Italy plans to resume building atomic plants

By New York Times


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Italy announced that within five years it planned to resume building nuclear energy plants, two decades after a public referendum resoundingly banned nuclear power and deactivated all its reactors.

“By the end of this legislature, we will put down the foundation stone for the construction in our country of a group of new-generation nuclear plants,” said Claudio Scajola, minister of economic development. “An action plan to go back to nuclear power cannot be delayed anymore.”

The change is a striking sign of the times, reflecting growing concern in many European countries over the skyrocketing price of oil and energy security, and the warming effects of carbon emissions from fossil fuels. All have combined to make this once-scorned form of energy far more palatable.

“Italy has had the most dramatic, the most public turnaround, but the sentiments against nuclear are reversing very quickly all across Europe — Holland, Belgium, Sweden, Germany and more,” said Ian Hore-Lacey, spokesman for the World Nuclear Association, an industry group based in London.

The rehabilitation of nuclear power was underscored in January when John Hutton, the British business secretary, grouped it with “other low-carbon sources of energy” like biofuels. It was barely mentioned in the government action plan on energy three years earlier.

Echoing the sentiment, Mr. Scajola said, “Only nuclear plants safely produce energy on a vast scale with competitive costs, respecting the environment.”

A number of European countries have banned or restricted nuclear power in the past 20 years, including Italy, which closed all its plants. Germany and Belgium have long prohibited the building of reactors, although existing ones were allowed to run their natural lifespan. France was one of the few countries that continued to rely heavily on nuclear power.

Environmental groups in Italy immediately attacked any plan to bring back nuclear power. Giuseppe Onufrio, a director of Greenpeace Italy, called the announcement “a declaration of war.”

Emma Bonino, an opposition politician and vice president of the Italian Senate, said building nuclear plants made no economic sense because they would not be ready for at least 20 years.

“We should be investing more in solar and wind,” she said. “We should be moving much more quickly to improve energy efficiency, of buildings, for example. That’s something Italy has never done anything with.”

But conditions were very different in the 1980s, when European countries turned away from nuclear power. Oil cost less than $50 a barrel, global warming was a fringe science and climate change had not been linked to manmade emissions. Perhaps more important for the public psyche, almost all of EuropeÂ’s nuclear bans and restrictions were enacted after the 1986 Chernobyl disaster in the Soviet Union in which radioactivity was released into the environment.

The equation has changed. Today, with oil approaching $150 a barrel, most European countries, which generally have no oil and gas resources, have been forced by finances to consider new forms of energy — and fast. New nuclear plants take 20 years to build. Also, Europeans watched in horror in 2006 as President Vladimir V. Putin of Russia cut off the natural gas supply to Ukraine in a price dispute, leaving it in darkness.

New green technologies, like solar power, wind and biofuel, cannot yet form the backbone of a countryÂ’s energy strategy, and it is not clear that they will ever achieve that level.

Italy is the largest net energy importer in Europe, but nearly all European countries rely heavily on imported energy — particularly oil and gas.

Enel, Italy’s leading energy provider, announced this year that it would close its oil-fired power plants because the fuel had become unaffordable. Italians pay the highest energy prices in Europe. Enel has been building coal plants to fill the void left by oil. Coal plants are cheaper but create relatively high levels of carbon emissions, even using the type of new “clean coal” technology Enel had planned.

A few European countries, like Germany and Poland, could likewise fall back on their abundant coal reserves if they rejected oil and gas — but most of the coal mined in each country is of low grade and pollutes highly.

After the government announcement opening Italy to nuclear power, Enel’s managing director, Fulvio Conti, said, “We are ready.” But he added that “new regulation and strong agreement on the plan within the country” would be needed.

Enel, which operates power plants in several European countries, already has at least one nuclear plant, in Bulgaria, and has been researching so-called fourth-generation nuclear reactors, which are intended to be safer and to minimize waste and the use of natural resources. ItalyÂ’s old reactors still exist, but are too outdated to be reopened. New ones would have to be built.

The Italian government laid out few specifics to back its announcement and officials at the Ministry of Economic Development said they were still studying issues like exactly what kind of plants could be built, and whether a new referendum would be required to re-open Italy to nuclear power.

Marzia Marzioli, who leads a citizens’ campaign against new coal plants in Italy, said nuclear was equally repellent. “As with coal, nuclear energy is the exact opposite of what we would like for Italy.”

“It is a choice that doesn’t consider the alternatives,” such as solar power, she said.

To build nuclear plants, Italy would almost certainly have to improve its system of dealing with nuclear waste. The plants that were shut down years ago still store 235 tons of nuclear fuel.

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Warren Buffett’s Secret To Cheap Electricity: Wind

Berkshire Hathaway Energy Wind Power drives cheap electricity rates in Iowa via utility-scale wind turbines, integrated transmission, battery storage, and grid management, delivering renewable energy, stable pricing, and long-term rate freezes through 2028.

 

Key Points

A vertically integrated wind utility lowering Iowa rates via owned generation, transmission, and advanced grid control.

✅ Owned wind assets meet Iowa residential demand

✅ Integrated transmission lowers costs and losses

✅ Rate freeze through 2028 sustains cheap power

 

In his latest letter to Berkshire Hathaway shareholders, Warren Buffett used the 20th anniversary of Berkshire Hathaway Energy to tout its cheap electricity bills for customers.

When Berkshire purchased the majority share of BHE in 2000, the cost of electricity for its residential customers in Iowa was 8.8 cents per kilowatt-hour (kWh) on average. Since then, these electricity rates have risen at a paltry <1% per year, with a freeze on rate hikes through 2028. As anyone who pays an electricity bill knows, that is an incredible deal.  

As Buffett himself notes with alacrity, “Last year, the rates [BHE’s competitor in Iowa] charged its residential customers were 61% higher than BHE’s. Recently, that utility received a rate increase that will widen the gap to 70%.”

 

The Winning Strategy

So, what’s Buffett’s secret to cheap electricity? Wind power.

“The extraordinary differential between our rates and theirs is largely the result of our huge accomplishments in converting wind into electricity,” Buffett explains. 

Wind turbines in Iowa that BHE owns and operates are expected to generate about 25.2 million megawatt-hours (MWh) of electricity for its customers, as projects like Building Energy operations begin to contribute. By Buffett’s estimations, that will be enough to power all of its residential customers’ electricity needs in Iowa.  


The company has plans to increase its renewable energy generation in other regions as well. This year, BHE Canada is expected to start construction on a 117.6MW wind farm in Alberta, Canada with its partner, Renewable Energy Systems, that will provide electricity to 79,000 homes in Canada’s oil country.

Observers note that Alberta is a powerhouse for both green energy and fossil fuels, underscoring the region's unique transition.

But I would argue that the secret to BHE’s success perhaps goes deeper than transitioning to sources of renewable energy. There are plenty of other utility companies that have adopted wind and solar power as an energy source. In the U.S., where renewable electricity surpassed coal in 2022, at least 50% of electricity customers have the option to buy renewable electricity from their power supplier, according to the Department of Energy. And some states, such as New York, have gone so far as to allow customers to pick from providers who generate their electricity.

What differentiates BHE from a lot of the competition in the utility space is that it owns the means to generate, store, transmit and supply renewable power to its customers across the U.S., U.K. and Canada, with lessons from the U.K. about wind power informing policy.

In its financial filings for 2019, the company reported that it owns 33,600MW of generation capacity and has 33,400 miles of transmission lines, as well as a 50% interest in Electric Transmission Texas (ETT) that has approximately 1,200 miles of transmission lines. This scale and integration enables BHE to be efficient in the distribution and sale of electricity, including selling renewable energy across regions.

BHE is certainly not alone in building renewable-energy fueled electricity dominions. Its largest competitor, NextEra, built 15GW of wind capacity and has started to expand its utility-scale solar installations. Duke Energy owns and operates 2,900 MW of renewable energy, including wind and solar. Exelon operates 40 wind turbine sites across the U.S. that generate 1,500 MW.

 

Integrated Utilities Power Ahead

It’s easy to see why utility companies see wind as a competitive source of electricity compared to fossil fuels. As I explained in my previous post, Trump’s Wrong About Wind, the cost of building and generating wind energy have fallen significantly over the past decade. Meanwhile, improvements in battery storage and power management through new technological advancements have made it more reliable (Warren Buffett bet on that one too).

But what is also striking is that integrated power and transmission enables these utility companies to make those decisions; both in terms of sourcing power from renewable energy, as well as the pricing of the final product. Until wind and solar power are widespread, these utility companies are going to have an edge of the more fragmented ends of the industry who can’t make these purchasing or pricing decisions independently. 

Warren Buffett very rarely misses a beat. He’s not the Oracle of Omaha for nothing. Berkshire Hathaway’s ownership of BHE has been immensely profitable for its shareholders. In the year ended December 31, 2019, BHE and its subsidiaries reported net income attributable to BHE shareholders of $2.95 billion.

There’s no question that renewable energy will transform the utility industry over the next decade. That change will be led by the likes of BHE, who have the power to invest, control and manage their own energy generation assets.

 

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Opinion: UK Natural Gas, Rising Prices and Electricity

European Energy Market Crisis drives record natural gas and electricity prices across the EU, as LNG supply constraints, Russian pipeline dependence, marginal pricing, and renewables integration expose volatility in liberalised power markets.

 

Key Points

A 2021 surge in European gas and electricity prices from supply strains, demand rebounds, and marginal pricing exposure.

✅ Record TTF gas and day-ahead power prices across Europe

✅ LNG constraints and Russian pipeline dependence tightened supply

✅ Debate over marginal pricing vs regulated models intensifies

 

By Ronan Bolton

The year 2021 was a turbulent one for energy markets across Europe, as Europe's energy nightmare deepened across the region. Skyrocketing natural gas prices have created a sense of crisis and will lead to cost-of-living problems for many households, as wholesale costs feed through into retail prices for gas and electricity over the coming months.

This has created immediate challenges for governments, but it should also encourage us to rethink the fundamental design of our energy markets as we seek to transition to net zero, with many viewing it as a wake-up call to ditch fossil fuels across the bloc.

This energy crisis was driven by a combination of factors: the relaxation of Covid-19 lockdowns across Europe created a surge in demand, while cold weather early in the year diminished storage levels and contributed to increasing demand from Asian economies. A number of technical issues and supply-side constraints also combined to limit imports of liquefied natural gas (LNG) into the continent.

Europe’s reliance on pipeline imports from Russia has once again been called into question, as Gazprom has refused to ride to the rescue, only fulfilling its pre-existing contracts. The combination of these, and other, factors resulted in record prices – the European benchmark price (the Dutch TTF Gas Futures Contract) reached almost €180/MWh on 21 December, with average day-ahead electricity prices exceeding €300/MWh across much of the continent in the following days.

Countries which rely heavily on natural gas as a source of electricity generation have been particularly exposed, with governments quickly put under pressure to intervene in the market.

In Spain the government and large energy companies have clashed over a proposed windfall tax on power producers. In Ireland, where wind and gas meet much of the country’s surging electricity demand, the government is proposing a €100 rebate for all domestic energy consumers in early 2022; while the UK government is currently negotiating a sector-wide bailout of the energy supply sector and considering ending the gas-electricity price link to curb bills.

This follows the collapse of a number of suppliers who had based their business models on attracting customers with low prices by buying cheap on the spot market. The rising wholesale prices, combined with the retail price cap previously introduced by the Theresa May government, led to their collapse.

While individual governments have little control over prices in an increasingly globalised and interconnected natural gas market, they can exert influence over electricity prices as these markets remain largely national and strongly influenced by domestic policy and regulation. Arising from this, the intersection of gas and power markets has become a key site of contestation and comment about the role of government in mitigating the impacts on consumers of rising fuel bills, even as several EU states oppose major reforms amid the price spike.

Given that renewables are constituting an ever-greater share of production capacity, many are now questioning why gas prices play such a determining role in electricity markets.

As I outline in my forthcoming book, Making Energy Markets, a particular feature of the ‘European model’ of liberalised electricity trade since the 1990s has been a reliance on spot markets to improve the efficiency of electricity systems. The idea was that high marginal prices – often set by expensive-to-run gas peaking plants – would signal when capacity limits are reached, providing clear incentives to consumers to reduce or delay demand at these peak periods.

This, in theory, would lead to an overall more efficient system, and in the long run, if average prices exceeded the costs of entering the market, new investments would be made, thus pushing the more expensive and inefficient plants off the system.

The free-market model became established during a more stable era when domestically-sourced coal, along with gas purchased on long-term contracts from European sources (the North Sea and the Netherlands), constituted a much greater proportion of electricity generation.

While prices fluctuated, they were within a somewhat predictable range, and provided a stable benchmark for the long-term contracts underpinning investment decisions. This is no longer the case as energy markets become increasingly volatile and disrupted during the energy transition.

The idea that free price formation in a competitive market, with governments standing back, would benefit electricity consumers and lead to more efficient systems was rooted in sound economic theory, and is the basis on which other major commodity markets, such as metals and agricultural crops, have been organised for decades.

The free-market model applied to electricity had clear limitations, however, as the majority of domestic consumers have not been exposed directly to real-time price signals. While this is changing with the roll-out of smart meters in many countries, the extent to which the average consumer will be willing or able to reduce demand in a predicable way during peak periods remains uncertain.

Also, experience shows that governments often come under pressure to intervene in markets if prices rise sharply during periods of scarcity, thus undermining a basic tenet of the market model, with EU gas price cap strategies floated as one option.

Given that gas continues to play a crucial role in balancing supply and demand for electricity, the options available to governments are limited, illustrating why rolling back electricity prices is harder than it appears for policymakers. One approach would be would be to keep faith with the liberalised market model, with limited interventions to help consumers in the short term, while ultimately relying on innovations in demand side technologies and alternatives to gas as a means of balancing systems with high shares of variable renewables.

An alternative scenario may see a return to old style national pricing policies, involving a move away from marginal pricing and spot markets, even as the EU prepares to revamp its electricity market in response. In the past, in particular during the post-WWII decades, and until markets were liberalised in the 1990s, governments have taken such an approach, centrally determining prices based on the costs of delivering long term system plans. The operation of gas plants and fuel procurement would become a much more regulated activity under such a model.

Many argue that this ‘traditional model’ better suits a world in which governments have committed to long-term decarbonisation targets, and zero marginal cost sources, such as wind and solar, play a more dominant role in markets and begin to push down prices.

A crucial question for energy policy makers is how to exploit this deflationary effect of renewables and pass-on cost savings to consumers, whilst ensuring that the lights stay on.

Despite the promise of storage technologies such as grid-scale batteries and hydrogen produced from electrolysis, aside from highly polluting coal, no alternative to internationally sourced natural gas as a means of balancing electricity systems and ensuring our energy security is immediately available.

This fact, above all else, will constrain the ambitions of governments to fundamentally transform energy markets.

Ronan Bolton is Reader at the School of Social and Political Science, University of Edinburgh and Co-Director of the UK Energy Research Centre. His book Making Energy Markets: The Origins of Electricity Liberalisation in Europe is to be published by Palgrave Macmillan in 2022.

 

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Key Ontario power system staff may end up locked down at work sites due to COVID-19, operator says

Ontario IESO COVID-19 Control Room Measures detail how essential operators safeguard the electricity grid with split shifts, backup control centres, real-time balancing, deep cleaning, social distancing, and shelter-in-place readiness to maintain reliable power.

 

Key Points

Measures that protect essential grid operators with split shifts, backup sites, and hygiene to keep power reliable.

✅ Split teams across primary and backup control centres

✅ 12-hour shifts with remote handoffs and deep cleaning

✅ Real-time grid modeling to balance demand and supply

 

A group of personnel key to keeping Ontario's electricity system functioning may end up locked down in their control centres due to the COVID-19 crisis, according to the head of the province's power operator.

But that has so far proven unnecessary with a change-up in routine, Independent Electricity System Operator CEO Peter Gregg said.

While about 90 per cent of staff were sent to work from home on March 13, another 48 control-room operators deemed essential are still going into work, Gregg said in an interview.

"We identified a smaller cohort of critical operations room staff that need to go in to operate the system out of our control centres," Gregg said. "My biggest concern is to maintain their health, their safety as we rely on them to do this critical work."

Some of the operators manage power demand and supply in real time as Ontario electricity demand shifts, by calling for more or less generation and keeping an eye on the distribution grid, which also allows power to flow to and from Ontario's neighbours. Others do scenario planning and modelling to prepare for changes.

The essential operators have been split into eight teams of six each working 12-hour shifts. The day crew works out of a control centre near Toronto and the night shift out of a backup centre in the city's west end, Gregg said.

"That means that we're not having physical hand-off between control room operators on shift change -- we can do it remotely -- and it also allows us to do deep cleansing," Gregg said. "We're fortunate that the way the room is set up allows us to practice good social distancing."

Should it become necessary, he said, bed, food and other on-site arrangements have been made to allow the operators to stay at their workplaces as a similar agency in New York has done.

"If we do need to shelter these critical employees in place, we've got the ability to do so."

IESO is responsible for ensuring a balance between supply and demand for electricity across the province. Because power cannot be stored, the IESO ensures generators produce enough power to meet peak demand while making sure they don't produce too much.

"You're seeing, obviously, commercial demand drop, some industrial demand drop," Gregg said. "But you're also seeing a shift in the demand curve as well, where normally you have people heading off to work and so residential demand would go down. But obviously with them staying home, you're seeing an increase in residential electricity use across the province."

Some utilities have indicated no cuts to peak rates for self-isolating customers, with Hydro One peak pricing remaining in place for now.

IESO also runs and settles the wholesale electricity markets. Market prices are set based on accepted offers to supply electricity, while programs supporting stable electricity pricing for industrial and commercial users can affect costs against forecast demand.

With the pandemic forcing many businesses to close and people to stay home, and provincial electricity relief for families and small businesses in place, typical power needs fallen about seven per cent at a time of year that would normally see demand soften anyway. It remains to be seen whether, and how much, power needs shift further amid stringent isolation measures and the ongoing economic impact of the outbreak.

Gregg said the operator is constantly modeling different possibilities.

"What we do normally is prepare for all of these sort of emergency scenarios, as reflected in the U.S. grid response coverage, and test and drill for these," he said. "What we're experiencing over the last few weeks is that those drills come in handy because they help us prepare for when the real-time situation actually happens."

 

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Canada Invests Over $960-Million in Renewable Energy and Grid Modernization Projects

Smart Renewables and Electrification Pathways Program enables clean energy and grid modernization across Canada, funding wind, solar, hydro, geothermal, tidal, and storage to cut GHG emissions and accelerate electrification toward a net-zero economy.

 

Key Points

A $964M Canadian program funding clean power and grid upgrades to cut emissions and build net-zero electrified economy.

✅ Funds wind, solar, hydro, geothermal, tidal, and storage projects

✅ Modernizes grids for reliability, digitalization, and resilience

✅ Supports net-zero by 2050 with Indigenous and utility partners

 

Harnessing Canada's immense clean energy resources requires transformational investments to modernize our electricity grid. The Government of Canada is investing in renewable energy and upgrading the electricity grid, moving toward an electric, connected and clean economy, to make clean, affordable electricity options more accessible in communities across Canada.

The Honourable Seamus O'Regan Jr., Minister of Natural Resources, today launched a $964-million program, alongside a recent federal green electricity contract in Alberta that underscores momentum, to support smart renewable energy and grid modernization projects that will lower emissions by investing in clean energy technologies, like wind, solar, storage, hydro, geothermal and tidal energy across Atlantic Canada.

The Smart Renewables and Electrification Pathways Program (SREPs) supports building Canada's low-emissions energy future and a renewable, electrified economy through projects that focus on non-emitting, cleaner energy technologies, such as storage, and modernizing electricity system operations.

Investing in these technologies reduces greenhouse gas emissions by creating a cleaner, more connected electrical system, supporting progress toward zero-emissions electricity by 2035 goals, while helping Canada reach net-zero emissions by 2050.

Minister O'Regan launched the program during the Canadian Electricity Association's (CEA) virtual regulatory forum on Electricity Regulation & the Four Disruptors – Decarbonization, Decentralization, Digitalization and Democratization, highlighting evolving regulatory approaches as B.C. streamlines clean energy approvals to support deployment nationwide. The launch also coincides with Canadian Environment Week, which celebrates Canada's environmental accomplishments and encourages Canadians to contribute to conserving and protecting the environment.

Through SREPs and other programming, the government is working with provinces and territories, with the Prairie Provinces leading renewable growth in the years ahead, utilities, Indigenous partners and others, including diverse businesses and communities, to deliver these clean and reliable energy initiatives. With Canadian innovation, technology and skilled energy workers, we can provide more communities, households and businesses with an increased supply of clean electricity and a cleaner electrical grid.

To help interested stakeholders find information on SREPs, a new webpage has been launched, which includes a comprehensive guide for eligible projects.

This supports Canada's strengthened climate plan, A Healthy Environment and a Healthy Economy. Canada is advancing projects that support the clean grid of the future and seize opportunities in the global electricity market to boost competitiveness. Collectively with investments from the Fall Economic Statement 2020 and Budget 2021, Canada will achieve our climate change commitments and ensure a healthier environment and more prosperous economy for future generations.

 

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Construction of expanded Hoa Binh Hydropower Plant to start October 2020

Expanded Hoa Binh Hydropower Plant increases EVN capacity with 480MW turbines, commercial loan financing, grid stability, flood control, and Da River reliability, supported by PECC1 feasibility work and CMSC collaboration on site clearance.

 

Key Points

A 480MW EVN expansion on the Da River to enhance grid stability, flood control, and seasonal water supply in Vietnam.

✅ 480MW, two turbines, EVN-led financing without guarantees

✅ Improves frequency modulation and national grid stability

✅ Supports flood control and dry-season water supply

 

The extended Hoa Binh Hydropower Plant, which is expected to break ground in October 2020, is considered the largest power project to be constructed this year, even as Vietnam advances a mega wind project planned for 2025.

Covering an area of 99.2 hectares, the project is invested by Electricity of Vietnam (EVN). Besides, Vietnam Electricity Power Projects Management Board No.1 (EVNPMB1) is the representative of the investor and Power Engineering Consulting JSC 1 (EVNPECC1) is in charge of building the feasibility report for the project. The expanded Hoa Binh Hydro Power Plant has a total investment of VND9.22 trillion ($400.87 million), 30 per cent of which is EVN’s equity and the remaining 70 per cent comes from commercial loans without a government guarantee.

According to the initial plan, EVN will begin the construction of the project in the second quarter of this year and is expected to take the first unit into operation in the third quarter of 2023, a timeline reminiscent of Barakah Unit 1 reaching full power, and the second one in the fourth quarter of the same year.

Chairman of the Committee for Management of State Capital at Enterprises (CMSC) Nguyen Hoang Anh said that in order to start the construction in time, CMSC will co-operate with EVN to work with partners as well as local and foreign banks to mobilise capital, reflecting broader nuclear project milestones across the energy sector.

In addition, EVN will co-operate with Hoa Binh People’s Committee to implement site clearance, remove Ba Cap port and select contractors.

Once completed, the project will contribute to preventing floods in the rainy season and supply water in the dry season. The plant expansion will include two turbines with the total capacity of 480MW, similar in scale to the 525-MW hydropower station China is building on a Yangtze tributary, and electricity output of about 488.3 million kWh per year.

In addition, it will help improve frequency modulation capability and stabilise the frequency of the national electricity system through approaches like pumped storage capacity, and reduce the working intensity of available turbines of the plant, thus prolonging the life of the equipment and saving maintenance and repair costs.

Built in the Da River basin in the northern mountainous province of Hoa Binh, at the time of its conception in 1979, Hoa Binh was the largest hydropower plant in Southeast Asia, while projects such as China’s Lawa hydropower station now dwarf earlier benchmarks.

The construction was supported by the Soviet Union all the way through, designing, supplying equipment, supervising, and helping it go on stream. Construction began in November 1979 and was completed 15 years later in December 1994, when it was officially commissioned, similar to two new BC generating stations recently brought online.

 

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Ontario Teachers' Plan Acquires Brazilian Electricity Transmission Firm Evoltz

Ontario Teachers' Evoltz Acquisition expands electricity transmission in Brazil, adding seven grid lines across ten states, aligning infrastructure strategy with inflation-linked cash flows, renewable energy integration, Latin America and net-zero objectives pending regulatory approvals.

 

Key Points

A 100% purchase of Brazil's Evoltz, adding seven grid lines and delivering stable, inflation-linked cash flows.

✅ 100% stake in Evoltz with seven transmission lines

✅ Aligns with net-zero and renewable energy strategy

✅ Inflation-linked, core infrastructure cash flows in Brazil

 

The Ontario Teachers’ Pension Plan has acquired Evoltz Participações, an electricity transmission firm in Brazil, from US asset manager TPG. 

The retirement system took a 100% stake in the energy firm, Ontario Teachers’ said Monday. The acquisition has netted the pension fund seven electricity transmission lines that service consumers and businesses across 10 states in Brazil, amid dynamics similar to electricity rate reductions for businesses seen in Ontario. The firm was founded by TPG just three years ago. 

“Our strategy focuses on allocating significant capital to high-quality core infrastructure assets with lower risks and stable inflation-linked cash flows,” Dale Burgess, senior managing director of infrastructure and natural resources at Ontario Teachers, said in a statement. “Electricity transmission businesses are particularly attractive given their importance in facilitating a transition to a low-carbon economy.” 

The pension fund has invested in other electricity distribution companies recently. In March, Ontario Teachers’ took a 40% stake in Finland’s Caruna, and agreed to acquire a 25% stake in SSEN Transmission in the UK grid. For more than a decade, it has maintained a 50% stake in Chile-based transmission firm Saesa. 

The investment into Evoltz demonstrates Ontario Teachers’ growing portfolio in Brazil and Latin America, while activity in Ontario such as the Peterborough Distribution sale reflects ongoing utility consolidation. In 2016, the firm, with the Canada Pension Plan Investment Board (CPPIB), invested in toll roads in Mexico. They took a 49% stake with Latin American infrastructure group IDEAL. 

Evoltz, which delivers renewable energy, will also help decarbonize the pension fund’s portfolio. In January, the fund pledged to reach net-zero carbon emissions by 2050. Last year, Ontario Teachers’ issued its first green bond offering. The $890 million 10-year bond will help the retirement system fund sustainable investments aligned with policy measures like Ontario's subsidized hydro plan during COVID-19. 

However, Ontario Teachers’ has also received criticism for its investment into parts of Abu Dhabi’s gas pipeline network, and investor concerns about Hydro One highlight sector uncertainties. Last summer, it joined other institutional investors in investing $10.1 billion for a 49% stake. 

As of December, Ontario Teachers’ reached a portfolio with C$221.2 billion (US$182.5 billion) in assets. Since 1990, the fund has maintained a 9.6% annualized return. Last year, it missed its benchmark with an 8.6% return, with examples such as Hydro One shares fall after shake-up underscoring market volatility.

The pension fund expects the deal will close later this fall, pending closing conditions and regulatory approvals, including decisions such as the OEB combined T&D rates ruling that shape utility economics. 

 

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