companies expand production such as GE’s blade factory in France to meet demand — the largest North America has ever seen.

Alex Strogen described the scene as crews used two tandem cranes to unload 27 giant white blades from the MV Star Kilimanjaro, which picked up the wind turbine assemblies in China. They were manufactured by Goldwind Co.

“When you see these things come off and put onto these trailers, it’s exceptional in the sheer length of them,” Strogen said. “It looks as long as an airplane.”

In fact, each blade is about as long as the wingspan of a Boeing 747.

Groups of longshoremen attached the cranes to each blade and hoisted it into the air and onto a waiting truck. Metal cage-like devices on both ends kept the blades from touching the ground. Once loaded onto the trucks, the blades and shaft parts head to a terminal to be unloaded by another group of workers.

Another fleet of trucks will drive the wind turbines, towers and blades to Assiniboia, Saskatchewan, Canada, over the course of 21 weeks. Potentia Renewables of Toronto is erecting the turbines on 34,000 acres of leased agriculture land, amid wind farm expansion in PEI elsewhere in the country, according to a news release from the Port of Vancouver.

Potentia’s project, called the Golden South Wind Project, will generate approximately 900,000 megawatt-hours of electricity. It also has greatly reduced CO2 emissions compared with a coal-fired plant, and complements tidal power in Nova Scotia in Canada’s clean energy mix, according to the news release.

The project is expected to be operating in 2021, similar to major UK offshore wind additions coming online.

The Port of Vancouver will receive 50 full turbines of two models for the project, as Manitoba invests in new turbines across Canada. In August, the larger of the models, with blades measuring 250 feet, will arrive. They’ll be the longest blades ever imported into any port in North America.

“It’s an exciting year for the port,” said Ryan Hart, chief external affairs officer.

The Port of Vancouver is following all the recommended safety precautions during the COVID-19 pandemic, including social distancing and face masks, Strogen said, with support from initiatives like Bruce Power’s PPE donation across Canada.
As for crews onboard the ships, the U.S. Coast Guard is the agency in charge, and it is monitoring the last port-of-call for all vessels seeking to enter the Columbia River, Hart wrote in an email.

Vessel masters on each ship are responsible for monitoring the health of the crew and are required to report sick or ill crew members to the USCG prior to arrival or face fines and potential arrest.

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SaskPower Rate Hike 2022-2023 signals higher electricity rates in Saskatchewan as natural gas costs surge; the Rate Review Panel approved increases, affecting residential utility bills amid affordability concerns and government energy policy shifts.

Key Points

An 8% SaskPower electricity rate increase split 4% in Sept 2022 and 4% in Apr 2023, driven by natural gas costs.

✅ 4% increase Sept 1, 2022; +4% on Apr 1, 2023

✅ Panel-approved amid natural gas price surge and higher fuel costs

✅ Avg residential bill up about $5 per step; affordability concerns

The NDP Opposition is condemning the provincial government’s decision to approve the Saskatchewan Rate Review Panel’s recommendation to increase SaskPower’s rates for the first time since 2018, despite a recent 10% rebate pledge by the Sask. Party.

The Crown electrical utility’s rates will increase four per cent this fall, and another four per cent in 2023, a trajectory comparable to BC Hydro increases over two years. According to a government news release issued Thursday, the new rates will result in an average increase of approximately $5 on residential customers’ bills starting on Sept. 1, 2022, and an additional $5 on April 1, 2023.

“The decision to increase rates is not taken lightly and came after a thorough review by the independent Saskatchewan Rate Review Panel,” Minister Responsible for SaskPower Don Morgan said in a news release, amid Nova Scotia’s 14% hike this year. “World events have caused a significant rise in the price of natural gas, and with 42 per cent of Saskatchewan’s electricity coming from natural gas-fueled facilities, SaskPower requires additional revenue to maintain reliable operations.”

But NDP SaskPower critic Aleana Young says the rate hike is coming just as businesses and industries are struggling in an “affordability crisis,” even as Manitoba Hydro scales back a planned increase next year.

She called the announcement of an eight per cent increase in power bills on a summer day before the long weekend “a cowardly move” by the premier and his cabinet, amid comparable changes such as Manitoba’s 2.5% annual hikes now proposed.

“Not to mention the Sask. Party plans to hike natural gas rates by 17% just days from now,” said Young in a news release issued Friday, as Manitoba rate hearings get underway nearby. “If Scott Moe thinks his choices — to not provide Saskatchewan families any affordability relief, to hike taxes and fees, then compound those costs with utility rate hikes — are defensible, he should have the courage to get out of his closed-door meetings and explain himself to the people of this province.”

The province noted natural gas is the largest generation source in SaskPower’s fleet. As federal regulations require the elimination of conventional coal generation in Canada by 2030, SaskPower’s reliance on natural gas generation is expected to grow, with experts in Alberta warning of soaring gas and power prices in the region. Fuel and Purchased Power expense increases are largely driven by increased natural gas prices, and SaskPower’s fuel and purchased power expense is expected to increase from $715 million in 2020-21 to $1.069 billion in 2023-24. This represents a 50 per cent increase in fuel and purchased power expense over three years.

“In the four years since our last increase SaskPower has worked to find internal efficiencies, but at this time we require additional funding to continue to provide reliable and sustainable power,” SaskPower president & CEO Rupen Pandya said in the release “We will continue to be transparent about our rate strategy and the need for regular, moderate increases.”

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