46 per cent rate rise in 5 years predicted

By Toronto Star


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Ontarians will be zapped with a 46 per cent increase in home electricity costs over the next five years to pay for much-needed hydro system upgrades, warns the Liberal government.

To offset that sticker shock, Premier Dalton McGuintyÂ’s administration is offering a 10 per cent discount called the Ontario Clean Energy Benefit on hydro bills starting in January and lasting five years.

But in his fall economic statement, Finance Minister Dwight Duncan said electricity prices would still rise about 3.6 per cent annually on an average bill after inflation and the new measure the rise would have been 7.9 per cent without the new benefit.

“Every little bit helps during lean times,” he told the Legislature, saying rates should stabilize after five years once more expensive renewable energy sources replace heavily polluting coal-fired power plants.

It will go to about four million Ontario households and 400,000 farms and small businesses. Big power users will not receive the benefit.

The price break would save a homeowner using 800 kilowatt hours a month $153.60 annually, rising to $1,716 a year for a small business using 10,000 kWh monthly and $2,052 annually on a farm consuming 12,000 kWh a month.

Duncan conceded the LiberalsÂ’ green energy policies account for 56 per cent of the skyrocketing prices with expansion of nuclear and natural gas power plants the reason for the remaining 44 per cent.

“We are all paying for decades of neglect by governments of all political stripes. We had to invest. These were necessary, unavoidable costs.”

Taking a pre-emptive shot at opposition critics as an election looms next October, Duncan added: “Any politician who suggests, implies or tries to tell people that the price of electricity is going to go down over the next five years is simply not telling the truth.”

Progressive Conservative Leader Tim Hudak dismissed the price break, as “so-called benefit” from a desperate government that is “out of touch, out of gas, and increasingly, out of time.”

But Hudak would not scrap the discount. Nor could he say how much hydro rates would increase if he is elected in next fallÂ’s provincial vote.

“I’m not going to be Dalton McGuinty and make this stuff up on the fly like his scheme to try to buy votes before an election campaign,” the Tory leader said.

Duncan also revealed Ontario taxpayers are receiving a $1 billion windfall from the province’s Teranet land registry system — under a secret deal done without a public tender.

With the 10 per cent break on electricity bills to cost $1.1 billion in its first full year, Queen’s Park will raise nearly that amount in an “upfront” payment to extend Teranet’s exclusive licences.

The money is to pay down the government’s debt of $149.6 billion — up from $124.2 billion in 2003-04 when the Liberals were first elected — and reduce annual interest costs by $50 million.

Teranet, owned by Borealis Infrastructure, will provide electronic land registration and writs services for another 50 years beyond the original 2017 date of the contract.

From that date until 2067, the government will receive at least $50 million in annual royalty payments, added Duncan, who projected a deficit of $18.7 billion this fiscal year.

ThatÂ’s down $1 billion from a previous forecast because of stronger economic growth boosting expected revenues by almost $800 million to $107.7 billion.

Despite his boast that 75 per cent of jobs lost in the recession have been regained, revenue from personal income taxes is expected to be $1.13 billion below this yearÂ’s forecast.

With a lack of detail on how the Teranet deal was put together, even though it could have been put up for bids at the 2017 expiry, NDP Leader Andrea Horwath called it a “short-term... cash grab.”

Horwath compared it to the “fire sale” of the Hwy 407 when the previous Progressive Conservative government sold off the toll highway before the 1999 election.

Duncan countered that the Liberals decided the time was right to strike a deal in advance, and that it had favourable opinions on the fairness of the deal for taxpayers from financial advisors.

The treasurer also defended the need to borrow money to finance the electricity rate cut, noting governments used loans to improve hospitals, highways, and bridges during the recession.

“We believe this is the right way to do it,” he told reporters. “We think providing this clean energy benefit, as we move towards a rebuilt energy system with more clean energy, is an appropriate priority.”

Satinder Chera, Ontario vice-president of the Canadian Federation of Independent Business, hailed the electricity price relief as welcome help for the “province’s job-creators.”

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Hydro One shares jump 5.7 per cent after U.S. regulators reject $6.7B takeover

Hydro One Avista takeover rejection signals Washington regulators blocking a utility acquisition over governance risk, EPS dilution, and balance sheet impact, as investors applaud share price gains and a potential US$103M break fee.

 

Key Points

A regulator-led block of Hydro One's Avista bid, citing EPS dilution, balance sheet risk, and governance concerns.

✅ Washington denies approval; Idaho, Oregon decisions pending.

✅ EPS dilution avoided; balance sheet strength preserved.

✅ Shares rise 5.7%; US$103M break fee if deal collapses.

 

Opposition politicians may not like it but investors are applauding the rejection of Hydro One Ltd.'s $6.7-billion Avista takeover of U.S.-based utility Avista Corp.

Shares in the power company controlled by the Ontario government, which has also proposed a bill redesign to simplify statements, closed at $21.53, up $1.16 or 5.7 per cent, on the Toronto Stock Exchange on Thursday.

On Wednesday, Washington State regulators said they would not allow Ontario's largest utility to buy Avista over concerns about political risk that the provincial government, which owns 47 per cent of Hydro One's shares, might meddle in Avista's operations.

Financial analysts had predicted investors would welcome the news because the deal, announced in July 2017, would have eroded earnings per share and weakened Hydro One's balance sheet.

"The Washington regulator's denial of Avista is a positive development for the shares, in our opinion," said analyst Ben Pham of BMO Capital Markets in a report on Wednesday.

"While this may sound odd, we note that the Avista deal is expected to be EPS dilutive and result in a weaker balance sheet for (Hydro One). Not acquiring Avista and refocusing its attention on its core Ontario franchise ... along with related interprovincial arrangements such as the Ontario-Quebec electricity deal under discussion would likely be viewed positively if the deal ultimately breaks."

Decisions are yet to come from Idaho and Oregon state regulators, but Washington was probably the most important as the state contains customers making up about 60 per cent of Avista's rate base, Pham said.

He pointed out that a US$103-million break fee is to be paid to Avista if the deal collapses due to a failure to obtain regulatory approval.

CIBC analyst Robert Catellier raised his 12-month Hydro One target price by 25 cents and said many shareholders will feel "relieved" that the deal had failed.

He warned that the company's earnings power could deteriorate as the province seeks to reduce power bills by 12 per cent, despite an Ontario-Quebec hydro deal that may not lower costs.

 

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Climate change: Greenhouse gas concentrations again break records

Rising Greenhouse Gas Concentrations drive climate change, with CO2, methane, and nitrous oxide surging; WMO data show higher radiative forcing, elevated pre-industrial baselines, and persistent atmospheric concentrations despite Paris Agreement emissions pledges.

 

Key Points

Increasing atmospheric CO2, methane, and nitrous oxide levels that raise radiative forcing and drive warming.

✅ WMO data show CO2 at 407.8 ppm in 2018, above decade average

✅ Methane and nitrous oxide surged, elevating total radiative forcing

✅ Concentrations differ from emissions; sinks absorb about half

 

The World Meteorological Organization (WMO) says the increase in CO2 was just above the average rise recorded over the last decade.

Levels of other warming gases, such as methane and nitrous oxide, have also surged by above average amounts.

Since 1990 there's been an increase of 43% in the warming effect on the climate of long lived greenhouse gases.

The WMO report looks at concentrations of warming gases in the atmosphere rather than just emissions.

The difference between the two is that emissions refer to the amount of gases that go up into the atmosphere from the use of fossil fuels, such as burning coal for coal-fired electricity generation and from deforestation.

Concentrations are what's left in the air after a complex series of interactions between the atmosphere, the oceans, the forests and the land. About a quarter of all carbon emissions are absorbed by the seas, and a similar amount by land and trees, while technologies like carbon capture are being explored to remove CO2.

Using data from monitoring stations in the Arctic and all over the world, researchers say that in 2018 concentrations of CO2 reached 407.8 parts per million (ppm), up from 405.5ppm a year previously.

This increase was above the average for the last 10 years and is 147% of the "pre-industrial" level in 1750.

The WMO also records concentrations of other warming gases, including methane and nitrous oxide, and some countries have reported declines in certain potent gases, as noted in US greenhouse gas controls reports, though global levels remain elevated. About 40% of the methane emitted into the air comes from natural sources, such as wetlands, with 60% from human activities, including cattle farming, rice cultivation and landfill dumps.

Methane is now at 259% of the pre-industrial level and the increase seen over the past year was higher than both the previous annual rate and the average over the past 10 years.

Nitrous oxide is emitted from natural and human sources, including from the oceans and from fertiliser-use in farming. According to the WMO, it is now at 123% of the levels that existed in 1750.

Last year's increase in concentrations of the gas, which can also harm the ozone layer, was bigger than the previous 12 months and higher than the average of the past decade.

What concerns scientists is the overall warming impact of all these increasing concentrations. Known as total radiative forcing, this effect has increased by 43% since 1990, and is not showing any indication of stopping.

There is no sign of a slowdown, let alone a decline, in greenhouse gases concentration in the atmosphere despite all the commitments under the Paris agreement on climate change and the ongoing global energy transition efforts," said WMO Secretary-General Petteri Taalas.

"We need to translate the commitments into action and increase the level of ambition for the sake of the future welfare of mankind," he added.

"It is worth recalling that the last time the Earth experienced a comparable concentration of CO2 was three to five million years ago. Back then, the temperature was 2-3C warmer, sea level was 10-20m higher than now," said Mr Taalas.

The UN Environment Programme will report shortly on the gap between what actions countries are taking to cut carbon, for example where Australia's emissions rose 2% recently, and what needs to be done to keep under the temperature targets agreed in the Paris climate pact.

Preliminary findings from this study, published during the UN Secretary General's special climate summit last September, indicated that emissions continued to rise during 2018, although global emissions flatlined in 2019 according to the IEA.

Both reports will help inform delegates from almost 200 countries who will meet in Madrid next week for COP25, following COP24 in Katowice the previous year, the annual round of international climate talks.

 

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Consumer choice has suddenly revolutionized the electricity business in California. But utilities are striking back

California Community Choice Aggregators are reshaping electricity markets with renewable energy, solar and wind sourcing, competitive rates, and customer choice, challenging PG&E, SDG&E, and Southern California Edison while advancing California's clean power goals.

 

Key Points

Local governments that buy power, often cleaner and cheaper, while utilities handle delivery and billing.

✅ Offer higher renewable mix than utilities at competitive rates

✅ Utilities retain transmission and billing responsibilities

✅ Rapid expansion threatens IOU market share across California

 

Nearly 2 million electricity customers in California may not know it, but they’re part of a revolution. That many residents and businesses are getting their power not from traditional utilities, but via new government-affiliated entities known as community choice aggregators. The CCAs promise to deliver electricity more from renewable sources, such as solar and wind, even as California exports its energy policies across Western states, and for a lower price than the big utilities charge.

The customers may not be fully aware they’re served by a CCA because they’re still billed by their local utility. But with more than 1.8 million accounts now served by the new system and more being added every month, the changes in the state’s energy system already are massive.

Faced for the first time with real competition, the state’s big three utilities have suddenly become havens of innovation. They’re offering customers flexible options on the portion of their power coming from renewable energy, amid a broader review to revamp electricity rates aimed at cleaning the grid, and they’re on pace to increase the share of power they get from solar and wind power to the point where they are 10 years ahead of their deadline in meeting a state mandate.

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But that may not stem the flight of customers. Some estimates project that by late this year, more than 3 million customers will be served by 20 CCAs, and that over a longer period, Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric could lose 80% of their customers to the new providers.

Two big customer bases are currently in play: In Los Angeles and Ventura counties, a recently launched CCA called the Clean Power Alliance is hoping by the end of 2019 to serve nearly 1 million customers. Unincorporated portions of both counties and 29 municipalities have agreed in principle to join up.

Meanwhile, the city of San Diego is weighing two options to meet its goal of 100% clean power by 2035, as exit fees are being revised by the utilities commission: a plan to be submitted by SDG&E, or the creation of a CCA. A vote by the City Council is expected by the end of this year. A city CCA would cover 1.4 million San Diegans, accounting for half SDG&E’s customer demand, according to Cody Hooven, the city’s chief sustainability officer.

Don’t expect the big companies to give up their customers without a fight. Indeed, battle lines already are being drawn at the state Public Utilities Commission, where a recent CPUC ruling sided with a community energy program over SDG&E, and local communities.

“SDG&E is in an all-out campaign to prevent choice from happening, so that they maintain their monopoly,” says Nicole Capretz, who wrote San Diego’s climate action plan as a city employee and now serves as executive director of the Climate Action Campaign, which supports creation of the CCA.

California is one of seven states that have legalized the CCA concept, even as regulators weigh whether the state needs more power plants to ensure reliability. (The others are New York, New Jersey, Massachusetts, Ohio, Illinois and Rhode Island.) But the scale of its experiment is likely to be the largest in the country, because of the state’s size and the ambition of its clean-power goal, which is for 50% of its electricity to be generated from renewable sources by 2030.

California created its system via legislative action in 2002. Assembly Bill 117 enabled municipalities and regional governments to establish CCAs anywhere that municipal power agencies weren’t already operating. Electric customers in the CCA zones were automatically signed up, though they could opt out and stay with their existing power provider. The big utilities would retain responsibility for transmission and distribution lines.

The first CCA, Marin Clean Energy, began operating in 2010 and now serves 470,000 customers in Marin and three nearby counties.

The new entities were destined to come into conflict with the state’s three big investor-owned utilities. Their market share already has fallen to about 70%, from 78% as recently as 2010, and it seems destined to keep falling. In part that’s because the CCAs have so far held their promise: They’ve been delivering relatively clean power and charging less.

The high point of the utilities’ hostility to CCAs was the Proposition 16 campaign in 2009. The ballot measure was dubbed the “Taxpayers Right to Vote Act,” but was transparently an effort to smother CCAs in the cradle. PG&E drafted the measure, got it on the ballot, and contributed all of the $46.5 million spent in the unsuccessful campaign to pass it.

As recently as last year, PG&E and SDG&E were lobbying in the legislature for a bill that would place a moratorium on CCAs. The effort failed, and hasn’t been revived this year.

Rhetoric similar to that used by PG&E against Marin’s venture has surfaced in San Diego, where a local group dubbed “Clear the Air” is fighting the CCA concept by suggesting that it could be financially risky for local taxpayers and questioning whether it will be successful in providing cleaner electricity. Whether Clear the Air is truly independent of SDG&E’s parent, Sempra Energy, is questionable, as at least two of its co-chairs are veteran lobbyists for the company.

SDG&E spokeswoman Helen Gao says the utility supports “customers’ right to choose an energy provider that best meets their needs” and expects to maintain a “cooperative relationship” with any provider chosen by the city.

 

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Electric Ferries Power Up B.C. with CIB Help

BC Ferries Electrification accelerates zero-emission vessels, Canada Infrastructure Bank financing, and fast charging infrastructure to cut greenhouse gas emissions, lower operating costs, and reduce noise across British Columbia's Island-class routes.

 

Key Points

BC Ferries Electrification is the plan to deploy zero-emission ferries and charging, funded by CIB, to reduce emissions.

✅ $75M CIB loan funds four electric ferries and chargers

✅ Cuts 9,000 tonnes CO2e annually on short Island-class routes

✅ Quieter service, lower operating costs, and redeployed hybrids

 

British Columbia is taking a significant step towards a cleaner transportation future with the electrification of its ferry fleet. BC Ferries, the province's ferry operator, has secured a $75 million loan from the Canada Infrastructure Bank (CIB) to fund the purchase of four zero-emission ferries and the necessary charging infrastructure to support them.

This marks a turning point for BC Ferries, which currently operates a fleet reliant on diesel fuel. The new Island-class electric ferries will be deployed on shorter routes, replacing existing hybrid ships on those routes. These hybrid ferries will then be redeployed on routes that haven't yet been converted to electric, maximizing their lifespan and efficiency.

Environmental Benefits

The transition to electric ferries is expected to deliver significant environmental benefits. The new vessels are projected to eliminate an estimated 9,000 tonnes of greenhouse gas emissions annually, and electric ships on the B.C. coast already demonstrate similar gains, contributing to British Columbia's ambitious climate goals. Additionally, the quieter operation of electric ferries will create a more pleasant experience for passengers and reduce noise pollution for nearby communities.

Economic Considerations

The CIB loan plays a crucial role in making this project financially viable. The low-interest rate offered by the CIB will help to keep ferry fares more affordable for passengers. Additionally, the long-term operational costs of electric ferries are expected to be lower than those of diesel-powered vessels, providing economic benefits in the long run.

Challenges and Opportunities

While the electrification of BC Ferries is a positive development, there are some challenges to consider. The upfront costs of electric ferries and charging infrastructure are typically higher than those of traditional options, though projects such as the Kootenay Lake ferry show growing readiness. However, advancements in battery technology are constantly lowering costs, making electric ferries a more cost-effective choice over time.

Moreover, the transition presents opportunities for job creation in the clean energy sector, with complementary initiatives like the hydrogen project broadening demand. The development, construction, and maintenance of electric ferries and charging infrastructure will require skilled workers, potentially creating a new avenue for economic growth in British Columbia.

A Pioneering Example

BC Ferries' electrification initiative sets a strong precedent for other ferry operators worldwide, including Washington State Ferries pursuing hybrid-electric upgrades. This project demonstrates the feasibility and economic viability of transitioning to cleaner marine transportation solutions. As battery technology and charging infrastructure continue to develop, we can expect to see more widespread adoption of electric ferries across the globe.

The collaboration between BC Ferries and the CIB paves the way for a greener future for BC's transportation sector, where efforts like Harbour Air's electric aircraft complement marine electrification. With cleaner air, quieter operation, and a positive impact on climate change, this project is a win for the environment, the economy, and British Columbia as a whole.

 

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Energy authority clears TEPCO to restart Niigata nuclear plant

TEPCO Kashiwazaki-Kariwa restart plan clears NRA fitness review, anchored by a seven-point safety code, Niigata consent, Fukushima lessons, seismic risk analysis, and upgrades to No. 6 and No. 7 reactors, each rated 1.35 GW.

 

Key Points

TEPCO's plan to restart Kashiwazaki-Kariwa under NRA rules, pending Niigata consent and upgrades to Units 6 and 7.

✅ NRA deems TEPCO fit; legally binding seven-point safety code

✅ Local consent required: Niigata review of evacuation and health impacts

✅ Initial focus on Units 6 and 7; 1.35 GW each, seismic upgrades

 

Tokyo Electric Power Co. cleared a major regulatory hurdle toward restarting a nuclear power plant in Niigata Prefecture, but the utility’s bid to resume its operations still hangs in the balance of a series of political approvals.

The government’s nuclear watchdog concluded Sept. 23 that the utility is fit to operate the plant, based on new legally binding safety rules TEPCO drafted and pledged to follow, even as nuclear projects worldwide mark milestones across different regulatory environments today. If TEPCO is found to be in breach of those regulations, it could be ordered to halt the plant’s operations.

The Nuclear Regulation Authority’s green light now shifts the focus over to whether local governments will agree in the coming months to restart the Kashiwazaki-Kariwa plant.

TEPCO is keen to get the plant back up and running. It has been financially reeling from the closure of its nuclear plants in Fukushima Prefecture following the triple meltdown at the Fukushima No. 1 nuclear plant in 2011 triggered by the earthquake and tsunami disaster.

In parallel, Japan is investing in clean energy innovations such as a large hydrogen system being developed by Toshiba, Tohoku Electric Power and Iwatani.

The company plans to bring the No. 6 and No. 7 reactors back online at the Kashiwazaki-Kariwa nuclear complex, which is among the world’s largest nuclear plants, amid China’s nuclear energy continuing on a steady development track in the region.

The two reactors each boast 1.35 gigawatts in output capacity, while Kenya’s nuclear plant aims to power industry as part of that country’s expansion. They are the newest of the seven reactors there, first put into service between 1996 and 1997.

TEPCO has not revealed specific plans yet on what to do with the older five reactors.

In 2017, the NRA cleared the No. 6 and No. 7 reactors under the tougher new reactor regulations established in 2013 in response to the Fukushima nuclear disaster, while jurisdictions such as Ontario support continued operation at Pickering under strict oversight.

It also closely scrutinized the operator’s ability to run the Niigata Prefecture plant safely, given its history as the entity responsible for the nation’s most serious nuclear accident.

After several rounds of meetings with top TEPCO managers, the NRA managed to hold the utility’s feet to the fire enough to make it pledge, in writing, to abide by a new seven-point safety code for the Kashiwazaki-Kariwa plant.

The creation of the new code, which is legally binding, is meant to hold the company accountable for safety measures at the facility.

“As the top executive, the president of TEPCO will take responsibility for the safety of nuclear power,” one of the points reads. “TEPCO will not put the facility’s economic performance above its safety,” reads another.

The company promised to abide by the points set out in writing during the NRA’s examination of its safety regulations.

TEPCO also vowed to set up a system where the president is directly briefed on risks to the nuclear complex, including the likelihood of earthquakes more powerful than what the plant is designed to withstand. It must also draft safeguard measures to deal with those kinds of earthquakes and confirm whether precautionary steps are in place.

The utility additionally pledged to promptly release public records on the decision-making process concerning crucial matters related to nuclear safety, and to preserve the documents until the facility is decommissioned.

TEPCO plans to complete its work to reinforce the safety of the No. 7 reactor in December. It has not set a definite deadline for similar work for the No. 6 reactor.

To restart the Kashiwazki-Kariwa plant, TEPCO needs to obtain consent from local governments, including the Niigata prefectural government.

The prefectural government is studying the plant’s safety through a panel of experts, which is reviewing whether evacuation plans are adequate as off-limits areas reopen and the health impact on residents from the Fukushima nuclear disaster.

Niigata Governor Hideyo Hanazumi said he will not decide on the restart until the panel completes its review.

The nuclear complex suffered damage, including from fire at an electric transformer, when an earthquake it deemed able to withstand hit in 2007.

 

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Why Fort Frances wants to build an integrated microgrid to deliver its electricity

Fort Frances Microgrid aims to boost reliability in Ontario with grid-connected and island modes, Siemens feasibility study, renewable energy integration, EV charging expansion, and resilience modeled after First Nations projects and regional biomass initiatives.

 

Key Points

A community microgrid in Fort Frances enabling grid and island modes to improve reliability and integrate renewables.

✅ Siemens-led feasibility via FedNor funding

✅ Grid-connected or islanded for outage resilience

✅ Integrates renewables, EV charging, and industry growth

 

When the power goes out in Fort Frances, Ont., the community may be left in the dark for hours.

The hydro system's unreliability — caused by its location on the provincial power grid — has prompted the town to seek a creative solution: its own self-contained electricity grid with its own source of power, known as a microgrid. 

Located more than 340 kilometres west of Thunder Bay, Ont., on the border of Minnesota, near the Great Northern Transmission Line corridor, Fort Frances gets its power from a single supply point on Ontario's grid. 

"Sometimes, it's inevitable that we have to have like a six- to eight-hour power outage while equipment is being worked on, and that is no longer acceptable to many of our customers," said Joerg Ruppenstein, president and chief executive officer of Fort Frances Power Corporation.

While Ontario's electrical grid serves the entire province, and national efforts explore macrogrids, a microgrid is contained within a community. Fort Frances hopes to develop an integrated, community-based electric microgrid system that can operate in two modes:

  • Grid-connected mode, which means it's connected to the provincial grid and informed by western grid planning approaches
  • Island mode, which means it's disconnected from the provincial grid and operates independently

The ability to switch between modes allows flexibility. If a storm knocks down a line, the community will still have power.

The town has been given grant funding from the Federal Economic Development Agency for Northern Ontario (FedNor), echoing smart grid funding in Sault Ste. Marie initiatives, for the project. On Monday night, council voted to grant a request for proposal to Siemens Canada Limited to conduct a feasibility study into a microgrid system.

The study, anticipated to be completed by the end of 2023 or early 2024, will assess what an integrated community-based microgrid system could look like in the town of just over 7,000 people, said Faisal Anwar, chief administrative officer of Fort Frances. A timeline for construction will be determined after that. 

The community is still reeling from the closure of the Resolute Forest Products pulp and paper mill in 2014 and faces a declining population, said Ruppenstein. It's hoped the microgrid system will help attract new industry to replace those lost workers and jobs, drawing on Manitoba's hydro experience as a model.

This gives the town a competitive advantage.

"If we were conceivably to attract a larger industrial player that would consume a considerable amount of energy, it would result in reduced rates for everyone…we're the only utility really in Ontario that can offer that model," Ruppenstein said.

The project can also incorporate renewable energy like solar or wind power, as seen in B.C.'s clean energy shift efforts, into the microgrid system, and support the growth of electric vehicles, he said. Many residents fill their gas tanks in Minnesota because it's cheaper, but Fort Frances has the potential to become a hub for electric vehicle charging.

A few remote First Nations have recently switched to microgrid systems fuelled by green energy, including Gull Bay First Nation and Fort Severn First Nation. These are communities that have historically relied on diesel fuel either flown in, which is incredibly expensive, or transported via ice roads, which are seeing shorter seasons each year.

Natural Resources Minister Jonathan Wilkinson was in Thunder Bay, Ont., to announce $35 million for a biomass generation facility in Whitesand First Nation, complementing federal funding for the Manitoba-Saskatchewan transmission line elsewhere in the region.

 

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