Winter Olympics are carbon neutral

Hornsea One Offshore Wind Farm delivers first power to the UK grid, scaling renewable energy with 1.2GW capacity, giant offshore turbines, and Yorkshire coast infrastructure to replace delayed nuclear and cut fossil fuel emissions.

Key Points

Hornsea One Offshore Wind Farm is a 1.2GW UK project delivering offshore renewable power to about 1 million homes.

✅ 174 turbines over 407 km2; Siemens Gamesa supply chain in the UK

✅ 1.2GW capacity can power ~1m homes; phases scale with 10MW+ turbines

✅ Supports UK grid, replaces delayed nuclear, cuts fossil generation

An offshore windfarm on the Yorkshire coast that will dwarf the world’s largest when completed is to supply its first power to the UK electricity grid this week, mirroring advances in tidal electricity projects delivering to the grid as well.

The Danish developer Ørsted, which has installed the first of 174 turbines at Hornsea One, said it was ready to step up its plans and fill the gap left by failed nuclear power schemes.

The size of the project takes the burgeoning offshore wind power sector to a new scale, on a par with conventional fossil fuel-fired power stations.

Hornsea One will cover 407 square kilometres, five times the size of the nearby city of Hull. At 1.2GW of capacity it will power 1m homes, making it about twice as powerful as today’s biggest offshore windfarm once it is completed in the second half of this year.

“The ability to generate clean electricity offshore at this scale is a globally significant milestone at a time when urgent action needs to be taken to tackle climate change,” said Matthew Wright, UK managing director of Ørsted, the world’s biggest offshore windfarm builder.

The power station is only the first of four planned in the area, with a green light and subsidies already awarded to a second stage due for completion in the early 2020s, and interest from Japanese utilities underscoring growing investor appetite.

The first two phases will use 7MW turbines, which are taller than London’s Gherkin building.

But the latter stages of the Hornsea development could use even more powerful, 10MW-plus turbines. Bigger turbines will capture more of the energy from the wind and should lower costs by reducing the number of foundations and amount of cabling firms need to put into the water, with developers noting that offshore wind can compete with gas in the U.S. as costs fall.

Henrik Poulsen, Ørsted’s chief executive, said he was in close dialogue with major manufacturers to use the new generation of turbines, some of which are expected to approach the height of the Shard in London, the tallest building in the EU.

The UK has a great wind resource and shallow enough seabed to exploit it, and could even “power most of Europe if it [the UK] went to the extreme with offshore”, he said.

Offshore windfarms could help ministers fill the low carbon power gap created by Hitachi and Toshiba scrapping nuclear plants, the executive suggested. “If nuclear should play less of a role than expected, I believe offshore wind can step up,” he said.

New nuclear projects in Europe had been “dramatically delayed and over budget”, he added, in comparison to “the strong track record for delivering offshore [wind]”.

The UK and Germany installed 85% of new offshore wind power capacity in the EU last year, according to industry data, with wind leading power across several markets. The average power rating of the turbines is getting bigger too, up 15% in 2018.

The turbines for Hornsea One are built and shipped from Siemens Gamesa’s factory in Hull, part of a web of UK-based suppliers that has sprung up around the growing sector, such as Prysmian UK's land cables supporting grid connections.

Around half of the project’s transition pieces, the yellow part of the structure that connects the foundation to the tower, are made in Teeside. Many of the towers themselves are made by a firm in Campbeltown in the Scottish highlands. Altogether, about half of the components for the project are made in the UK.

Ørsted is not yet ready to bid for a share of a £60m pot of further offshore windfarm subsidies, to be auctioned by the government this summer, but expects the price to reach even more competitive levels than those seen in 2017.

Like other international energy companies, Ørsted has put in place contingency planning in event of a no-deal Brexit – but the hope is that will not come to pass. “We want a Brexit deal that will facilitate an orderly transition out of the union,” said Poulsen.

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Grid Modernization drives utilities to integrate DER, AMI, and battery storage while balancing reliability, safety, and affordability; regulators pursue cost-benefit analyses, new rate design, and policy actions to guide investment and protect customer-owned resources.

Key Points

Upgrading the grid to manage DER with digital tools, while maintaining reliability, safety, and customer affordability.

✅ Cost-benefit analyses guide prudent grid investments

✅ AMI and storage deployments enable DER visibility and control

✅ Rate design reforms support customer-owned resources

Utilities’ pursuit of a modern grid, including the digital grid concept, to maintain the reliability and safety pillars of electricity delivery has raised a lot of questions about the third pillar — affordability.

Utilities are seeing rising penetrations of emerging technologies, highlighted in recent grid edge trends reports, like distributed solar, behind-the-meter battery storage, and electric vehicles. These new distributed energy resources (DER) do not eliminate utilities' need to keep distribution systems safe and reliable.

But the need for modern tools to manage DER imposes costs on utilities, prompting calls to invest in smarter infrastructure even as some regulators, lawmakers and policymakers are concerned those costs could drive up electricity rates.

The result is an increasing number of legislative and regulatory grid modernization actions aimed at identifying what is necessary to serve the coming power sector transformation and address climate change risks across the grid.

The rise of grid modernization

Grid modernization, which is supported by both conservatives and distributed energy resources advocates, got a lot of attention last year. According to the 2017 review of grid modernization policy by the North Carolina Clean Energy Technology Center (NCCETC), 288 grid modernization policy actions were proposed, pending or enacted in 39 states.

These numbers from NCCETC's first annual review of policy activity set a benchmark against which future years' activity can be measured.

The most common type of state actions, by far, were those that focused on the deployment of advanced metering infrastructure (AMI) and battery energy storage. Those are two of the 2017 trends identified in NCCETC’s 50 States of Grid Modernization report. But deployment of those technologies, while foundational to an updated grid, only begins to prepare distribution systems for the coming power sector transformation.

Bigger advances, including the newest energy system management tools, are being held back by 2017’s other policy actions requiring more deliberation and fact-finding, even as grid vulnerability report cards underscore the risks that modernization seeks to mitigate.

Utilities’ proposals to more fully prepare their grids to deliver 21st century technologies are being met with questions about completeness and cost.

Utilities are being asked to address these questions in comprehensive, public utility commission-led cost-benefit analyses and studies. This is also one of NCCETC’s top 2017 policy action trends for grid modernization. The outcome to date appears to be an increased, but still incomplete, understanding of what is needed to build a 21st century grid.

Among the top objectives of those driving the policy actions are resolving questions about private sector participation in grid modernizaton buildouts and developing new rate designs to protect and support customer-owned distributed energy resources. Actions on those topics are also on NCCETC’s list of 2017 policy trends.

Altogether, the trend list is dominated by actions that do not lead to completion of grid modernization but to more work on it.

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Western Canada Electric Grid could deliver interprovincial transmission, reliability, peak-load support, reserve sharing, and wind and solar integration, lowering costs versus new generation while respecting AESO markets and Crown utility structures.

Key Points

Interprovincial transmission to share reserves, boost reliability, integrate wind and solar, and cut peak capacity costs.

✅ Cuts reserve margins via diversity of peak loads

✅ Enables wind and solar balancing across provinces

✅ Saves ratepayers vs replacing retiring thermal plants

The 2017 Canadian Free Trade Agreement does not do much to encourage provinces to trade electric energy east and west. Would a western Canada electric grid help electricity consumers in the western provinces? Some Alberta officials feel that their electric utilities are investor owned and they perceive the Crown corporations of BC Hydro, SaskPower and Manitoba Hydro to be subsidized by their provincial governments, so an interprovincial electric energy trade would not be on a level playing field.

Because of the limited trade of electric energy between the western provinces, each utility maintains an excessive reserve of thermal and hydroelectric generation greater than their peak loads, to provide a reliable supply during peak load days as grids are increasingly exposed to harsh weather across Canada. This excess does not include variable wind and solar generation, which within a province can’t be guaranteed to be available when needed most.

This attitude must change. Transmission is cheaper than generation, and coordinated macrogrids can further improve reliability and cut costs. By constructing a substantial grid with low profile and aesthetically designed overhead transmission lines, the excess reserve of thermal and hydroelectric generation above the peak electric load can be reduced in each province over time. Detailed assessments will ensure each province retains its required reliability of electric supply.

As the provinces retire aging thermal and coal-fired generators, they only need to replace them to a much lower level, by just enough to meet their future electric loads and Canada's net-zero grid by 2050 goals. Some of the money not spent in replacing retired generation can be profitably invested in the transmission grid across the four western provinces.

But what about Alberta, which does not want to trade electric energy with the other western provinces? It can carry on as usual within the Alberta Electric System Operator’s (AESO) market and will save money by keeping the installed reserve of thermal and hydroelectric generation to a minimum. When Alberta experiences a peak electric load day and some generators are out of service due to unplanned maintenance, it can obtain the needed power from the interprovincial electric grid. None of the other three western provinces will peak at the same time, because of different weather and time zones, so they will have spare capacity to help Alberta over its peak. The peak load in a province only lasts for a few hours, so Alberta will get by with a little help from its friends if needed.

The grid will have no energy flowing on it for this purpose except to assist a province from time to time when it’s unable to meet its peak load. The grid may only carry load five per cent of the time in a year for this purpose. Under such circumstances, the empty grid can then be used for other profitable markets in electric energy. This includes more effective use of variable wind and solar energy, by enabling a province to better balance such intermittent power as well as allowing increased installation of it in every province. This is a challenge for AESO which the grid would substantially ease.

Natural Resources Canada promoted the “Regional Electricity Co-Operative and Strategic Infrastructure” initiative for completion this year and contracted through AESO, alongside an Atlantic grid study to explore regional improvements. This is a first step, but more is needed to achieve the full benefit of a western grid.

In 1970 a study was undertaken to electrically interconnect Britain with France, which was justified based on the ability to reduce reserve generation in both countries. Initially Britain rejected it, but France was partially supportive. In time, a substantial interconnection was built, and being a profitable venture, they are contemplating increasing the grid connections between them.

For the sake of the western consumers of electricity and to keep electricity rates from rising too quickly, as well as allowing productive expansion of wind and solar energy in places like British Columbia's clean energy shift efforts, an electric grid is essential across western Canada.

Dennis Woodford is president of Electranix Corporation in Winnipeg, which studies electric transmission problems, particularly involving renewable energy generators requiring firm connection to the grid.

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Gaza Electricity Crisis drives severe power cuts in the Gaza Strip, as Hamas-PA tensions and Mahmoud Abbas's supply reductions under blockade spur fuel shortages, hospital strain, and soaring demand for batteries, LED lights, and generators.

Key Points

A prolonged Gaza power shortage from politics, blockade, and fuel cuts, disrupting daily life, hospitals, and water.

✅ Demand surges for batteries, LED lights, and generators

✅ PA cuts to Israel-supplied power deepen shortages

✅ Hospitals, water, and sanitation face critical strain

In Imad Shlayl’s electronics shop in Gaza City, the customers crowding his store are interested in only two products: LED lights and the batteries to power them.

In the already impoverished Gaza Strip, residents have learned to adapt to the fact that electricity is only available for between two and four hours a day.

But fresh anger was sparked when availability was cut further last month, at the request of the Palestinian president, Mahmoud Abbas, in an escalation of his conflict with Hamas, the Islamist group.

The shortages have defined how people live their lives, echoing Europe’s energy crisis in other regions: getting up in the middle of the night, if there is power, to run washing machines or turn on water pumps.

Only the wealthy few have frequent, long-lasting access to electricity, even as U.S. brownout risks highlight grid fragility, to power lights and fans and fridges, televisions and wifi routers, in Gaza’s stifling summer heat.

“We used to sell all sorts of things,” says Shlayl. “But it’s different these days. All we sell is batteries and chargers. Because the crisis is so deep we are selling 100 batteries a day when normally we would sell 20.”

Gaza requires 430 megawatts of power to meet daily demand, but receives only half that. Sixty megawatts are supplied by its solitary power station, now short on fuel, while the rest is provided through the Israel’s power sector and funded by Abbas’s West Bank-based Palestinian Authority (PA).

Abbas’s move to cut supplies to Gaza, which is already under a joint Israeli and Egyptian blockade – now in its 11th year – has quickly made him a hate figure among many Gazans, who question why he is punishing 2 million fellow Palestinians in what appears to be an attempt to force Hamas to relinquish control of the territory.

Though business is good for Shlayl, he is angry at the fresh shortages faced by Gazans which, as pandemic power shut-offs elsewhere have shown, affect all areas of life, from hospital emergency wards to clean water supplies.

“I’ve not done anything to be punished by anyone. It is the worst I can remember but we are expecting it to get worse and worse,” he said. “Not just electricity, but other things as well. We are in a very deep descent.”

As well as cutting electricity, the PA has cut salaries for its employees in Gaza by upwards of 30% , prompting thousands to protest on the streets of Gaza city.

Residents also blame Abbas for a backlog in processing the medical referral process for those needing to travel out of Gaza for treatment, although who is at fault in that issue is less clear cut.

The problems facing Gaza – where high levels of unemployment are endemic – is most obvious in the poorest areas.

In Gaza City’s al-Shati refugee camp, home to the head of Hamas’s political bureau, Ismail Haniyeh, whole housing blocks were dark, while in others only a handful of windows were weakly illuminated.

In the one-room kiosk selling pigeons and chickens that he manages, just off the camp’s main market, Ayman Nasser, 32, is sitting on the street with his friends in search of a sea breeze.

His face is illuminated by the light of his mobile phone. He has one battery-powered light burning in his shop.

“Part of the problem is that we don’t have any news. Who should we blame for this? Hamas, Israelis, Abbas?” he said.

 A Palestinian girl reads by candle light due to power cut at the Jabalia Camp in Gaza City
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 A Palestinian girl reads by candlelight due to a power cut at the Jabalia camp in Gaza City. Photograph: Anadolu Agency/Getty Images
His friend, Ashraf Kashqin, interrupts: “It is all connected to politics, but it is us who is getting played by the two sides.”

If there is a question that all the Palestinians in Gaza are asking, it is what the ageing and remote Abbas hopes to achieve, a dynamic also seen in Lebanon’s electricity disputes, not least whether he hopes the cuts will lead to an insurrection against Hamas following demonstrations linked to the power supply in January.

While a senior official in the Fatah-led government on the West Bank said last month that the aim behind the move by the PA – which has been paying $12m (£9m) a month for the electricity Israel supplies to Gaza – was to “dry up Hamas’s financial resources”, others are dubious about the timing, the motive and the real impact.

Among them are human rights groups, such as Amnesty International, who have warned it could turn Gaza’s long-running crisis into a major disaster already hitting hospitals and waste treatment plants.

“For 10 years the siege has unlawfully deprived Palestinians in Gaza of their most basic rights and necessities. Under the burden of the illegal blockade and three armed conflicts, the economy has sharply declined and humanitarian conditions have deteriorated severely. The latest power cuts risk turning an already dire situation into a full-blown humanitarian catastrophe,” said Magdalena Mughrabi, of the group.

Then there is the question of timing. “Abbas is probably the only one who knows why he is doing this to Gaza,” adds Mohameir Abu Sa’da, a political science professor at Al Azhar University and analyst.

“I honestly don’t buy what he has been saying for the last three months: that he will take exceptional measures against Hamas to put pressure on it to give up control of the Gaza Strip.

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Hydrogen Fuel Cell Crane Port of Vancouver showcases zero-emission RTG technology by DP World, TCA Electric, and partners, using hydrogen-electric fuel cells, battery energy storage, and regenerative capture to decarbonize container handling operations.

Key Points

A retrofitted RTG crane powered by hydrogen fuel cells, batteries, and regeneration to cut diesel use and CO2 emissions.

✅ Dual fuel cell system charges high-voltage battery

✅ Regenerative capture reduces energy demand and cost

✅ Pilot targets zero-emission RTG fleets by 2040

In a groundbreaking move toward sustainable logistics, TCA Electric, a Chilliwack-based industrial electrical contractor, is at the forefront of a pioneering hydrogen fuel cell crane project at the Port of Vancouver. This initiative, led by DP World in collaboration with TCA Electric and other partners, marks a significant step in decarbonizing port operations and showcases the potential of hydrogen technology in heavy-duty industrial applications.

A Vision for Zero-Emission Ports

The Port of Vancouver, Canada's largest port, has long been a hub for international trade. However, its operations have also contributed to substantial greenhouse gas emissions, even as DP World advances an all-electric berth in the U.K., primarily from diesel-powered Rubber-Tired Gantry (RTG) cranes. These cranes are essential for container handling but are significant sources of CO₂ emissions. At DP World’s Vancouver terminal, 19 RTG cranes account for 50% of diesel consumption and generate over 4,200 tonnes of CO₂ annually. 

To address this, the Vancouver Fraser Port Authority and the Province of British Columbia have committed to transforming the port into a zero-emission facility by 2050, supported by provincial hydrogen investments that accelerate clean energy infrastructure across B.C. This ambitious goal has spurred several innovative projects, including the hydrogen fuel cell crane pilot. 

TCA Electric’s Role in the Hydrogen Revolution

TCA Electric's involvement in this project underscores its expertise in industrial electrification and commitment to sustainable energy solutions. The company has been instrumental in designing and implementing the electrical systems that power the hydrogen fuel cell crane. This includes integrating the Hydrogen-Electric Generator (HEG), battery energy storage system, and regenerative energy capture technologies. The crane operates using compressed gaseous hydrogen stored in 15 pressurized tanks, which feed a dual fuel cell system developed by TYCROP Manufacturing and H2 Portable. This system charges a high-voltage battery that powers the crane's electric drive, significantly reducing its carbon footprint. 

The collaboration between TCA Electric, TYCROP, H2 Portable, and HTEC represents a convergence of local expertise and innovation. These companies, all based in British Columbia, have leveraged their collective knowledge to develop a world-first solution in the industrial sector, while regional pioneers like Harbour Air's electric aircraft illustrate parallel progress in aviation. TCA Electric's leadership in this project highlights its role as a key enabler of the province's clean energy transition. 

Demonstrating Real-World Impact

The pilot project began in October 2023 with the retrofitting of a diesel-powered RTG crane. The first phase included integrating the hydrogen-electric system, followed by a one-year field trial to assess performance metrics such as hydrogen consumption, energy generation, and regenerative energy capture rates. Early results have been promising, with the crane operating efficiently and emitting only steam, compared to the 400 kilograms of CO₂ produced by a comparable diesel unit. 

If successful, this project could serve as a model for decarbonizing port operations worldwide, mirroring investments in electric trucks at California ports that target landside emissions. DP World plans to consider converting its fleet of RTG cranes in Vancouver and Prince Rupert to hydrogen power, aligning with its global commitment to achieve carbon neutrality by 2040.

Broader Implications for the Industry

The success of the hydrogen fuel cell crane pilot at the Port of Vancouver has broader implications for the shipping and logistics industry. It demonstrates the feasibility of transitioning from diesel to hydrogen-powered equipment in challenging environments, and aligns with advances in electric ships on the B.C. coast. The project's success could accelerate the adoption of hydrogen technology in other ports and industries, contributing to global efforts to reduce carbon emissions and combat climate change.

Moreover, the collaboration between public and private sectors in this initiative sets a precedent for future partnerships aimed at advancing clean energy solutions. The support from the Province of British Columbia, coupled with the expertise of companies like TCA Electric and utility initiatives such as BC Hydro's vehicle-to-grid pilot underscore the importance of coordinated efforts in achieving sustainability goals.

Looking Ahead

As the field trial progresses, stakeholders are closely monitoring the performance of the hydrogen fuel cell crane. The data collected will inform decisions on scaling the technology and integrating it into broader port operations. The success of this project could pave the way for similar initiatives in other regions, complementing the province's move to electric ferries with CIB support, promoting the widespread adoption of hydrogen as a clean energy source in industrial applications.

TCA Electric's leadership in this project exemplifies the critical role of skilled industrial electricians in driving the transition to sustainable energy solutions. Their expertise ensures the safe and efficient implementation of complex systems, making them indispensable partners in the journey toward a zero-emission future.

The hydrogen fuel cell crane pilot at the Port of Vancouver represents a significant milestone in the decarbonization of port operations. Through innovative partnerships and local expertise, this project is setting the stage for a cleaner, more sustainable future in global trade and logistics.

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Ontario electricity emissions forecast highlights rising grid CO2 as nuclear refurbishments and the Pickering closure drive more natural gas, limited renewables, and delayed Quebec hydro imports, pending advances in storage and transmission upgrades.

Key Points

A projection that Ontario's grid CO2 will rise as nuclear units refurbish or retire, increasing natural gas use.

✅ Nuclear refurbs and Pickering shutdown cut zero-carbon baseload

✅ Gas plants fill capacity gaps, boosting GHG emissions

✅ Quebec hydro imports face cost, transmission, and timing limits

Ontario's energy grid is among the cleanest in North America — but the province’s nuclear plans mean that some of our progress will be reversed over the next decade.

What was once Canada’s largest single source of greenhouse-gas emissions is now a solar-power plant. The Nanticoke Generating Station, a coal-fired power plant in Haldimand County, was decommissioned in stages from 2010 to 2013 — and even before the last remaining structures were demolished earlier this year, Ontario Power Generation had replaced its nearly 4,000 megawatts with a 44-megawatt solar project in partnership with the Six Nations of the Grand River Development Corporation and the Mississaugas of the Credit First Nation.

But neither wind nor solar has done much to replace coal in Ontario’s hydro sector, a sign of how slowly Ontario is embracing clean power in practice across the province. At Nanticoke, the solar panels make up less than 2 per cent of the capacity that once flowed out to southern Ontario over high-voltage transmission lines. In cleaning up its electricity system, the province relied primarily on nuclear power — but the need to extend the nuclear system’s lifespan will end up making our electricity dirtier again.

“We’ve made some pretty great strides since 2005 with the fuel mix,” says Terry Young, vice-president of corporate communications at the Independent Electricity System Operator, the provincial agency whose job it is to balance supply and demand in Ontario’s electricity sector. “There have been big changes since 2005, but, yes, we will see an increase because of the closure of Pickering and the refurbs coming.”

“The refurbs” is industry-speak for the major rebuilds of both the Darlington and Bruce nuclear-power stations. The two are both in the early stages of major overhauls intended to extend their operating lives into the 2060s: in the coming years, they’ll be taken offline and rebuilt. (The Pickering nuclear plant will not be refurbished and will shut down in 2024.)

The catch is that, as the province loses its nuclear capacity in increments, Ontario will be short of electricity in the coming years and the IESO will need to find capacity elsewhere to make sure the lights stay on. And that could mean burning a lot more natural gas — and creating more greenhouse-gas emissions.

According to the IESO’s planning assumptions, electricity will be responsible for 11 megatonnes of greenhouse-gas emissions annually by 2035 (last year, it was three megatonnes). That’s the “reference case” scenario: if conservation and efficiency policies shave off some electricity demand, we could get it down to something like nine megatonnes. But if demand is higher than expected, it could be as high as 13 megatonnes — more than quadruple Ontario’s 2018 emissions.

Even in the worst-case scenario, the province’s emissions from electricity would still be less than half of what they were in 2005, before the province began phasing out its coal generation. But it’s still a reversal of a trend that both Liberals and Progressive Conservatives have boasted about — the Liberals to justify their energy policies, the PCs to justify their hostility to a federal carbon tax.

Young emphasized that technology can change and that the IESO’s planning assumptions are just that: projections based on the information available today. A revolution in electricity storage could make it possible to store the province’s cleaner power sources overnight for use during the day, but that’s still only in the realm of speculation — and the natural-gas infrastructure exists in the real world, today.

Ontario Power Generation — the Crown corporation that operates many of the province’s power plants, including Pickering and Darlington — recently bought four gas plants, two of them outright (two it already owned in part). All were nearly complete or already operational, so the purchase itself won’t change the province’s emissions prospects. Rather, OPG is simply looking to maintain its share of the electricity market after the Pickering shutdown.

“It will allow us to maintain our scale, with the upcoming end of Pickering’s commercial operations, so that we can continue our role as the driver of Ontario’s lower carbon future,” Neal Kelly, OPG’s director of media, issues, and management, told TVO.org via email. “Further, there is a growing need for flexible gas fired generation to support intermittent wind and solar generation.”

The shift to more gas-fired generation has been coming for a while, and critics say that Ontario has missed an opportunity to replace the lost Pickering capacity with something cleaner. MPP Mike Schreiner, leader of the Green party, has argued for years that Ontario should have pursued an agreement with Quebec to import clean hydroelectricity.

“To me, it’s a cost-effective solution, and it’s a zero-emissions solution,” Schreiner says. “Regardless of your position on sources of electricity, I think everyone could agree that waterpower from Quebec is going to be less expensive.”

Quebec is eager to sell Ontario its surplus hydro power, but not everyone agrees that importing power would be cheaper. A study published by the Ontario Chamber of Commerce (and commissioned by Ontario Power Generation) calls the claim a “myth” and states that upgrading electric-transmission wires between Ontario and Quebec would cost $1.2 billion and take 10 years, while some estimates suggest fully greening Ontario's grid would cost far more overall.

With Quebec imports seemingly a non-starter and major changes to Ontario’s nuclear fleet already underway, there’s only one path left for this province’s greenhouse-gas emissions: upwards.

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