Canada's power sector reports record lows in occupational injuries

Texas Deep Freeze Energy Crisis strains grids as polar vortex triggers rolling blackouts, record natural gas and electricity prices, refinery shutdowns, WTI gains, and scarcity pricing across Texas, Oklahoma, SPP, and Mexico.

Key Points

A polar vortex slamming Texas energy: outages, record power prices, gas spikes, and reduced oil output.

✅ Record gas trades near $500/mmBtu; power hits $6,000/MWh

✅ WTI tops $60 as Texas shuts in ~1 million bpd

✅ Rolling blackouts across SPP; ERCOT scarcity pricing

A deep freeze is roiling electricity markets in more than a dozen U.S. states, leading to record-setting prices for electricity and natural gas, knocking oil production off line and shutting down some of North America’s largest refineries.

“It’s freakishly cold,” said Eric Fell, a senior natural gas analyst with Wood Mackenzie in Houston, where record cold temperatures and snow have blanketed the city, caused rolling power outages, shut down refineries and sent both natural gas and electricity prices soaring.

'It’s freakishly cold': Deep freeze slams North American energy sector

The polar vortex has led to freezing temperatures in every county in Texas, the largest energy-producing state in the U.S., and caused massive disruptions across the North American energy complex, triggering Texas power outages as far south as Mexico.

As the plunge in temperatures forced oil companies to shut in an estimated one million barrels of oil production in Texas on Monday, the West Texas Intermediate benchmark price rose above the US$60 per barrel threshold for the first time in a year to settle up 1 per cent, or US65 cents, at US$60.12 per barrel.

President Joe Biden declared an emergency on Monday, unlocking federal assistance to Texas.

People carry groceries from a local gas station on Monday in Austin, Texas. Winter storm Uri has brought historic cold weather to Texas, causing traffic delays and power outages. 

Frozen wind farms are just a small piece of Texas’s power grid woes right now.

Fell said regional natural gas and electricity prices in Oklahoma and Texas broke U.S. records over the weekend.

On Friday, Oklahoma gas transmission prices averaged US$350 per million British thermal units and Fell said one trade went as high as US$600 per mmBtu. In parts of the Texas panhandle and elsewhere, prices jumped to US$200, “all of which individually would have been new records,” Fell said, noting the previous record was US$160.

On Monday, natural gas for physical delivery in the U.S. was trading for as much as US$500 per mmBtu as demand for the heating and power plant fuel soared.  Spot gas has been trading for hundreds of dollars across the central U.S. since Thursday with a surge in heating demand triggering widespread blackouts and sending electricity prices soaring. The fuel normally trades in the region for less than US$3 per mmBtu.

Similarly, electricity prices in Texas surged to US$6,000 per megawatt hour on Monday, as U.S. power companies grapple with supply-chain constraints, which Fell said is “100 times the normal price.”

“You’re seeing scarcity pricing in power and gas. The only thing that’s different this time is it’s staying there – it’s not just an hour or two hours, it’s the whole day,” he said.

The blast of Arctic cold, which has blanketed Canada and much of the U.S., has created a massive draw on natural gas supplies, used both for home heating and industrial uses like electricity generation.

Little Rock, Ark.-based Southwest Power Pool, which coordinates electricity distribution for parts of 14 states including Oklahoma Kansas, Nebraska and even as far north as North Dakota, announced rolling blackouts across its network on Monday as a result of the power outages.

“In our history as a grid operator, this is an unprecedented event and marks the first time SPP has ever had to call for controlled interruptions of service” SPP’s executive vice-president and chief operating officer Lanny Nickell said in a release, adding the move was “a last resort” to “prevent circumstances from getting worse.”

The frigid conditions have led to a surge in natural gas prices across the continent, including in Alberta where the AECO benchmark price jumped to a seven-year high of $6.36 per thousand cubic feet last week, a price not seen since 2014.

Energy systems in Texas and Oklahoma, which are major energy exporters to other U.S. states, are built to withstand severe heat – not extreme cold. The result is a disruption to the gas supply at exactly the time the U.S. energy system is demanding those molecules.

“Given how far south it’s gone into Texas, this is where you have a lot of gas production that isn’t properly winterized,” said Jeremy McCrea, an analyst with Raymond James covering the natural gas industry.

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Ontario Nuclear Power Costs highlight LCOE, capex, refurbishment outlays, and waste management, compared with renewables, grid reliability, and emissions targets, informing Australia and Peter Dutton on feasibility, timelines, and electricity prices.

Key Points

They include high capex and LCOE from refurbishments and waste, offset by reliable, low-emission baseload.

✅ Refurbishment and maintenance drive lifecycle and LCOE variability.

✅ High capex and long timelines affect consumer electricity prices.

✅ Low emissions, but waste and safety compliance add costs.

Australian opposition leader Peter Dutton recently lauded Canada’s use of nuclear power as a model for Australia’s energy future. His praise comes as part of a broader push to incorporate nuclear energy into Australia’s energy strategy, which he argues could help address the country's energy needs and climate goals. However, the question arises: Is Ontario’s experience with nuclear power as cost-effective as Dutton suggests?

Dutton’s endorsement of Canada’s nuclear power strategy highlights a belief that nuclear energy could provide a stable, low-emission alternative to fossil fuels. He has pointed to Ontario’s substantial reliance on nuclear power, and the province’s exploration of new large-scale nuclear projects, as an example of how such an energy mix might benefit Australia. The province’s energy grid, which integrates a significant amount of nuclear power, is often cited as evidence that nuclear energy can be a viable component of a diversified energy portfolio.

The appeal of nuclear power lies in its ability to generate large amounts of electricity with minimal greenhouse gas emissions. This characteristic aligns with Australia’s climate goals, which emphasize reducing carbon emissions to combat climate change. Dutton’s advocacy for nuclear energy is based on the premise that it can offer a reliable and low-emission option compared to the fluctuating availability of renewable sources like wind and solar.

However, while Dutton’s enthusiasm for the Canadian model reflects its perceived successes, including recent concerns about Ontario’s grid getting dirtier amid supply changes, a closer look at Ontario’s nuclear energy costs raises questions about the financial feasibility of adopting a similar strategy in Australia. Despite the benefits of low emissions, the economic aspects of nuclear power remain complex and multifaceted.

In Ontario, the cost of nuclear power has been a topic of considerable debate. While the province benefits from a stable supply of electricity due to its nuclear plants, studies warn of a growing electricity supply gap in coming years. Ontario’s experience reveals that nuclear power involves significant capital expenditures, including the costs of building reactors, maintaining infrastructure, and ensuring safety standards. These expenses can be substantial and often translate into higher electricity prices for consumers.

The cost of maintaining existing nuclear reactors in Ontario has been a particular concern. Many of these reactors are aging and require costly upgrades and maintenance to continue operating safely and efficiently. These expenses can add to the overall cost of nuclear power, impacting the affordability of electricity for consumers.

Moreover, the development of new nuclear projects, as seen with Bruce C project exploration in Ontario, involves lengthy and expensive construction processes. Building new reactors can take over a decade and requires significant investment. The high initial costs associated with these projects can be a barrier to their economic viability, especially when compared to the rapidly decreasing costs of renewable energy technologies.

In contrast, the cost of renewable energy has been falling steadily, even as debates over nuclear power’s trajectory in Europe continue, making it a more attractive option for many jurisdictions. Solar and wind power, while variable and dependent on weather conditions, have seen dramatic reductions in installation and operational costs. These lower costs can make renewables more competitive compared to nuclear energy, particularly when considering the long-term financial implications.

Dutton’s praise for Ontario’s nuclear power model also overlooks some of the environmental and logistical challenges associated with nuclear energy. While nuclear power generates low emissions during operation, it produces radioactive waste that requires long-term storage solutions. The management of nuclear waste poses significant environmental and safety concerns, as well as additional costs for safe storage and disposal.

Additionally, the potential risks associated with nuclear power, including the possibility of accidents, contribute to the complexity of its adoption. The safety and environmental regulations surrounding nuclear energy are stringent and require continuous oversight, adding to the overall cost of maintaining nuclear facilities.

As Australia contemplates integrating nuclear power into its energy mix, it is crucial to weigh these financial and environmental considerations. While the Canadian model provides valuable insights, the unique context of Australia’s energy landscape, including its existing infrastructure, energy needs, and the costs of scrapping coal-fired electricity in comparable jurisdictions, must be taken into account.

In summary, while Peter Dutton’s endorsement of Canada’s nuclear power model reflects a belief in its potential benefits for Australia’s energy strategy, the cost-effectiveness of Ontario’s nuclear power experience is more nuanced than it may appear. The high capital and maintenance costs associated with nuclear energy, combined with the challenges of managing radioactive waste and ensuring safety, present significant considerations. As Australia evaluates its energy future, a comprehensive analysis of both the benefits and drawbacks of nuclear power will be essential to making informed decisions about its role in the country’s energy strategy.

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National Grid Cybersecurity Component Removal signals NCSC and GCHQ oversight of critical infrastructure, replacing NR Electric and Nari Technology grid control systems to mitigate supply chain risk, cyber threats, and blackout risk.

Key Points

A UK move to remove China-linked grid components after NCSC/GCHQ advice, reducing cyber and blackout risks.

✅ NCSC advice to remove NR Electric components

✅ GCHQ-linked review flags critical infrastructure risks

✅ Aims to cut blackout risk and supply chain exposure

Britain's National Grid has started removing components supplied by a unit of China-backed Nari Technology's from the electricity transmission network over cybersecurity fears, reflecting a wider push on protecting the power grid across critical sectors.

The decision came in April after the utility sought advice from the National Cyber Security Center (NCSC), a branch of the nation's signals intelligence agency, Government Communications Headquarters (GCHQ), amid campaigns like the Dragonfly campaign documented by Symantec, the newspaper quoted a Whitehall official as saying.

National Grid declined to comment citing "confidential contractual matters." "We take the security of our infrastructure very seriously and have effective controls in place to protect our employees and critical assets, while preparing for an independent operator transition in Great Britain, to ensure we can continue to reliably, safely and securely transmit electricity," it said in a statement.

The report said an employee at the Nari subsidiary, NR Electric Company-U.K., had said the company no longer had access to sites where the components were installed, at a time when utilities worldwide have faced control-room intrusions by state-linked hackers, and that National Grid did not disclose a reason for terminating the contracts.

It quoted another person it did not name as saying the decision was based on NR Electric Company-U.K.'s components that help control and balance the grid, respond to work-from-home demand shifts, and minimize the risk of blackouts.

It was unclear whether the components remained in the electricity transmission network, the report said, amid reports of U.S. power plant breaches that have heightened vigilance.

NR Electric Company-U.K., GCHQ and the Chinese Embassy in London did not immediately respond to requests for comment outside of business hours.

Britain's Department for Energy Security and Net Zero said that it did not comment on the individual business decisions taken by private organizations. "As a government department we work closely with the private sector to safeguard our national security, and to support efforts to fast-track grid connections across the network," it said in a statement.
 

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European Grid Frequency Clock Slowdown has made appliance clocks run minutes behind as AC frequency drifts on the 50 Hz electricity grid, driven by a Kosovo-Serbia billing dispute and ENTSO-E monitored supply-demand imbalance.

Key Points

An EU-wide timing error where 50 Hz AC deviations slow appliance clocks due to Kosovo-Serbia grid imbalances.

✅ Clocks drifted up to six minutes across interconnected Europe

✅ Cause: unpaid power in N. Kosovo, contested by Serbia

✅ ENTSO-E reported 50 Hz deviations from supply-demand mismatch

Over the past couple of months, Europeans have noticed time slipping away from them. It’s not just their imaginations: all across the continent, clocks built into home appliances like ovens, microwaves, and coffee makers have been running up to six minutes slow. The unlikely cause? A dispute between Kosovo and Serbia over who pays the electricity bill.

To make sense of all this, you need to know that the clocks in many household devices use the frequency of electricity to keep time. Electric power is delivered to our homes in the form of an alternating current, where the direction of the flow of electricity switches back and forth many times a second. (How this system came to be established is complex, but the advantage is that it allows electricity to be transmitted efficiently.) In Europe, this frequency is 50 Hertz — meaning a current alternating of 50 times a second. In America, it’s 60 Hz, and during peak summer demand utilities often prepare for blackouts as heat drives loads higher.

Since the 1930s, manufacturers have taken advantage of this feature to keep time. Each clock needs a metronome — something with a consistent rhythm that helps space out each second — and an alternating current provides one, saving the cost of extra components. Customers simply set the time on their oven or microwave once, and the frequency keeps it precise.

At least, that’s the theory. But because this timekeeping method is reliant on electrical frequency, when the frequency changes, so do the clocks. That is what has been happening in Europe.

The news was announced this week by ENTSO-E, the agency that oversees the single, huge electricity grid connecting 25 European countries and which recently synchronized with Ukraine to bolster regional resilience. It said that variations in the frequency of the AC caused by imbalances between supply and demand on the grid have been messing with the clocks. The imbalance is itself caused by a political argument between Serbia and Kosovo. “This is a very sensitive dispute that materializes in the energy issues,” Susanne Nies, a spokesperson for ENTSO-E, told The Verge.

Essentially, after Kosovo declared independence from Serbia in 2008, there were long negotiations over custody of utilities like telecoms and electricity infrastructure. As part of the ongoing agreements (Serbia still does not recognize Kosovo as a sovereign state), four Serb-majority districts in the north of Kosovo stopped paying for electricity. Kosovo initially covered this by charging the rest of the country more, but last December, it decided it had had enough and stopped paying. This led to an imbalance: the Kosovan districts were still using electricity, but no one was paying to put it on the grid.

This might sound weird, but it’s because electricity grids work on a system of supply and demand, where surging consumption has even triggered a Nordic grid blockade in response to constrained flows. As Stewart Larque of the UK’s National Grid explains, you want to keep the same amount of electricity going onto the grid from power stations as the amount being taken off by homes and businesses. “Think of it like driving a car up a hill at a constant speed,” Larque told The Verge. “You need to carefully balance acceleration with gravity.” (The UK itself has not been affected by these variations because it runs its own grid.)

“THEY ARE FREE-RIDING ON THE SYSTEM.”

This balancing act is hugely complex and requires constant monitoring of supply and demand and communication between electricity companies across Europe, and growing cyber risks have spurred a renewed focus on protecting the U.S. power grid among operators worldwide. The dispute between Kosovo and Serbia, though, has put this system out of whack, as the two governments have been refusing to acknowledge what the other is doing.

“The Serbians [in Kosovo] have, according to our sources, not been paying for their electricity. So they are free-riding on the system,” says Nies.

The dispute came to a temporary resolution on Tuesday, when the Kosovan government stepped up to the plate and agreed to pay a fee of €1 million for the electricity used by the Serb-majority municipalities. “It is a temporary decision but as such saves our network functionality,” said Kosovo’s prime minister Ramush Haradinaj. In the longer term, though, a new agreement will need to be reached.

There have been rumors that the increase in demand from northern Kosovo was caused by cryptocurrency miners moving into the area to take advantage of the free electricity. But according to ENTSO-E, this is not the case. “It is absolutely unrelated to cryptocurrency,” Nies told The Verge. “There’s a lot of speculation about this, and it’s absolutely unrelated.” Representatives of Serbia’s power operator, EMS, refused to answer questions on this.

For now, “Kosovo is in balance again,” says Nies. “They are producing enough [electricity] to supply the population. The next step is to take the system back to normal, which will take several weeks.” In other words, time will return to normal for Europeans — if they remember to change their clocks, even as the U.S. power grid sees more blackouts than other developed nations.

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CPUC Exit Fee Increase for CCAs adjusts the PCIA, affecting utilities, San Diego ratepayers, renewable energy procurement, customer equity, and cost allocation, while providing regulatory certainty for Community Choice Aggregation programs and clean energy goals.

Key Points

A CPUC-approved change raising PCIA exit fees paid by CCAs to utilities, balancing cost shifts and customer equity.

✅ PCIA rises from about 2.5c to roughly 4.25c per kWh in San Diego

✅ Aims to reduce cost shifts and protect non-CCA customers

✅ Offers regulatory certainty for CCA launches and clean energy goals

The California Public Utilities Commission approved an increase on the exit fees charged to customers who take part in Community Choice Aggregation -- government-run alternatives to traditional utilities like San Diego Gas & Electric.

After reviewing two competing exit fee proposals, all five commissioners voted Thursday in favor of an adjustment that many CCA advocates predicted could hamper the growth of the community choice movement.

But minutes after the vote was announced, one of the leading voices in favor of the city San Diego establishing its own CCA said the decision was good news because it provides some regulatory certainty.

"For us in San Diego, it's a green light to move forward with community choice," said Nicole Capretz, executive director of the Climate Action Campaign. "For us, it's let's go, let's launch and let's give families a choice. We no longer have to wait."

Under the CCA model, utilities still maintain transmission and distribution lines (poles and wires, etc.) and handle customer billing. But officials in a given local government entity make the final decisions about what kind of power sources are purchased.

Once a CCA is formed, its customers must pay an exit fee -- called a Power Charge Indifference Adjustment -- to the legacy utility serving that particular region. The fee is included in customers' monthly bills.

The fee is required to offset the costs of the investments utilities made over the years for things like natural gas power plants, renewable energy facilities and other infrastructure.

Utilities argue if the exit fee is set too low, it does not fairly compensate them for their investments; if it's too high, CCAs complain it reduces the financial incentive for their potential customers.

The Public Utilities Commission chose to adopt a proposal that some said was more favorable to utilities, leading to complaints from CCA boosters.

"We see this will really throw sand in the gears in our ability to do things that can move us toward (climate change) goals," Jim Parks, staff member of Valley Clean Energy, a CCA based in Davis, said before the vote.

Commissioner Carla Peterman, who authored the proposal that passed, said she supports CCAs but stressed the commission has a "legal obligation" to make sure increased costs are not shouldered by "customers who do not, or cannot, join a CCA. Today's proposal ensures a more level playing field between customers."

As for what the vote means for the exit fee in San Diego, Peterman's office earlier in the week estimated the charge would rise from 2.5 cents a kilowatt-hour to about 4.25 cents.

The Clear the Air Coaltion, a San Diego County group critical of CCAs, said the newly established exit fee -- which goes into effect starting next year -- is "a step in the direction."

But the group, which includes the San Diego Regional Chamber of Commerce, the San Diego County Taxpayers Association and lobbyists for Sempra Energy (the parent company of SDG&E), repeated concerns it has brought up before.

"If the city of San Diego decides to get into the energy business this decision means ratepayers in National City, Chula Vista, Carlsbad, Imperial Beach, La Mesa, El Cajon and all other neighboring communities would see higher energy bills, and San Diego taxpayers would be faced with mounting debt," coalition spokesman Tony Manolatos said in an email.

CCA supporters say community choice is critical in ensuring San Diego meets the pledge made by Mayor Kevin Faulconer to adopt the city's Climate Action Plan, mandating 100 percent of the city's electricity needs must come from renewable sources by 2035.

Now attention turns to Faulconer, who promised to make a decision on bringing a CCA proposal to the San Diego City Council only after the utilities commission made its decision.

A Faulconer spokesman said Thursday afternoon that the vote "provides the clarity we've been waiting for to move forward" but did not offer a specific time table.

"We're on schedule to reach Mayor Faulconer's goal of choosing a pathway that achieves our renewable energy goals while also protecting ratepayers, and the mayor looks forward to making his recommendation in the next few weeks," said Craig Gustafson, a Faulconer spokesman, in an email.

A feasibility study released last year predicted a CCA in San Diego has the potential to deliver cheaper rates over time than SDG&E's current service, while providing as much as 50 percent renewable energy by 2023 and 80 percent by 2027.

"The city has already figured out we are still capable of launching a program, having competitive, affordable rates and finally offering families a choice as to who their energy provider is," said Capretz, who helped draft an initial blueprint of the climate plan as a city staffer.

SDG&E has come to the city with a counterproposal that offers 100 percent renewables by 2035.

Thus far, the utility has produced a rough outline for a "tariff" program that would charge ratepayers the cost of delivering more clean sources of energy over time.

Some council members have expressed frustration more specifics have not been sketched out.

SDG&E officials said they will take the new exit fee into account as they go forward with their counterproposal to the city council.

Speaking in general about the utility commission's decision, SDG&E spokeswoman Helen Gao called it "a victory for our customers, as it minimizes the cost shifts that they have been burdened with under the existing fee formula.

"As commissioners noted in rendering their decision, reforming the (exit fee) addresses a customer-to-customer equity issue and has nothing to do with increasing profits for investor-owned utilities," Gao said in an email.

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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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