Doubts about Brazilian grid linger

By Globe and Mail


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BrazilÂ’s president fended off criticism of his nationÂ’s shaky power grid as officials investigated a blackout that plunged as many as 60 million people into darkness, prompting concerns about the countryÂ’s preparedness to host the 2016 Olympic Games.

Power went out for more than two hours in Rio de Janeiro, Sao Paulo and several other major cities after transmission problems knocked one of the worldÂ’s biggest hydroelectric dams offline. Airport operations were hindered and subways ground to a halt.

A group of muggers took advantage of the darkness to rob people en masse near RioÂ’s Maracana stadium, which will host the OlympicsÂ’ opening and closing ceremonies. But overall, police said, crime did not rise in Rio and fell in Sao Paulo during the outage.

All of neighbouring Paraguay also went dark, but for less than a half hour. A spokesman at Brazil’s Energy Ministry said up to 60 million people — nearly a third of the nation’s population — were affected by the blackout. He spoke on condition of anonymity, as he was not authorized to discuss the matter.

The failure affected more people than the worst U.S. blackout on record: an August 14, 2003 outage caused by power line problems in the Midwest that cut electricity to 50 million people in eight states and Canada.

The Energy Ministry called an emergency meeting, but Justice Minister Tarso Genro minimized the impact, saying Brazil has vastly improved its electrical grid since a series of outages in the 1990s.

“This is a micro-accident among the extraordinary conquests for energy production for Brazil over the last seven years,” Mr. Genro said.

Energy analysts say Brazil has failed to invest enough in transmission lines as demand for power skyrockets amid an extended boom for Latin AmericaÂ’s largest economy.

But President Luiz Inacio Lula da Silva defended his government from criticism that it has not done enough to improve the power grid since he took office in 2003, two years after Brazil suffered shortages and rationing under his predecessor.

“In seven years, we created 30 per cent of all the transmission lines built in the last 130 years,” Mr. Silva said.

Brazilian authorities blamed storms that took down power lines and towers, causing a domino effect that rippled across the region.

Lights twinkled back on along RioÂ’s Copacabana beach, in South AmericaÂ’s largest city of Sao Paulo and in ParaguayÂ’s sleepy capital of Asuncion. But some traffic lights were still out in both Rio and Sao Paulo and traffic officials were expecting drivers to face difficulties the rest of the day, according to local media.

In Rio, Governor Sergio Cabral sent an elite police unit into the streets to help maintain calm in a city known for its crime. The mayor dispatched 300 extra unarmed civil guards to help control traffic.

The city saw a series of robberies around the Maracana football stadium — where the opening and closing ceremonies of the 2016 Olympics will be held, along with the 2014 World Cup final. A police spokesman said a band of roughly a dozen criminals worked the area together, robbing people en masse — a crime phenomenon so routine it is known as a “big sweep.”

A Rio police statement said there was no increase in crime, though it did not give figures. In Sao Paulo, military police said they handled fewer incidents than usual.

Questions remained about what happened and what the fallout would be in Brazil, a nation seen as an ascending economic and political power.

“The image of Brazil, of Rio, is bad enough with all the violence,” said 35-year-old graphic designer Paulo Viera, as he sat in a restaurant a block from the sandy arc of Copacabana.

Standing in an open-air restaurant where patrons were drinking quickly warming beer, Mr. Viera said he worried about how the outage might look for a city that last month was picked to host the Olympics and will be the showcase city for soccer’s World Cup in 2014. “We don’t need this to happen. I don’t know how it could get worse.”

The blackout comes on the heels of a wave of gang fighting in RioÂ’s slums that led to violence fears ahead of the games.

“It’s sad to see such a beautiful city with such a precarious infrastructure,” 22-year-old law student Igor Fernandes said. “This shouldn’t happen in a city that is going to host the Olympic Games.”

The outage occurred when the huge Itaipu dam straddling the Brazilian-Paraguay border stopped producing 17,000 megawatts of power, Brazilian Mines and Energy Minister Edison Lobao said. His ministry said in a statement that outages hit 18 of the 27 states in this country of more than 190 million people. No power outages happened in Brasilia, the national capital.

Jorge Miguel Samek, the head of Itaipu Binacional, the agency in charge of the dam, said there was a “99 per cent chance the blackout happened because of a storm.”

“There was no problem with generating electricity, but a problem with ‘lightning or a storm that took down some towers’,” he said.

The agency said that despite the fact it never stopped functioning, “there was no possibility of transmitting energy because the transmission lines that connect Itaipu to the Brazilian system were disconnected.”

Mr. Lobao also said the hydro plant at the dam itself was working, but there were problems with the power lines that carry electricity across Brazil. Brazil uses almost all the energy produced by the dam, and Paraguay consumes the rest. About 80 per cent of BrazilÂ’s energy comes from hydroelectric power.

In Paraguay, the national energy agency blamed the blackout on a short-circuit at an electrical station near Sao Paulo, saying that failure shut down the entire power grid supplied by Itaipu. All of Paraguay went dark for about 20 minutes, ABC Color newspaper reported.

It is at least the fourth time since 1985 that Brazil has suffered a massive power outage involving transmission lines from Itaipu.

The worst of those, in 1999, occurred after lightning struck a power substation in Sao Paulo state, plunging 97 million Brazilians into darkness for up to five hours.

The blackouts came two days after CBSÂ’s 60 Minutes news program reported that several past Brazilian power outages were caused by computer hackers. Brazilian officials had played down the report before the latest outages, and Mr. Lobao did not mention it.

The Itaipu dam is the worldÂ’s second biggest hydroelectric producer, supplying 20 per cent of BrazilÂ’s electricity. ChinaÂ’s Three Gorges dam is the largest.

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Alberta set to retire coal power by 2023, ahead of 2030 provincial deadline

Alberta coal phaseout accelerates as utilities convert to natural gas, cutting emissions under TIER regulations and deploying hydrogen-ready, carbon capture capable plants, alongside new solar projects in a competitive, deregulated electricity market.

 

Key Points

A provincewide shift from coal to natural gas and renewables, cutting power emissions years ahead of the 2030 target.

✅ Capital Power, TransAlta converting coal units to gas

✅ TIER pricing drives efficiency, carbon capture readiness

✅ Hydrogen-ready turbines, solar projects boost renewables

 

Alberta is set to meet its goal to eliminate coal-fired electricity production years earlier than its 2030 target, amid a broader shift to cleaner energy in the province, thanks to recently announced utility conversion projects.

Capital Power Corp.’s plan to spend nearly $1 billion to switch two coal-fired power units west of Edmonton to natural gas, and stop using coal entirely by 2023, was welcomed by both the province and the Pembina Institute environmental think-tank.

In 2014, 55 per cent of Alberta’s electricity was produced from 18 coal-fired generators. The Alberta government announced in 2015 it would eliminate emissions from coal-fired electricity generation by 2030.

Dale Nally, associate minister of Natural Gas and Electricity, said Friday that decisions by Capital Power and other utilities to abandon coal will be good for the environment and demonstrates investor confidence in Alberta’s deregulated electricity market, where the power price cap has come under scrutiny.

He credited the government’s Technology Innovation and Emissions Reduction (TIER) regulations, which put a price on industrial greenhouse gas emissions, as a key factor in motivating the conversions.

“Capital Power’s transition to gas is a great example of how private industry is responding effectively to TIER, as it transitions these facilities to become carbon capture and hydrogen ready, which will drive future emissions reductions,” Nally said in an email.

Capital Power said direct carbon dioxide emissions at its Genesee power facility near Edmonton will be about 3.4 million tonnes per year lower than 2019 emission levels when the project is complete.

It says the natural gas combined cycle units it’s installing will be the most efficient in Canada, adding they will be capable of running on 30 per cent hydrogen initially, with the option to run on 95 per cent hydrogen in future with minor investments.

In November, Calgary-based TransAlta Corp. said it will end operations at its Highvale thermal coal mine west of Edmonton by the end of 2021 as it switches to natural gas at all of its operated coal-fired plants in Canada four years earlier than previously planned.

The Highvale surface coal mine is the largest in Canada, and has been in operation on the south shore of Wabamun Lake in Parkland County since 1970.

The moves by the two utilities and rival Atco Ltd., which announced three years ago it would convert to gas at all of its plants by this year, mean significant emissions reduction and better health for Albertans, said Binnu Jeyakumar, director of clean energy for Pembina.

“Alberta’s early coal phaseout is also a great lesson in good policy-making done in collaboration with industry and civil society,” she said.

“As we continue with this transformation of our electricity sector, it is paramount that efforts to support impacted workers and communities are undertaken.”

She added the growing cost-competitiveness of renewable energy, such as wind power, makes coal plant retirements possible, applauding Capital Power’s plans to increase its investments in solar power.

In Ontario, clean power policy remains a focus as the province evaluates its energy mix.

The company announced it would go ahead with its 75-megawatt Enchant Solar power project in southern Alberta, investing between $90 million and $100 million, and that it has signed a 25-year power purchase agreement with a Canadian company for its 40.5-MW Strathmore Solar project now under construction east of Calgary.
 

 

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Analysis: Out in the cold: how Japan's electricity grid came close to blackouts

Japan Electricity Crunch exposes vulnerabilities in a liberalised power market as LNG shortages, JEPX price spikes, snow-hit solar, and weak hedging strain energy security and retail providers amid cold snap demand and limited reserve capacity.

 

Key Points

A winter demand shock and LNG shortfalls sent JEPX to records, exposing gaps in hedging, data, and energy security.

✅ JEPX wholesale prices spiked to an all-time high

✅ LNG inventories and procurement proved insufficient

✅ Snow disabled solar; new entrants lacked hedging

 

Japan's worst electricity crunch since the aftermath of the Fukushima crisis has exposed vulnerabilities in the country's recently liberalised power market, although some of the problems appear self-inflicted.

Power prices in Japan hit record highs last month, mirroring UK peak power prices during tight conditions, as a cold snap across northeast Asia prompted a scramble for supplies of liquefied natural gas (LNG), a major fuel for the country's power plants. Power companies urged customers to ration electricity to prevent blackouts, although no outages occurred.

The crisis highlighted how many providers were unprepared for such high demand. Experts say LNG stocks were not topped up ahead of winter and snow disabled solar power farms, while China's power woes strained solar supply chains.

The hundreds of small power companies that sprang up after the market was opened in 2016 have struggled the most, saying the government does not disclose the market data they need to operate. The companies do not have their own generators, instead buying electricity on the wholesale market.

Prices on the Japan Electric Power Exchange (JEPX) hit a record high of 251 yen ($2.39) per kilowatt hour in January, equating to $2,390 per megawatt hour of electricity, above record European price surges seen recently and the highest on record anywhere in the world. One megawatt hour is roughly what an average home in the U.S. would consume over 35 days.

But the vast majority of the new, smaller companies are locked into low, fixed rates they set to lure customers from bigger players, crushing them financially during a price spike like the one in January.

More than 50 small power providers wrote on Jan. 18 to Japan's industry minister, Hiroshi Kajiyama, who oversees the power sector, asking for more accessible data on supply and demand, reserve capacity and fuel inventories.

"By organising and disclosing this information, retail electricity providers will be able to bid at more appropriate prices," said the companies, led by Looop Co.

They also called on Kajiyama to require transmission and distribution companies to pass on some of the unexpected profits from price spikes to smaller operators.

The industry ministry said it had started releasing more timely market data, and is reviewing the cause of the crunch and considering changes, echoing calls by Fatih Birol to keep electricity options open amid uncertainty.

Japan reworked its power markets after the Fukushima nuclear disaster in 2011, liberalizing the sector in 2016 while pushing for more renewables.

But Japan is still heavily reliant on LNG and coal, and only four of 33 nuclear reactors are operating. The power crisis has led to growing calls to restart more reactors.

Kazuno Power, a small retail provider controlled by a municipality of the same name in northern Japan, where abundant renewable energy is locally produced, buys electricity from hydropower stations and JEPX.

During the crunch, the company had to pay nearly 10 times the usual price, Kazuno Power president Takao Takeda said in an interview. Like most other new providers, it could not pass on the costs, lost money, and folded. The local utility has taken over its customers.

"There is a contradiction in the current system," Takeda said. "We are encouraged to locally produce power for local consumption as well as use more renewable energy, but prices for these power supplies are linked to wholesale prices, which depend on the overall power supply."

The big utilities, which receive most of their LNG on long-term contracts, blamed the power shortfall on a tight spot market and glitches at generation units.

"We were not able to buy as much supply as we wanted from the spot market because of higher demand from South Korea and China, where power cuts have tightened supply," Kazuhiro Ikebe, the head of the country's electricity federation, said recently.

Ikebe is also president of Kyushu Electric Power, which supplies the southern island of Kyushu.

Utilities took extreme measures - from burning polluting fuel oil in coal plants to scavenging the dregs from empty LNG tankers - to keep the grid from breaking down.

"There is too much dependence on JEPX for procurement," said Bob Takai, the local head of European Energy Exchange, where electricity pricing reforms are being discussed, and which started offering Japan power futures last year. He added that new entrants were not hedging against sharp price moves.

Three people, who requested anonymity because of the sensitivity of the matter, were more blunt. One called the utilities arrogant in assuming they could find LNG cargoes in a pinch. Prices were already rising as China snapped up supplies, the sources noted.

"You had volatility caused by people saying 'Oh, well, demand is going to be weak because of coronavirus impacts' and then saying 'we can rely more on solar than in the past,' but solar got snowed out," said a senior executive from one generator. "We have a problem of who is charge of energy security in Japan."

Inventories of LNG, generally about two weeks worth of supplies, were also not topped up enough to prepare for winter, a market analyst said.

The fallout from the crunch has become more apparent in recent days, with new power companies like Rakuten Inc suspending new sales and Tokyo Gas, along with traditional electricity utilities, issuing profit downgrades or withdrawing their forecasts.

Although prices have fallen sharply as temperatures warmed up slightly and more generation units have come back online, the power generator executive said, "we are not out of the woods yet."
 

 

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What Will Drive Utility Revenue When Electricity Is Free?

AI-Powered Utility Customer Experience enables transparency, real-time pricing, smart thermostats, demand response, and billing optimization, helping utilities integrate distributed energy resources, battery storage, and microgrids while boosting customer satisfaction and reducing costs.

 

Key Points

An approach where utilities use AI and real-time data to personalize service, optimize billing, and cut energy costs.

✅ Real-time pricing aligns retail and wholesale market signals

✅ Device control via smart thermostats and home energy management

✅ Analytics reveal appliance-level usage and personalized savings

 

The latest electric utility customer satisfaction survey results from the American Customer Satisfaction Index (ACSI) Energy Utilities report reveal that nearly every investor-owned utility saw customer satisfaction go down from 2018 to 2019. Residential customers are sending a clear message in the report: They want more transparency and control over energy usage, billing and ways to reduce costs.

With both customer satisfaction and utility revenues on the decline, utilities are facing daunting challenges to their traditional business models amid flat electricity demand across many markets today. That said, it is the utilities that see these changing times as an opportunity to evolve that will become the energy leaders of tomorrow, where the customer relationship is no longer defined by sales volume but instead by a utility company's ability to optimize service and deliver meaningful customer solutions.

We have seen how the proliferation of centralized and distributed renewables on the grid has already dramatically changed the cost profile of traditional generation and variability of wholesale energy prices. This signals the real cost drivers in the future will come from optimizing energy service with things like batteries, microgrids and peer-to-peer trading networks. In the foreseeable future, flat electricity rates may be the norm, or electricity might even become entirely free as services become the primary source of utility revenue.

The key to this future is technological innovation that allows utilities to better understand a customer’s unique needs and priorities and then deliver personalized, well-timed solutions that make customers feel valued and appreciated as their utility helps them save and alleviates their greatest pain points.

I predict utilities that adopt new technologies focused on customer experience, aligned with key utility trends shaping the sector, and deliver continual service improvements and optimization will earn the most satisfied, most loyal customers.

To illustrate this, look at how fixed pricing today is applied for most residential customers. Unless you live in one of the states with deregulated utilities where most customers are free to choose a service provider in a competitive marketplace, as consumers in power markets increasingly reshape offerings, fixed-rate tariffs or time-of-use tariffs might be the only rate structures you have ever known, though new utility rate designs are being tested nationwide today. These tariffs are often market distortions, bearing little relation to the real-time price that the utility pays on the wholesale market.

It can be easy enough to compare the rate you pay as a consumer and the market rate that utilities pay. The California ISO has a public dashboard -- as do other grid operators -- that shows the real-time marginal cost of energy. On a recent Friday, for example, a buyer in San Francisco could go to the real-time market and procure electricity at a rate of around 9.5 cents per kilowatt-hour (kWh), yet a residential customer can pay the utility PG&E between 22 cents and 49 cents per kWh amid major changes to electric bills being debated, depending on usage.

The problem is that utility customers do not usually see this data or know how to interpret it in a way that helps add value to their service or drive down the cost.

This is a scenario ripe for innovation. Artificial intelligence (AI) technologies are beginning to be applied to give customers the transparency and control over the energy they desire, and a new type of utility is emerging using real-time pricing signals from wholesale markets to give households hassle-free energy savings. Evolve Energy in Texas is developing a utility service model, even as Texas utilities revisit smart home network strategies, that delivers electricity to consumers at real-time market prices and connects to smart thermostats and other connected devices in the home for simple monitoring and control -- all managed via an intuitive consumer app.

My company, Bidgely, partners with utilities and energy retailers all over the world to apply artificial intelligence and machine learning algorithms to customer data in order to bring transparency to their electricity bills, showing exactly where the customers’ money is going down to the appliance and offering personalized, actionable advice on how to save.

Another example is from energy management company Keewi. Its wireless outlet adaptors are revealing real-time energy usage information to Texas A&M dorm residents as well as providing students the ability to conserve energy through controlling items in their rooms from their smartphones.

These are but a few examples of innovations among many in play that answer the consumer demand for increased transparency and control over energy usage.

Electric service providers will be closely watching how consumers respond to AI-driven innovation, including providers in traditionally regulated markets that are exploring equitable regulation approaches now, to stay aligned with policy and customer expectations. While regulated utilities have no reason to fear that their customers might sign up with a competitor, they understand that the revenues from electricity sales are going down and the deployment of distributed energy resources is going up. Both trends were reflected in a March report from Bloomberg New Energy Finance (via ThinkProgress) that claimed unsubsidized storage projects co-located with solar or wind are starting to compete with coal and gas for dispatchable power. Change is coming to regulated markets, and some of that change can be attributed to customer dissatisfaction with utility service.

Like so many industries before, the utility-customer relationship is on track to become less about measuring unit sales and more about driving revenue through services and delivering the best customer value. Loyal customers are most likely to listen and follow through on the utility’s advice and to trust the utility for a wide range of energy-related products and services. Utilities that make customer experience the highest priority today will emerge tomorrow as the leaders of a new energy service era.

 

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Cape Town to Build Own Power Plants, Buy Additional Electricity

Cape Town Renewable Energy Plan targets 450+ MW via solar, wind, and battery storage, cutting Eskom reliance, lowering greenhouse gas emissions, stabilizing electricity prices, and boosting grid resilience through municipal procurement, PPAs, and city-owned plants.

 

Key Points

A municipal plan to procure over 450 MW, cut Eskom reliance, stabilize prices, and reduce Cape Town emissions.

✅ Up to 150 MW from private plants within the city

✅ 300 MW to be purchased from outside Cape Town later

✅ City financing 100-200 MW of its own generation

 

Cape Town is seeking to secure more than 450 megawatts of power from renewable sources to cut reliance on state power utility Eskom Holdings SOC Ltd., where wind procurement cuts were considered during lockdown, and reduce greenhouse gas emissions.

South Africa’s second-biggest city is looking at a range of options, including geothermal exploration in comparable markets, and expects the bulk of the electricity to be generated from solar plants, Kadri Nassiep, the city’s executive director of energy and climate change, said in an interview.

On July 14 the city of 4.6 million people released a request for information to seek funding to build its own plants. This month or next it will seek proposals for the provision of as much as 150 megawatts from privately owned plants, largely solar additions, to be built and operated within the city, he said. As much as 300 megawatts may also be purchased at a later stage from plants outside of Cape Town, according to Nassiep.

The city could secure finance to build 100 to 200 megawatts of its own generation capacity, Nassiep said. “We realized that it is important for the city to be more in control around the pricing of the power,” he added.

Power Outages

Cape Town’s foray into the securing of power from sources other than Eskom comes after more than a decade of intermittent electricity outages, while elsewhere in Africa coal projects face scrutiny from lenders, because the utility can’t meet national demand. The government last year said municipalities could find alternative suppliers.

Earlier this month Ethekwini, the municipal area that includes the city of Durban, issued a request for information for the provision of 400 megawatts of power, similar to BC Hydro’s call for power driven by EV uptake.

The City of Johannesburg will in September seek information and proposals for the construction of a 150-megawatt solar plant, reflecting moves like Ontario’s new wind and solar procurements to tackle supply gaps, 50 megawatts of rooftop solar panels and the refurbishment of an idle gas-fired plant that could generate 20 megawatts, it said in June. It will also seek information for the installation of 100 megawatts of battery storage.

Cape Town, which uses a peak of 1,800 megawatts of electricity in winter, hopes to start generating some of its own power next year, aligning with SaskPower’s 2030 renewables plan seen in Canada, according to a statement that accompanied its request for financing proposals.
 

 

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TTC Introduces Battery Electric Buses

TTC Battery-Electric Buses lead Toronto transit toward zero-emission mobility, improving air quality and climate goals with sustainable operations, advanced charging infrastructure, lower maintenance, energy efficiency, and reliable public transportation across the Toronto Transit Commission network.

 

Key Points

TTC battery-electric buses are zero-emission vehicles improving quality, lowering costs, and providing efficient service.

✅ Zero tailpipe emissions improve urban air quality

✅ Lower maintenance and energy costs increase savings

✅ Charging infrastructure enables reliable operations

 

The Toronto Transit Commission (TTC) has embarked on an exciting new chapter in its commitment to sustainability with the introduction of battery-electric buses to its fleet. This strategic move not only highlights the TTC's dedication to reducing its environmental impact but also positions Toronto as a leader in the evolution of public transportation. As cities worldwide strive for greener solutions, the TTC’s initiative stands as a significant milestone toward a more sustainable urban future.

Embracing Green Technology

The decision to integrate battery-electric buses into Toronto's transit system aligns with a growing trend among urban centers to adopt cleaner, more efficient technologies, including Metro Vancouver electric buses now in service. With climate change posing urgent challenges, transit authorities are rethinking their operations to foster cleaner air and reduce greenhouse gas emissions. The TTC’s new fleet of battery-electric buses represents a proactive approach to addressing these concerns, aiming to create a cleaner, healthier environment for all Torontonians.

Battery-electric buses operate without producing tailpipe emissions, and deployments like Edmonton's first electric bus illustrate this shift, offering a stark contrast to traditional diesel-powered vehicles. This transition is crucial for improving air quality in urban areas, where transportation is a leading source of air pollution. By choosing electric options, the TTC not only enhances the city’s air quality but also contributes to the global effort to combat climate change.

Economic and Operational Advantages

Beyond environmental benefits, battery-electric buses present significant economic advantages. Although the initial investment for electric buses may be higher than that for conventional diesel buses, and broader adoption challenges persist, the long-term savings are substantial. Electric buses have lower operating costs due to reduced fuel expenses and less frequent maintenance requirements. The electric propulsion system generally involves fewer moving parts than traditional engines, resulting in lower overall maintenance costs and improved service reliability.

Moreover, the increased efficiency of electric buses translates into reduced energy consumption. Electric buses convert a larger proportion of energy from the grid into motion, minimizing waste and optimizing operational effectiveness. This not only benefits the TTC financially but also enhances the overall experience for riders by providing a more reliable and punctual service.

Infrastructure Development

To support the introduction of battery-electric buses, the TTC is also investing in necessary infrastructure upgrades, including the installation of charging stations throughout the city. These charging facilities are essential for ensuring that the electric fleet can operate smoothly and efficiently. By strategically placing charging stations at transit hubs and along bus routes, the TTC aims to create a seamless transition for both operators and riders.

This infrastructure development is critical not just for the operational capacity of the electric buses but also for fostering public confidence in this new technology, and consistent safety measures such as the TTC's winter safety policy on lithium-ion devices reinforce that trust. As the TTC rolls out these vehicles, clear communication regarding their operational logistics, including charging times and routes, will be essential to inform and engage the community.

Engaging the Community

The TTC is committed to engaging with Toronto’s diverse communities throughout the rollout of its battery-electric bus program. Community outreach initiatives will help educate residents about the benefits of electric transit, addressing any concerns and building public support, and will also discuss emerging alternatives like Mississauga fuel cell buses in the region. Informational campaigns, workshops, and public forums will provide opportunities for dialogue, allowing residents to voice their opinions and learn more about the technology.

This engagement is vital for ensuring that the transition is not just a top-down initiative but a collaborative effort that reflects the needs and interests of the community. By fostering a sense of ownership among residents, the TTC can cultivate support for its sustainable transit goals.

A Vision for the Future

The TTC’s introduction of battery-electric buses marks a transformative moment in Toronto’s public transit landscape. This initiative exemplifies the commission's broader vision of creating a more sustainable, efficient, and user-friendly transportation network. As the city continues to grow, the need for innovative solutions to urban mobility challenges becomes increasingly critical.

By embracing electric technology, the TTC is setting an example for other transit agencies across Canada and beyond, and piloting driverless EV shuttles locally underscores that leadership. This initiative is not just about introducing new vehicles; it is about reimagining public transportation in a way that prioritizes environmental responsibility and community engagement. As Toronto moves forward, the integration of battery-electric buses will play a crucial role in shaping a cleaner, greener future for urban transit, ultimately benefitting residents and the planet alike.

 

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Mercury in $3 billion takeover bid for Tilt Renewables

Mercury Energy Tilt Renewables acquisition signals a trans-Tasman energy push as PowAR and Mercury split assets via a scheme of arrangement, offering $7.80 per share and a $2.96b valuation across Australia and New Zealand.

 

Key Points

A PowAR-Mercury deal to buy Tilt Renewables, splitting Australian and New Zealand assets via a court-approved scheme.

✅ $7.80 per share, valuing Tilt at $2.96b

✅ PowAR takes AU assets; Mercury gets NZ business

✅ Infratil and Mercury to vote for the scheme

 

Mercury Energy and an Australian partner appear to have won the race to buy Tilt Renewables, an Australasian wind farm developer which was spun out of TrustPower, bidding almost $3 billion, amid wider utility consolidation such as the Peterborough Distribution sale to Hydro One.

Yesterday Tilt Renewables announced that it had entered a scheme implementation agreement under which it was proposed that PowAR would acquire its Australian business and Mercury would acquire the New Zealand business, mirroring cross-border approvals where U.S. antitrust clearance shaped Hydro One's bid for Avista.

Conducted through a scheme of arrangement, Tilt shareholders will be offered $7.80 a share, valuing Tilt at $2.96b.

Yesterday morning shares in Tilt opened about 18 per cent up at $7.65, though regulatory outcomes can swing valuations as seen when Hydro One-Avista reconsideration of a U.S. order came into play.

In early December Infratil, which owns around two thirds of Tilt's shares, announced it was undertaking a review of its investment after receiving approaches, with investor sentiment sensitive to governance shifts as when Hydro One shares fell after leadership changes in Ontario.

According to a report in the Australian Financial Review, the transtasman bid beat out other parties including ASX-listed APA Group, Canadian pension fund CDPQ and Australian fund manager Infrastructure Capital Group, as Canadian investors like Ontario Teachers' Plan pursue similar infrastructure deals.

“This compelling acquisition proposal is a result of Tilt Renewables’ constant focus on delivering long-term value for shareholders and the board is pleased that, with these new owners, the transition to renewables in Australia and New Zealand will continue to accelerate,” Tilt’s chairman Bruce Harker said.

Comparable community-led clean energy partnerships, such as initiatives with British Columbia First Nations highlighted in clean-energy generation, underscore the broader momentum.

Just prior to the announcement, Tilt shares had been trading for less than $4. Such repricing reflects how utilities can face perceived uncertainties, as one investor argued too many unknowns at the time.

Mercury is already Tilt’s second largest shareholder, at just under 20 per cent. Both Infratil and Mercury have agreed to vote in favour of the scheme. The deal values Tilt’s New Zealand business at $770m, however the value of Mercury’s existing shareholding is around $585m, meaning the company will increase debt by around $185m.

 

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