German renewables law under scrutiny

U.S. Data Center Power Demand is straining electric utilities and grid reliability as AI, cloud computing, and streaming surge, driving transmission and generation upgrades, demand response, and renewable energy sourcing amid rising electricity costs.

Key Points

The rising electricity load from U.S. data centers, affecting utilities, grid capacity, and energy prices.

✅ AI, cloud, and streaming spur hyperscale compute loads

✅ Grid upgrades: transmission, generation, and substations

✅ Demand response, efficiency, and renewables mitigate strain

U.S. electric utilities are facing a significant new challenge as the explosive growth of data centers puts unprecedented strain on power grids across the nation. According to a new report from Reuters, data centers' power demands are expected to increase dramatically over the next few years, raising concerns about grid reliability and potential increases in electricity costs for businesses and consumers.

What's Driving the Data Center Surge?

The explosion in data centers is being fueled by several factors, with grid edge trends offering early context for these shifts:

• Cloud Computing: The rise of cloud computing services, where businesses and individuals store and process data on remote servers, significantly increases demand for data centers.
• Artificial Intelligence (AI): Data-hungry AI applications and machine learning algorithms are driving a massive need for computing power, accelerating the growth of data centers.
• Streaming and Video Content: The growth of streaming platforms and high-definition video content requires vast amounts of data storage and processing, further boosting demand for data centers.

Challenges for Utilities

Data centers are notorious energy hogs. Their need for a constant, reliable supply of electricity places  heavy demand on the grid, making integrating AI data centers a complex planning challenge, often in regions where power infrastructure wasn't designed for such large loads. Utilities must invest significantly in transmission and generation capacity upgrades to meet the demand while ensuring grid stability.

Some experts warn that the growth of data centers could lead to brownouts or outages, as a U.S. blackout study underscores ongoing risks, especially during peak demand periods in areas where the grid is already strained. Increased electricity demand could also lead to price hikes, with utilities potentially passing the additional costs onto consumers and businesses.

Sustainable Solutions Needed

Utility companies, governments, and the data center industry are scrambling to find sustainable solutions, including using AI to manage demand initiatives across utilities, to mitigate these challenges:

• Energy Efficiency: Data center operators are investing in new cooling and energy management solutions to improve energy efficiency. Some are even exploring renewable energy sources like onsite solar and wind power.
• Strategic Placement: Authorities are encouraging the development of data centers in areas with abundant renewable energy and access to existing grid infrastructure. This minimizes the need for expensive new transmission lines.
• Demand Flexibility: Utility companies are experimenting with programs as part of a move toward a digital grid architecture to incentivize data centers to reduce their power consumption during peak demand periods, which could help mitigate power strain.

The Future of the Grid

The rapid growth of data centers exemplifies the significant challenges facing the aging U.S. electrical grid, with a recent grid report card highlighting dangerous vulnerabilities. It highlights the need for a modernized power infrastructure, capable of accommodating increasing demand spurred by new technologies while addressing climate change impacts that threaten reliability and affordability.  The question for utilities, as well as data center operators, is how to balance the increasing need for computing power with the imperative of a sustainable and reliable energy future.

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Alberta Ends Renewable Energy Moratorium, accelerating wind and solar deployment while prioritizing grid stability, reliability, and infrastructure upgrades to attract investment, cut emissions, meet climate targets, and integrate renewables into the provincial power system.

Key Points

It is Alberta's decision to lift a pause on new wind and solar projects while enhancing grid reliability.

✅ Resumes wind and solar development across Alberta.

✅ Focuses on grid stability and infrastructure upgrades.

✅ Aims to attract investment and meet climate targets.

The Alberta government has announced the end of a temporary suspension on the development of new renewable energy projects, as the power grid operator prepares to accept green energy bids across the market. This pause, which had been in place since May 2023, was initially implemented to evaluate the effects of rapid growth in renewable energy installations on the province's power grid and overall energy system. However, the decision to lift the moratorium reflects a shift in the government’s approach to balancing energy needs and environmental goals.

The suspension was introduced amid concerns that the swift expansion of wind and solar energy projects, including documented challenges with solar energy expansion in the province, could place undue stress on Alberta's electrical grid and infrastructure. Officials expressed worries about the ability of the grid to handle the increased load and the potential need for upgrades to accommodate new renewable energy sources. The government aimed to assess the implications of this growth and determine appropriate measures to ensure that the energy system could support both existing and future demands.

The moratorium drew significant criticism from various sectors, including renewable energy companies, environmental advocates, and local communities. Critics argued that the pause was detrimental to Alberta's efforts to transition to cleaner energy sources and meet climate targets, citing cases like TransAlta scrapping a wind farm amid policy uncertainty. They pointed out that halting projects could delay investments and job creation associated with the renewable energy sector, potentially impeding progress towards a more sustainable energy future.

In response to these concerns, the Alberta government conducted further reviews and consultations. The decision to cancel the pause reflects the government’s recognition of the importance of advancing renewable energy initiatives while also addressing the need for grid stability and infrastructure development. By ending the moratorium, the government aims to support the continued growth of renewable energy projects and maintain momentum in the shift towards greener energy solutions.

The lifting of the moratorium is expected to have a positive impact on the renewable energy industry in Alberta. Several planned projects that were put on hold can now proceed, leading to renewed investment and economic benefits, including a renewable energy surge that could power 4,500 jobs across the province. The government’s decision signals a commitment to integrating renewable energy sources into the provincial grid in a way that ensures both reliability and sustainability.

Going forward, the Alberta government plans to implement measures to better manage the integration of renewable energy into the existing power infrastructure. This includes addressing any potential challenges related to grid capacity and ensuring that the growth of renewable energy projects aligns with the province's overall energy strategy, as recent federal procurement such as a $500M green electricity contract with an Edmonton company underscores demand that integration efforts must accommodate. The goal is to create a balanced approach that supports the development of clean energy while maintaining the stability and efficiency of the energy system.

The end of the moratorium aligns with Alberta’s broader objectives to reduce greenhouse gas emissions and promote environmental sustainability within a province recognized as a powerhouse for both green energy and fossil fuels in Canada. The government’s approach reflects a willingness to adapt policies and strategies in response to evolving industry needs and environmental priorities. By removing the pause, Alberta demonstrates its commitment to fostering a diverse and resilient energy sector that can meet both current and future demands.

The decision to cancel the moratorium is also seen as a move to reinforce Alberta’s position as a leader in renewable energy development. With the lifting of restrictions, the province can continue to attract investment in clean energy projects, as neighboring jurisdictions such as B.C. streamline clean energy approvals to accelerate deployment, enhance its reputation as a progressive energy market, and contribute to global efforts to address climate change.

In summary, the Alberta government’s decision to lift the pause on renewable energy projects represents a significant shift in its approach to energy policy. The move reflects an acknowledgment of the importance of advancing renewable energy while addressing the practical challenges associated with grid management and infrastructure development. By ending the moratorium, Alberta aims to support the growth of clean energy initiatives and maintain its commitment to sustainability and environmental responsibility.

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Ontario Darlington SMR Expansion advances four GE Hitachi BWRX-300 reactors with OPG, adding 1,200 MW of baseload nuclear power to support electrification, grid reliability, and clean energy growth across Ontario and Saskatchewan.

Key Points

Plan to build four BWRX-300 SMRs at Darlington, delivering 1,200 MW of clean, reliable baseload power under OPG.

✅ Four GE Hitachi BWRX-300 units, 1,200 MW total

✅ Shared infrastructure cuts costs and timelines

✅ Supports electrification, grid reliability, net zero

The day after Ontario announced it would be building an additional 4,800 megawatts of nuclear reactors at Bruce Nuclear Generating Station, the province announced it would be dramatically expanding its planned rollout of small modular reactors at its Darlington Nuclear Generating Station, and confirmed plans to refurbish Pickering B as part of its broader strategy.

Ontario Power Generation OPG was always going to be the first to build the GE-Hitachi BWRX-300 small modular reactor SMR, with the U.S.’s Tennessee Valley Authority among others like SaskPower and several European nations following suit. But the OPG was originally going to build just one. On July 7, OPG and the Province of Ontario announced they would be bumping that up to four units of the BWRX-300.

The Ontario government is working with Ontario Power Generation (OPG) to commence planning and licensing for three additional small modular reactors (SMRs), for a total of four SMRs at the Darlington nuclear site. Once deployed, these four units would produce a total 1,200 megawatts (MW) of electricity, equivalent to powering 1.2 million homes, helping to meet increasing demand from electrification and fuel the province’s strong economic growth, the Ontario Ministry of Energy said in a release.

“Our government’s open for business approach has led to unprecedented investments across the province — from electric vehicles and battery manufacturing to critical minerals to green steel,” said Todd Smith, Minister of Energy. “Expanding Ontario’s world-leading SMR program will ensure we have the reliable, affordable and clean electricity we need to power the next major international investment, the new homes we are building and industries as they grow and electrify.”

For the first time since 2005, Ontario’s electricity demand is rising. While the government has implemented its plan to meet rising electricity demand this decade, the experts at Ontario’s Independent Electricity System Operator have recommended the province advance new nuclear generation and pursue life-extension at Pickering NGS to provide reliable, baseload power to meet increasing electricity needs in the 2030s and beyond.

Subject to Ontario Government and Canadian Nuclear Safety Commission (CNSC) regulatory approvals on construction, the additional SMRs could come online between 2034 and 2036. That is the same timeframe that SaskPower is looking at for its first, and possibly second, units.

The initial unit is expected to go online in 2028 following Ontario’s first SMR groundbreaking at Darlington.

The Darlington site, which already hosts four reactors, was originally considered for an expansion of “large nuclear,” which is why OPG was already well on its way for site approvals of additional nuclear power generation. The plan changed to one, singular, SMR. Now that has been updated to four.

The announcement has significant impact on Saskatchewan, and its plans to build four of its own SMRs. The timing would allow Ontario Power Generation to apply learnings from the construction of the first unit to deliver cost savings on subsequent units. This is also the strategy SaskPower is following – allow Ontario to build the first, then learn from that experience.

Building multiple units will also allow common infrastructure such as cooling water intake, transmission connection and control room to be utilized by all four units instead of just one, reducing costs even further, the Ministry said.

“A fleet of SMRs at the Darlington New Nuclear Site is key to meeting growing electricity demands and net zero goals,” said Ken Hartwick, OPG President and CEO. “OPG has proven its large nuclear project expertise through the on-time, on budget Darlington Refurbishment project. By taking a similar approach to building a fleet of SMRs, we will deliver cost and schedule savings, and power 1.2 million homes from this site by the mid-2030s.”

The Darlington SMR project is situated on the traditional and treaty territories of the seven Williams Treaties First Nations and is also located within the traditional territory of the Huron Wendat peoples. OPG is actively engaging and consulting with potentially impacted Indigenous communities, including exploring economic opportunities in the Darlington SMR project such as commercial participation and employment.

The Ministry noted, “Ontario’s robust nuclear supply chain is uniquely positioned to support SMR development and deployment in Ontario, Canada and globally. Building additional SMRs at Darlington would provide more opportunities for Ontario companies and broader economic benefits as suppliers of nuclear equipment, components, and services to make further investments to expand their operation to serve the growing SMR market both domestically and abroad.”

Supporting new SMR development and investing in nuclear power is part of the Ontario government’s larger plan, aligned with a Canadian interprovincial nuclear initiative that brings provinces together, to prepare for electricity demand in the 2030s and 2040s that will build on Ontario’s clean electricity advantage and ensure the province has the power to maintain it’s position as leader in job creation and a magnet for the industries of the future, the Ministry said.

In February, World Nuclear News (WNN) reported that Poland was considering up to 79 small modular reactors of the same design as OPG and SaskPower. And on June 5, it reported, “Canada’s Ontario Power Generation will provide operator services to Poland’s Orlen Synthos Green Energy under a letter of intent signed between the partners, extending their existing cooperation on the deployment of small modular reactors.”

WNN added, “The letter of intent is aimed at concluding future agreements under which OPG and its subsidiaries could provide operator services for SMR reactors to OSGE in connection with the deployment of SMRs in Poland and other European countries. The partnership would include a number of SMR-related activities including: development and deployment; operations and maintenance; operator training; commissioning; and regulatory support.”

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EDF Nuclear Power Price Deal sets a 70 euros/MWh reference price, adds consumer protection if wholesale electricity prices exceed 110 euros/MWh, and outlines taxation mechanisms to shield bills while funding nuclear investment.

Key Points

A government-EDF deal setting 70 euros/MWh with safeguards above 110 euros/MWh to protect consumers.

✅ Reference price fixed at 70 euros/MWh, near EDF costs.

✅ Consumer shield above 110 euros/MWh; up to 90% extra-revenue tax.

✅ Review clauses maintain 70 euros/MWh through market swings.

State-controlled power group EDF and the French government have reached a tentative deal on future nuclear power prices, echoing a new electricity pricing scheme France has floated, a source close to the government said on Monday, ending months of tense negotiations.

The two sides agreed on 70 euros per megawatt hour (MWH) as a reference level for power prices, aligning with EU plans for more fixed-price contracts for consumers, the source said, cautioning that details of the deal are still being finalised.

The negotiations aimed to find a compromise between EDF, which is eager to maximise revenues to fund investments, and the government, keen to keep electricity bills for French households and businesses as low as possible, amid ongoing EU electricity reform debates across the bloc.

EDF declined to comment.

The preliminary deal sets out mechanisms that would protect consumers if power market prices rise above 110 euros/MWH, similar to potential emergency electricity measures being weighed in Europe, the source said, adding that the deal also includes clauses that would provide a price guarantee for EDF.

The 70 euros/MWH agreed reference price level is close to EDF's nuclear production costs, as Europe moves to revamp its electricity market more broadly. The nuclear power produced by the company provides 70% of France's electricity.

The agreement would allow the government to tax EDF's extra revenues at 90% if prices surpass 110 euros/MWH, in order to offset the impact on consumers. It would also enable a review of conditions in case of market fluctuations to safeguard the 70 euro level for EDF, reflecting how rolling back electricity prices is tougher than it appears, the source said.

French wholesale electricity prices are still above 100 euros/MWH, after climbing to 1,200 euros during last year's energy crisis, even as diesel prices have returned to pre-conflict levels.

A final agreement should be officially announced on Tuesday after a meeting between Finance Minister Bruno Le Maire, Energy Transition Minister Agnes Pannier-Runacher and EDF chief Luc Remont.

That meeting will work out the final details on price thresholds and tax rates between the reference level and the upper limit, the source said.

Negotiations between the two sides were so fraught that at one stage they raised questions about the future of EDF chief Luc Remont, who was appointed by President Emmanuel Macron a year ago to turn around EDF.

The group ended 2022 with a 18 billion-euro loss and almost 65 billion euros of net debt, hurt by a record number of reactor outages that coincided with soaring energy prices in the wake of Russia's invasion of Ukraine.

With its output at a 30-year low, EDF was forced to buy electricity on the market to supply customers. The government, meanwhile, imposed a cap on electricity prices, leaving EDF selling power at a discount.

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Power plant staff sequestration isolates essential operators on-site at plants and control centers, safeguarding critical infrastructure and grid reliability during the COVID-19 pandemic under DHS CISA guidance, with social distancing, offset shifts, and stockpiled supplies.

Key Points

A protocol isolating essential grid workers on-site to maintain operations at plants and control centers.

✅ Ensures grid reliability and continuity of critical infrastructure

✅ Implements social distancing, offset shifts, and isolation protocols

✅ Stockpiles food, beds, PPE, and sanitation for essential crews

The U.S. electric industry may ask essential staff to live on site at power plants and control centers to keep operations running if the coronavirus outbreak worsens, after a U.S. grid warning from the overseer, and has been stockpiling beds, blankets, and food for them, according to industry trade groups and electric cooperatives.

The contingency plans, if enacted, would mark an unprecedented step by power providers to keep their highly-skilled workers healthy as both private industry and governments scramble to minimize the impact of the global pandemic that has infected more than 227,000 people worldwide, with some utilities such as BC Hydro at Site C reporting COVID-19 updates as the situation evolves.

“The focus needs to be on things that keep the lights on and the gas flowing,” said Scott Aaronson, vice president of security and preparedness at the Edison Electric Institute (EEI), the nation’s biggest power industry association. He said that some “companies are already either sequestering a healthy group of their essential employees or are considering doing that and are identifying appropriate protocols to do that.”

Maria Korsnick, president of the Nuclear Energy Institute, said that some of the nation’s nearly 60 nuclear power plants are also “considering measures to isolate a core group to run the plant, stockpiling ready-to-eat meals and disposable tableware, laundry supplies and personal care items.”

Neither group identified specific companies, though nuclear worker concerns have been raised in some cases.

Electric power plants, oil and gas infrastructure and nuclear reactors are considered “critical infrastructure” by the federal government, and utilities continue to emphasize safety near downed lines even during emergencies. The U.S. Department of Homeland Security is charged with coordinating plans to keep them operational during an emergency.

A DHS spokesperson said that its Cybersecurity and Infrastructure Security Agency had issued guidance to local governments and businesses on Thursday asking them to implement policies to protect their critical staff from the virus, even as an EPA telework policy emerged during the pandemic.

“When continuous remote work is not possible, businesses should enlist strategies to reduce the likelihood of spreading the disease,” the guidance stated. “This includes, but is not necessarily limited to, separating staff by off-setting shift hours or days and/or social distancing.”

Public health officials have urged the public to practice social distancing as a preventative measure to slow the spread of the virus, and as more people work from home, rising residential electricity use is being observed alongside daily routines. If workers who are deemed essential still leave, go to work and return to their homes, it puts the people they live with at risk of exposure. 

California has imposed a statewide shutdown, asking all citizens who do not work in those critical infrastructure industries not to leave their homes, a shift that may raise household electricity bills for consumers. Similar actions have been put in place in cities across America.

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Bruce Power Capacity Uprate boosts nuclear output through generator stator upgrades, turbine and transformer enhancements, and cooling pump improvements at Bruce A and B, unlocking megawatts and efficiency gains from legacy heavy water design capacity.

Key Points

Upgrades that raise Bruce Power capacity via stator, turbine, transformer, and cooling enhancements.

✅ Generator stator replacement increases electrical conversion efficiency

✅ Turbine and transformer upgrades enable higher MW output

✅ Cooling pump enhancements optimize plant thermal performance

Bruce Power’s Unit 3 nuclear reactor will squeeze out an extra 22 megawatts of electricity, thanks to upgrades during its recent planned outage for refurbishment.

Similar gains are anticipated at its three sister reactors at Bruce A generating station, which presents the opportunity for the biggest efficiency gains and broader economic benefits for Ontario, due to a design difference over Bruce B’s four reactors, Bruce Power spokesman John Peevers said.

Bruce A reactor efficiency gains stem mainly from the fact Bruce A’s non-nuclear side, including turbines and the generator, was sized at 88 per cent of the nuclear capacity, Peevers said, while early Bruce C exploration work advances.

This allowed 12 per cent of the energy, in the form of steam, to be used for heavy water production, which was discontinued at the plant years ago. Heavy water, or deuterium, is used to moderate the reactors.

That design difference left a potential excess capacity that Bruce Power is making use of through various non-nuclear enhancements. But the nuclear operator, which also made major PPE donations during the pandemic, will be looking at enhancements at Bruce B as well, Peevers said.

Bruce Power’s efficiency gain came from “technology advancements,” including a “generator-stator improvement project that was integral to the uprate,” and contributed to an operating record at the site, a Bruce Power news release said July 11.

Peevers said the stationary coils and the associated iron cores inside the generator are referred to as the stator. The stator acts as a conductor for the main generator current, while the turbine provides the mechanical torque on the shaft of the generator.

“Some of the other things we’re working on are transformer replacement and cooling pump enhancements, backed by recent manufacturing contracts, which also help efficiency and contribute to greater megawatt output,” Peevers said.

The added efficiency improvements raised the nuclear operator’s peak generating capacity to 6,430 MW, as projects like Pickering life extensions continue across Ontario.

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