OPG takes another step toward site preparation at Darlington

By Ontario Power Generation


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The Federal Government of Canada has responded to the recommendations of the Joint Review Panel of the Ontario Power Generation OPG, the province's power generator, and approved the Darlington New Nuclear Project Environmental Assessment EA.

This project is aimed at adding additional nuclear generation to OPG's Darlington power plant in Darlington, Ontario.

"OPG is pleased with the Federal GovernmentÂ’s decision," said Albert Sweetnam, OPGÂ’s Executive Vice President, Nuclear Projects. "We were confident in the conclusions of our extensive studies, however independent review and confirmation provides added assurance that the project will not result in any significant adverse environmental effects, given mitigation."

OPG now awaits a decision by the Joint Review Panel, as a panel of the Canadian Nuclear Safety Commission, the federal regulator for nuclear power in Canada, on the next key milestone: the issuance of the site preparation license. The site preparation license is the first of three licenses required to build and operate a new nuclear facility in Canada.

In 2009, OPG submitted the Environmental Impact Statement and supporting technical documents in support of the project, along with an updated application for a "license to prepare site." A federally appointed Joint Review Panel undertook an extensive review involving federal, provincial and municipal agencies, independent technical experts, and held 17 days of public hearings before recommending to the Federal Government they accept the EA.

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Power Outages to Mitigate Wildfire Risks

Colorado Wildfire Power Shutoffs reduce ignition risk through PSPS, grid safety protocols, data-driven forecasts, and emergency coordination, protecting communities, natural resources, and infrastructure during extreme fire weather fueled by drought and climate change.

 

Key Points

Planned PSPS outages cut power in high-risk areas to prevent ignitions, protect residents, and boost wildfire resilience.

✅ PSPS triggered by forecasts, fuel moisture, and fire danger indices.

✅ Utilities coordinate alerts, timelines, and critical facility support.

✅ Paired with forest management, education, and rapid response.

 

Colorado, known for its stunning landscapes and outdoor recreation, has implemented proactive measures to reduce the risk of wildfires by strategically shutting off power in high-risk areas, similar to PG&E wildfire shutoffs implemented in California during extreme conditions. This approach, while disruptive, aims to safeguard communities, protect natural resources, and mitigate the devastating impacts of wildfires that have become increasingly prevalent in the region.

The decision to initiate power outages as a preventative measure against wildfires underscores Colorado's commitment to proactive fire management and public safety, aligning with utility disaster planning practices that strengthen grid readiness. With climate change contributing to hotter and drier conditions, the state faces heightened wildfire risks, necessitating innovative strategies to minimize ignition sources and limit fire spread.

Utility companies, in collaboration with state and local authorities, identify areas at high risk of wildfire based on factors such as weather forecasts, fuel moisture levels, and historical fire data. When conditions reach critical thresholds, planned power outages, also known as Public Safety Power Shutoffs (PSPS), are implemented to reduce the likelihood of electrical equipment sparking wildfires during periods of extreme fire danger, particularly during windstorm-driven outages that elevate ignition risks.

While power outages are a necessary precautionary measure, they can pose challenges for residents, businesses, and essential services that rely on uninterrupted electricity, as seen when a North Seattle outage affected thousands last year. To mitigate disruptions, utility companies communicate outage schedules in advance, provide updates during outages, and coordinate with emergency services to ensure the safety and well-being of affected communities.

The implementation of PSPS is part of a broader strategy to enhance wildfire resilience in Colorado. In addition to reducing ignition risks from power lines, the state invests in forest management practices, wildfire prevention education, and emergency response capabilities, including continuity planning seen in the U.S. grid COVID-19 response, to prepare for and respond to wildfires effectively.

Furthermore, Colorado's approach to wildfire prevention highlights the importance of community preparedness and collaboration, and utilities across the region adopt measures like FortisAlberta precautions to sustain critical services during emergencies. Residents are encouraged to create defensible space around their properties, develop emergency evacuation plans, and stay informed about wildfire risks and response protocols. Community engagement plays a crucial role in building resilience and fostering a collective effort to protect lives, property, and natural habitats from wildfires.

The effectiveness of Colorado's proactive measures in mitigating wildfire risks relies on a balanced approach that considers both short-term safety measures and long-term fire prevention strategies. By integrating technology, data-driven decision-making, and community partnerships, the state aims to reduce the frequency and severity of wildfires while enhancing overall resilience to wildfire impacts.

Looking ahead, Colorado continues to refine its wildfire management practices in response to evolving environmental conditions and community needs, drawing on examples of localized readiness such as PG&E winter storm preparation to inform response planning. This includes ongoing investments in fire detection and monitoring systems, research into fire behavior and prevention strategies, and collaboration with neighboring states and federal agencies to coordinate wildfire response efforts.

In conclusion, Colorado's decision to implement power outages as a preventative measure against wildfires demonstrates proactive leadership in wildfire risk reduction and public safety. By prioritizing early intervention and community engagement, the state strives to safeguard vulnerable areas, minimize the impact of wildfires, and foster resilience in the face of increasing wildfire threats. As Colorado continues to innovate and adapt its wildfire management strategies, its efforts serve as a model for other regions grappling with the challenges posed by climate change and wildfire risks.

 

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Texas's new set of electricity regulators begins to take shape in wake of deep freeze, power outages

Texas PUC Appointments signal post-storm reform as Gov. Greg Abbott taps Peter Lake and advances Will McAdams for Senate confirmation, affecting ERCOT oversight, grid reliability, wholesale power pricing, and securitization for co-ops.

 

Key Points

Texas PUC appointments add Peter Lake and Will McAdams to steer ERCOT, grid reliability, and market policy.

✅ Peter Lake nominated chair to replace Arthur D'Andrea.

✅ Will McAdams advances toward Senate confirmation.

✅ Focus on ERCOT oversight, price cap debate, grid resilience.

 

A new set of Texas electricity regulators began to take shape Monday, as Gov. Greg Abbott nominated a finance expert to be the next chairman of the Public Utility Commission while his earlier choice of a PUC member moved toward Senate confirmation.

The Republican governor put forward Peter Lake of Austin, who has spent more than five years as an Abbott appointee to the Texas Water Development Board, as his second commission pick in as many weeks.

“I am confident he will bring a fresh perspective and trustworthy leadership to the PUC,” Abbott said of Lake, who once worked as a trader of futures and derivatives for a firm belonging to the Chicago Mercantile Exchange and more recently has eagerly promoted bonds for the State Water Implementation Fund for Texas.

“Peter’s expertise in the Texas energy industry and business management will make him an asset to the agency,” Abbott, who has touted grid readiness in recent months, said in a written statement. “I urge the Senate to swiftly confirm Peter’s appointment.”

On Monday, the Senate appeared to be moving quickly to confirm Abbott’s April 1 selection for the PUC, Will McAdams, president of Associated Builders and Contractors of Texas and a former legislative aide who helped write policy for regulated industries such as electricity.

McAdams was among the 129 nominees that the Senate Nominations Committee voted out, 8-0. His nomination heads now to the Senate floor.

All three of Abbott’s handpicked PUC commissioners who were in place before and during February’s calamitous winter storm have since quit or said they’re resigning, even as Sierra Club criticism of Abbott's demands intensified in the aftermath.

February’s polar vortex left in its wake physical and financial wreckage after a nonprofit grid operator answering to the PUC, amid calls for market reforms to avoid blackouts, shut off electricity to more than 4 million Texans, causing the deaths of at least 125 people, 13 of them in the Dallas-Fort Worth area.

Gov. Greg Abbott on Thursday named Will McAdams to the embattled Public Utility Commission of Texas. McAdams is a construction industry lobbyist with strong ties to the GOP-controlled Legislature. In Feb. 17 file photo, winter storm's snowfall andn large electrical transmission lines in South Arlington are pictured.

In a 45-minute confirmation hearing, McAdams, as lawmakers discussed ways to improve electricity reliability statewide, drew praise – and few tough questions.

McAdams, who previously worked for three GOP senators, testified that had he been on the commission in February, he would not have kept in place a controversial, $9,000-per-megawatt hour price cap on wholesale power for about 32 hours on Feb. 18-19.

“I don’t see myself making that decision,” he said.

McAdams, though, hedged slightly, saying he’s not privy to all information that the Electric Reliability Council of Texas, or ERCOT, and the PUC may have had at their disposal during the crisis.

The comments were notable because Lt. Gov. Dan Patrick and the Senate have fought with Abbott and the House over $16 billion in overcharges that, according to an independent market monitor, wrongly accrued near the end of the Feb. 15-19 outages.

Sen. Charles Schwertner, R-Georgetown, said the commission’s former chairwoman, DeAnn Walker, and Bill Magness, president of ERCOT, decided to hold the high cap in place because there “was still great concern about grid stability, even though there was significant reserves.”

He pressed McAdams to call that incorrect, which McAdams did.

“Given the fact pattern that I’m privy to, senator,” it wasn’t the right move, he said. “But again, there may be other facts out there. There probably are.”

McAdams acknowledged many homeowners and businesses were traumatized.

“The public’s confidence in the ability of the PUC to effectively regulate our electric markets has been badly damaged and shaken,” he said.

McAdams spoke favorably of renewable energy, calling wind and solar “absolutely valuable resources,” as the electricity sector faces profound change nationwide. To whatever extent those are not available, the PUC should “firm that up” with “dispatchable forms of generation,” such as gas, coal and nuclear, McAdams said.

He also called for lawmakers to consider providing electricity market bailout through “securitization,” or low-interest bond financing, to rural electric co-ops that were unable to pay the massive wholesale power bills they racked up during the February crisis.

“It would prevent those systems from having to front-load those costs onto their own members and smooth that out over a term of years,” while preventing an “uplift” of costs to other market participants who wisely hedged against soaring prices, McAdams said.

Noting that more than 400 bills have been filed to change ERCOT and how it’s governed, and as Texans prepare to vote on grid modernization funding this year, McAdams told the Senate panel, “It is clear to me that the Legislature wants meaningful changes to the status quo – to ensure that something positive comes out of this tragedy.”

Lake, who if confirmed by the Senate would replace Arthur D’Andrea as PUC chairman, grew up in Tyler. He attended prep school in New England and earned an undergraduate degree from the University of Chicago and a master of business administration degree from Stanford University.

He then worked for a commodities trading firm, a behavioral health company and as a business consultant before he became director of business development for Tyler-based Lake Ronel Oil Co. in 2014.

In late 2015, Abbott named Lake to the Texas Water Development Board and in February 2018 picked him to be the chairman of the three-member board that seeks to ensure water supplies for a fast-growing state.

Lake has steered the water board as it rolled out additional loans for water projects, approved by the Legislature and voters in 2013, and took the lead after Hurricane Harvey on flood control planning and infrastructure financing.

He’s posted exuberantly on Twitter as he toured agricultural water installations, lakes in West Texas and river authorities.

If confirmed, Lake and McAdams each would make $189,500 a year.

 

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Europe's Renewables Are Crowding Out Gas as Coal Phase-Out Slows

EU Renewable Energy Shift is cutting gas dependence as wind and solar expand, reshaping Europe's power mix, curbing emissions, and pressuring coal use amid a supply crisis and rising natural gas prices.

 

Key Points

An EU trend where wind and solar growth reduce gas reliance, curb coal, and lower power-sector emissions.

✅ Wind and solar displace gas in EU power mix

✅ Coal use rises as gas prices surge

✅ Emissions fall, but not fast enough for 1.5 C target

 

The European Union’s renewable energy sources are helping reduce its dependence on natural gas, under the current European electricity pricing framework, that’s still costing the region dearly.

Renewables growth has helped reduce the EU’s dependence on gas, as wind and solar outpaced gas across the bloc last year, which has soared in price since the middle of last year as the region grapples with a supply crisis that’s dealt blows to industries as well as ordinary consumers’ pockets. More than half of new renewable generation since 2019 has replaced gas power, according to a study by London-based climate think tank Ember, with the rest replacing mainly nuclear and coal sources.

“These are moments and paradigm shifts when governments and businesses start taking this much more seriously,” said Charles Moore, the lead author on the study, amid Covid-19 responses accelerating the transition across Europe. “The alternatives are available, they are cheaper, and they are likely to get even cheaper and more competitive. Renewables are now an opportunity, not a cost.”

The high price of gas relative to coal has meant utilities are leaning more on coal as a back-up for renewable generation, as stunted hydro and nuclear output has constrained low-carbon alternatives in parts of Europe, which risks the trajectory of Europe’s phase-out of the dirtiest fossil fuel. Last year, the EU’s coal use jumped disproportionately high relative to the rise in power generation as high gas prices boosted the relative profitability of burning coal instead.


Europe Coal Use Jumps as Costly Gas Turns Firms to Dirty Fuel
EU power generation from renewables reached a record high in 2021 of 547 terawatt-hours last year, accounting for an 11% increase compared to two years before, according to Ember’s Europe Electricity Review. It’s more than doubled in a decade, representing a 157% increase since 2011. 

Gas use declined last year for the second year in a row, as Europe explores storing electricity in gas pipelines to leverage existing infrastructure, reaching a level 8.1% lower than 2019. By contrast, coal use fell just 3.3% in the same period. Put simply, wind and solar did a great job of replacing coal during 2011-2019 but since then renewables have mostly been nudging out gas-fired power stations.

Ember’s Moore warned that the slowing phase-out of coal might require legislation to accelerate. The International Energy Agency recommends OECD countries cease using coal by the end of the decade to ensure alignment with the Paris Agreement target of keeping the world’s temperature increase below 1.5 Celsius, with renewables poised to eclipse coal globally by the mid-2020s lending momentum. 

“Europe can accelerate the phasing out of coal by building more renewable energy and faster,” said Felicia Aminoff,  an energy-transition analyst at BloombergNEF. “Wind and solar have no fuel costs, so as soon as you have made the initial investments to build wind and solar capacity it will start replacing generation that uses any kind of fuel, whether it is coal or gas.”

Overall, EU power sector emissions fell at less than half the rate required to hit that target, Ember’s report said. Spain produced the largest emissions reduction in the last two years, with renewables adding about 25 TWh and gas falling 15 TWh, and in Germany renewables topped coal and nuclear for the first time to support the shift. In contrast, heavy use of coal dragged down the bloc’s climate progress in Poland, where coal use rose about 8 TWh and renewables gained only 4 TWh.

 

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Wind Denmark - summer's autumn weather provides extraordinarily low electricity prices

Western Denmark Negative Electricity Prices stem from wind energy oversupply, grid congestion, and limited interconnector capacity via Nord Pool and TenneT, underscoring electrification needs, renewable integration, special regulation, and system flexibility.

 

Key Points

They are sub-zero power prices from wind oversupply, weak interconnectors, low demand, and balancing needs.

✅ Caused by high wind output, low demand, and export bottlenecks

✅ Limited Nord Pool interconnector capacity depresses prices

✅ Special regulation and district heating absorb excess power

 

A downturn in the cable connection to Norway and Sweden, together with low electricity consumption and high electricity production, has pushed down European electricity prices to a negative level in Western Denmark.

A sign that the electrification of society is urgently needed, says Soren Klinge, head of electricity market at Wind Denmark today.

The heavy winds during the first weekend of July, unlike periods when cheap wind power wanes in the UK, have not only had consequences for the Danes who had otherwise been looking forward to spending their first days at home in the garden or at the beach. It has also pushed down prices in the electricity market to a negative level, which especially the West Danish wind turbine owners have had to notice.

'The electricity market is currently affected by an unfortunate coincidence of various factors that have a negative impact on the electricity price: a reduced export capacity to the other Nordic countries, a low electricity consumption and a high electricity generation, reflecting broader concerns over dispatchable power shortages in Europe today. Unfortunately, the coincidence of these three factors means that the price base falls completely out of the market. This is another sign that the electrification of society is urgently needed, 'explains Soren Klinge, electricity market manager at Wind Denmark.

According to the European power exchange Nord Pool Spot, where UK peak power prices are also tracked, the cable connection to Sweden is expected to return to full capacity from 19 July. The connection between Jutland and Norway is only expected to return to full capacity in early September.

2000 MWh / hour in special regulation

During the windy weather on Monday morning, July 6, up to 2000 MWh / hour was activated at national level in the form of so-called special regulation. Special regulation is the designation that the German system operator TenneT switches off Danish electricity generation at cogeneration plants and wind turbines in order to help with the balancing of the German power system during such events. In addition, electric boilers at the cogeneration plants also contribute by using the electricity from the electricity grid and converting it to district heating for the benefit of Danish homes and businesses.

'The Danish wind turbines are probably the source of most of the special regulation, because there are very few cogeneration units to down-regulate electricity generation. Of course, it is positive to see that we have a high degree of flexibility in the wind-based power system at home. That being said, Denmark does not really get ahead with the green transition, even as its largest energy company plans to stop using coal by 2023, until we are able to raise electricity consumption based on renewable energy.

 

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Manitoba Hydro's burgeoning debt surpasses $19 billion

Manitoba Hydro Debt Load surges past $19.2B as the Crown corporation faces shrinking net income, restructuring costs, and PUB rate decisions, driven by Bipole III, Keeyask construction, aging infrastructure, and rising interest rate risks.

 

Key Points

Manitoba Hydro Debt Load refers to the utility's escalating borrowings exceeding $19B, pressuring rates and finances.

✅ Debt rose to $19.2B; projected near $25B within five years.

✅ Major drivers: Bipole III, Keeyask, aging assets, restructuring.

✅ Rate hikes sought; PUB approved 3.6% vs 7.9% request.

 

Manitoba Hydro's debt load now exceeds $19 billion as the provincial Crown corporation grapples with a shrinking net income amid ongoing efforts to slay costs.

The utility's annual report, to be released publicly on Tuesday, also shows its total consolidated net income slumped from $71 million in 2016-2017 to $37 million in the last fiscal year, mirroring a Hydro One profit drop as electricity revenue fell.

It said efforts to restructure the utility and reduce costs are partly to blame for the $34 million drop in year-over-year income.

These earnings come nowhere close, however, to alleviating Hydro's long-term debt problem, a dynamic also seen in a BC Hydro deferred costs report about customer exposure. The figure is pegged at $19.2 billion this fiscal year, up from $16.1 billion the previous year and $14.2 billion in 2016.

The utility projects its debt will grow to about $25 billion in the next five years. Its largest expenses include finishing the Bipole III line, working on the Keeyask Generating System that is halfway done and rebuilding aging wood poles and substations, the report said.

"This level of debt increases the potential financial exposure from risks facing the corporation and is a concern for both

the corporation and our customers who may be exposed to higher rate increases in the event of rising interest rates, a prolonged drought or a major system failure," outgoing president and CEO Kelvin Shepherd wrote.

The income drop is primarily a result of the $50 million spent in the form of restructuring charges associated with the utility's efforts to streamline the organization and drive down costs, amid NDP criticism of Hydro changes related to government policy.

Those efforts included the implementation of buyouts for employees through what the utility dubbed its "voluntary departure program."

Among the changes, Manitoba Hydro reduced its workforce by 800 employees, which is expected to save the utility over $90 million per year. It also reduced its management positions by 26 per cent, a Monday news release said, while Hydro One leadership upheaval in Ontario drove its shares down during comparable governance turmoil.

To improve its financial situation, Hydro has applied for rate increases, even as the Consumers Coalition pushes to have the proposal rejected. The Public Utilities Board offered a 3.6 per cent average rate hike, instead of the 7.9 per cent jump the utility asked for.

In May, when the PUB rendered its decision, it made several recommendations as an alternative to raising rates, including receiving a share of carbon tax revenue and asking the government to help pay for Bipole III.

Hydro is projecting a net income of $70 million for 2018-2019, which includes the impact of the recent rate increase. That total reflects an approximately 20 per cent reduction in net income from 2017-18 after restructuring costs are calculated.

 

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NDP takes aim at approval of SaskPower 8 per cent rate hike

SaskPower Rate Hike 2022-2023 signals higher electricity rates in Saskatchewan as natural gas costs surge; the Rate Review Panel approved increases, affecting residential utility bills amid affordability concerns and government energy policy shifts.

 

Key Points

An 8% SaskPower electricity rate increase split 4% in Sept 2022 and 4% in Apr 2023, driven by natural gas costs.

✅ 4% increase Sept 1, 2022; +4% on Apr 1, 2023

✅ Panel-approved amid natural gas price surge and higher fuel costs

✅ Avg residential bill up about $5 per step; affordability concerns

 

The NDP Opposition is condemning the provincial government’s decision to approve the Saskatchewan Rate Review Panel’s recommendation to increase SaskPower’s rates for the first time since 2018, despite a recent 10% rebate pledge by the Sask. Party.

The Crown electrical utility’s rates will increase four per cent this fall, and another four per cent in 2023, a trajectory comparable to BC Hydro increases over two years. According to a government news release issued Thursday, the new rates will result in an average increase of approximately $5 on residential customers’ bills starting on Sept. 1, 2022, and an additional $5 on April 1, 2023.

“The decision to increase rates is not taken lightly and came after a thorough review by the independent Saskatchewan Rate Review Panel,” Minister Responsible for SaskPower Don Morgan said in a news release, amid Nova Scotia’s 14% hike this year. “World events have caused a significant rise in the price of natural gas, and with 42 per cent of Saskatchewan’s electricity coming from natural gas-fueled facilities, SaskPower requires additional revenue to maintain reliable operations.”

But NDP SaskPower critic Aleana Young says the rate hike is coming just as businesses and industries are struggling in an “affordability crisis,” even as Manitoba Hydro scales back a planned increase next year.

She called the announcement of an eight per cent increase in power bills on a summer day before the long weekend “a cowardly move” by the premier and his cabinet, amid comparable changes such as Manitoba’s 2.5% annual hikes now proposed.

“Not to mention the Sask. Party plans to hike natural gas rates by 17% just days from now,” said Young in a news release issued Friday, as Manitoba rate hearings get underway nearby. “If Scott Moe thinks his choices — to not provide Saskatchewan families any affordability relief, to hike taxes and fees, then compound those costs with utility rate hikes — are defensible, he should have the courage to get out of his closed-door meetings and explain himself to the people of this province.”

The province noted natural gas is the largest generation source in SaskPower’s fleet. As federal regulations require the elimination of conventional coal generation in Canada by 2030, SaskPower’s reliance on natural gas generation is expected to grow, with experts in Alberta warning of soaring gas and power prices in the region. Fuel and Purchased Power expense increases are largely driven by increased natural gas prices, and SaskPower’s fuel and purchased power expense is expected to increase from $715 million in 2020-21 to $1.069 billion in 2023-24. This represents a 50 per cent increase in fuel and purchased power expense over three years.

“In the four years since our last increase SaskPower has worked to find internal efficiencies, but at this time we require additional funding to continue to provide reliable and sustainable power,” SaskPower president & CEO Rupen Pandya said in the release “We will continue to be transparent about our rate strategy and the need for regular, moderate increases.”

 

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