British carbon tax leads to 93% drop in coal-fired electricity

European Energy Crisis shocks markets as Russia slashes gas via Nord Stream, spiking prices and triggering rationing, LNG imports, storage shortfalls, and emergency measures to secure energy security before a harsh winter.

Key Points

Europe-wide gas shock from reduced Russian flows drives price spikes, rationing risk, LNG reliance, and emergency action.

✅ Nord Stream cuts deepen supply insecurity and storage gaps

✅ LNG imports rise but terminal capacity and shipping are tight

✅ Policy tools: rationing, subsidies, demand response, coal restarts

As Russian gas cutoffs upend European energy security, the continent is struggling to cope with what experts say is one of its worst-ever energy crises—and it could still get much worse. 

For months, European leaders have been haunted by the prospect of losing Russia’s natural gas supply, which accounts for some 40 percent of European imports and has been a crucial energy lifeline for the continent. That nightmare is now becoming a painful reality as Moscow slashes its flows in retaliation for Europe’s support for Ukraine, dramatically increasing energy prices and forcing many countries to resort to emergency plans, including emergency measures to limit electricity prices in some cases, and as backup energy suppliers such as Norway and North Africa are failing to step up.

“This is the most extreme energy crisis that has ever occurred in Europe,” said Alex Munton, an expert on global gas markets at Rapidan Energy Group, a consultancy. “Europe [is] looking at the very real prospect of not having sufficient gas when it’s most needed, which is during the coldest part of the year.”

“Prices have shot through the roof,” added Munton, who noted that European natural gas prices—nearly $50 per MMBTu—have eclipsed U.S. price rises by nearly tenfold, and that rolling back electricity prices is tougher than it appears in the current market. “That is an extraordinarily high price to be paying for natural gas, and really there is no immediate way out from here.” 

Many officials and energy experts worry that the crisis will only deepen after Nord Stream 1, the largest gas pipeline from Russia to Europe, is taken down for scheduled maintenance this week. Although the pipeline is supposed to be under repair for only 10 days, the Kremlin’s history of energy blackmail and weaponization has stoked fears that Moscow won’t turn it back on—leaving heavily reliant European countries in the lurch. (Russia’s second pipeline to Germany, Nord Stream 2, was killed in February as Russian President Vladimir Putin prepared to invade Ukraine, leaving Nord Stream 1 as the biggest direct gas link between Russia and Europe’s biggest economy.)

“Everything is possible. Everything can happen,” German economy minister Robert Habeck told Deutschlandfunk on Saturday. “It could be that the gas flows again, maybe more than before. It can also be the case that nothing comes.”

That would spell trouble for the upcoming winter, when demand for energy surges and having sufficient natural gas is necessary for heating. European countries typically rely on the summer months to refill their gas storage facilities. And at a time of war, when the continent’s future gas supply is uncertain, having that energy cushion is especially crucial.

If Russia’s prolonged disruptions continue, experts warn of a difficult winter: one of potential rationing, industrial shutdowns, and even massive economic dislocation. British officials, who just a few months ago warned of soaring power bills for consumers, are now warning of even worse, despite a brief fall to pre-Ukraine war levels in gas prices earlier in the year.

Europe could face a “winter of discontent,” said Helima Croft, a managing director at RBC Capital Markets. “Rationing, industrial shut-ins—all of that is looming.”

Unrest has already been brewing, with strikes erupting across the continent as households struggle under the pressures of spiraling costs of living and inflationary pressures. Some of this discontent has also had knock-on effects in the energy market. In Norway, the European Union’s biggest supplier of natural gas after Russia, mass strikes in the oil and gas industries last week forced companies to shutter production, sending further shockwaves throughout Europe.

European countries are at risk of descending into “very, very strong conflict and strife because there is no energy,” Frans Timmermans, the vice president of the European Commission, told the Guardian. “Putin is using all the means he has to create strife in our societies, so we have to brace ourselves for a very difficult period.”

The pain of the crisis, however, is perhaps being felt most clearly in Germany, which has been forced to turn to a number of energy-saving measures, including rationing heated water and closing swimming pools. To cope with the crunch, Berlin has already entered the second phase of its three-stage emergency gas plan; last week, it also moved to bail out its energy giants amid German utility troubles that have been financially slammed by Russian cutoffs. 

But it’s not just Germany. “This is happening all across Europe,” said Olga Khakova, an expert on European energy security at the Atlantic Council, who noted that France has also announced plans to nationalize the EDF power company as it buckles under mounting economic losses, and the EU outlines gas price cap strategies to temper volatility. “The challenging part is how much can these governments provide in support to their energy consumers, to these companies? And what is that breaking point?”

The situation has also complicated many countries’ climate goals, even as some call it a wake-up call to ditch fossil fuels for Europe. In late June, Germany, Italy, Austria, and the Netherlands announced they would restart old coal power plants as they grapple with shrinking supplies. 

The potential outcomes that European nations are grappling with reveal how this crisis is occurring on a scale that has only been seen in times of war, Munton said. In the worst-case scenario, “we’re talking about rationing gas supplies, and this is not something that Europe has had to contend with in any other time than the wartime,” he said. “That’s essentially where things have got to now. This is an energy war.”

They also underscore the long and painful battle that Europe will continue to face in weaning itself off Russian gas. Despite the continent’s eagerness to leave Moscow’s supply behind, experts say Europe will likely remain trapped in this spiraling crisis until it can develop the infrastructure for greater energy independence—and that could take years. U.S. gas, shipped by tanker, is one option, but that requires new terminals to receive the gas and U.S. energy impacts remain a factor for policymakers. New pipelines take even longer to build—and there isn’t a surfeit of eligible suppliers.

Until then, European leaders will continue to scramble to secure enough supplies—and can only hope for mild weather. The “worst-case scenario is people having to choose between eating and heating come winter,” Croft said. 

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OPG Pickering Nuclear Refurbishment extends four CANDU reactors to bolster Ontario clean energy, grid reliability, and decarbonization goals, leveraging Darlington lessons, mature supply chains, and AtkinsRealis OEM expertise for cost effective life extension.

Key Points

Modernizing four Pickering CANDU units to extend life, add clean power, and enhance Ontario grid reliability.

✅ Extends four 515 MW CANDU reactors by 30 years

✅ Supports clean, reliable baseload and decarbonization

✅ Leverages Darlington playbook and AtkinsRealis OEM supply chain

In a pivotal shift last month, Ontario Power Generation (OPG) revised its strategy for the Pickering Nuclear Power Station, scrapping plans to decommission its six remaining reactors. Instead, OPG has opted to modernize four reactors (Pickering B Units 5-8) starting in 2027, while Units 1 and 4 are slated for closure by the end of the current year.

This revision ensures the continued operation of the four 515 MW Canada Deuterium Uranium (CANDU) reactors—originally constructed in the 1970s and 1980s—extending their service life by at least 30 more years amid an extension request deadline for Pickering.

Todd Smith, Ontario's Energy Minister, underscored the significance of nuclear power in maintaining Ontario's status as a region with one of the cleanest and most reliable electricity grids globally. He emphasized the integral role of nuclear facilities, particularly the Pickering station, in the provincial energy strategy during the announcement supporting continued operations, which was made in the presence of union workers at the plant.

The Pickering station has demonstrated remarkable efficiency and reliability, notably achieving its second-highest output in 2023 and setting a record in 2022 for continuous operation. Extending the lifespan of nuclear plants like Pickering is deemed the most cost-effective method for sustaining low-carbon electricity, according to research conducted by the International Energy Agency (IEA) and the OECD Nuclear Energy Agency (NEA) across 243 plants in 24 countries.

The refurbishment project is poised to significantly boost Ontario's economy, projected to add CAN$19.4 billion to the GDP over 11 years and generate approximately 11,000 jobs annually. The Independent Electricity System Operator (IESO) has indicated that to meet the province's future electrification and decarbonization goals, as it faces a growing electricity supply gap, Ontario will need to double its nuclear capacity by 2050, requiring an addition of 17.8 GW of nuclear power.

Subo Sinnathamby, OPG's Senior Vice President of Nuclear Refurbishment, emphasized the necessity of nuclear energy in reducing reliance on natural gas. Sinnathamby, who is leading the refurbishment efforts at OPG's Darlington nuclear power station, where SMR plans are also underway, highlighted the positive impact of the Darlington and Bruce Power projects on the nuclear power supply chain and workforce.

The procurement strategy employed for Darlington, which involved placing orders early to ensure readiness among suppliers, is set to be replicated for the Pickering refurbishment. This approach aims to facilitate a seamless transition of skilled workers and resources from Darlington to Pickering refurbishment, leveraging a matured supply chain and experienced vendors.

AtkinsRealis, the original equipment manufacturer (OEM) for CANDU reactors, has a track record of successfully refurbishing CANDU plants worldwide. The CANDU reactor design, known for its refurbishment capabilities, allows for individual replacement of pressure tubes and access to fuel channels without decommissioning the reactor. Gary Rose, Executive Vice-President of Nuclear at AtkinsRealis, highlighted the economic benefits and environmental benefits of refurbishing reactors, stating it as a viable and swift solution to maximize fossil-free energy.

Looking forward, AtkinsRealis is exploring the potential for multiple refurbishments of CANDU reactors, which could extend their operational life beyond 100 years, addressing local energy needs and economic factors in the decision-making process. This innovative approach underscores the role of nuclear refurbishment in meeting global energy demands sustainably and economically.

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FERC Grid Resiliency Pricing Opposition underscores industry groups, RTOs, and ISOs rejecting DOE's NOPR, warning against out-of-market subsidies for coal and nuclear, favoring competitive markets, reliability, and true grid resilience.

Key Points

Coalition urging FERC to reject DOE's NOPR subsidies, protecting reliability and competitive power markets.

✅ Industry groups, RTOs, ISOs oppose DOE NOPR

✅ PJM reports sufficient reliability and resilience

✅ Reject out-of-market aid to coal, nuclear

A diverse group of a dozen energy industry associations representing oil, natural gas, wind, solar, efficiency, and other energy technologies today submitted reply comments to the Federal Energy Regulatory Commission (FERC) continuing their opposition to the Department of Energy's (DOE) proposed rulemaking on grid resiliency pricing and electricity pricing changes within competitive markets, in the next step in this FERC proceeding.

Action by FERC, as lawmakers urge movement on aggregated DERs to modernize markets, is expected by December 11.

In these comments, this broad group of energy industry associations notes that most of the comments submitted initially by an unprecedented volume of filers, including grid operators whose markets would be impacted by the proposed rule, urged FERC not to adopt DOE'sproposed rule to provide out-of-market financial support to uneconomic coal and nuclear power plants in the wholesale electricity markets overseen by FERC.

Just a small set of interests - those that would benefit financially from discriminatory pricing that favors coal and nuclear plants - argued in favor of the rule put forward by DOE in its Notice of Proposed Rulemaking, or NOPR, as did coal and business interests in related regulatory debates. But even those interests - termed 'NOPR Beneficiaries' by the energy associations - failed to provide adequate justification for FERC to approve the rule, and their specific alternative proposals for implementing the bailout of these plants were just as flawed as the DOE plan, according to the energy industry associations.

'The joint comments filed today with partners across the energy spectrum reflect the overwhelming majority view that this proposed rulemaking by FERC is unprecedented and unwarranted, said Todd Foley, Senior Vice President, Policy & Government Affairs, American Council on Renewable Energy.

We're hopeful that FERC will rule against an anti-competitive distortion of the electricity marketplace and avoid new unnecessary initiatives that increase power prices for American consumers and businesses.'

In the new reply comments submitted in response to the initial comments filed by hundreds of stakeholders on or before October 23 - the energy industry associations made the following points: Despite hundreds of comments filed, no new information was brought forth to validate the assertion - by DOE or the NOPR Beneficiaries - that an emergency exists that requires accelerated action to prop up certain power plants that are failing in competitive electricity markets: 'The record in this proceeding, including the initial comments, does not support the discriminatory payments proposed' by DOE, state the industry groups.

Nearly all of the initial comments filed in the matter take issue with the DOE NOPR and its claim of imminent threats to the reliability and resilience of the electric power system, despite reports of coal and nuclear disruptions cited by some advocates: 'Of the hundreds of comments filed in response to the DOE NOPR, only a handful purported to provide substantive evidence in support of the proposal. In contrast, an overwhelming majority of initial comments agree that the DOE NOPR fails to substantiate its assertions of an immediate reliability or resiliency need related to the retirement of merchant coal-fired and nuclear generation.'

Grid operators filed comments refuting claims that the potential retirement of coal and nuclear plants which could not compete for economically present immediate or near-term challenges to grid management, even as a coal CEO criticism targeted federal decisions: 'Even the RTOs and ISOs themselves filed comments opposing the DOE NOPR, noting that the proposed cost-of-service payments to preferred generation would disrupt the competitive markets and are neither warranted nor justified.... Most notably, this includes PJM Interconnection, ... the RTO in which most of the units potentially eligible for payments under the DOE NOPR are located. PJM states that its region 'unquestionably is reliable, and its competitive markets have for years secured commitments from capacity resources that well exceed the target reserve margin established to meet [North American Electric Reliability Corp.] requirements.' And PJM analysis has confirmed that the region's generation portfolio is not only reliable, but also resilient.'

The need for NOPR Beneficiaries to offer alternative proposals reflects the weakness of DOE'srule as drafted, but their options for propping up uneconomic power plants are no better, practically or legally: 'Plans put forward by supporters of the power plant bailout 'acknowledge, at least implicitly, that the preferential payment structure proposed in the DOE NOPR is unclear, unworkable, or both. However, the alternatives offered by the NOPR Beneficiaries, are equally flawed both substantively and procedurally, extending well beyond the scope of the DOE NOPR.'

Citing one example, the energy groups note that the detailed plan put forward by utility FirstEnergy Service Co. would provide preferential payments far more costly than those now provided to individual power plants needed for immediate reasons (and given a 'reliability must run' contract, or RMR): 'Compensation provided under [FirstEnergy's proposal] would be significantly expanded beyond RMR precedent, going so far as to include bailing [a qualifying] unit out of debt based on an unsupported assertion that revenues are needed to ensure long-term operation.'

Calling the action FERC would be required to take in adopting the DOE proposal 'unprecedented,' the energy industry associations reiterate their opposition: 'While the undersigned support the goals of a reliable and resilient grid, adoption of ill-considered discriminatory payments contemplated in the DOE NOPR is not supportable - or even appropriate - from a legal or policy perspective.

About ACORE

The American Council on Renewable Energy (ACORE) is a national non-profit organization leading the transition to a renewable energy economy. With hundreds of member companies from across the spectrum of renewable energy technologies, consumers and investors, ACORE is uniquely positioned to promote the policies and financial structures essential to growth in the renewable energy sector. Our annual forums in Washington, D.C., New York and San Franciscoset the industry standard in providing important venues for key leaders to meet, discuss recent developments, and hear the latest from senior government officials and seasoned experts.

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Hydro One Q2 Earnings show lower net income and EPS as mild weather curbed electricity demand; revenue missed Refinitiv estimates, while tree-trimming costs rose and the dividend remained unchanged for Ontario's grid operator.

Key Points

Hydro One Q2 earnings fell to $155M, EPS $0.26, revenue $1.41B; costs rose, demand eased, dividend held at $0.2415.

✅ Net income $155M; EPS $0.26 vs $0.34 prior year

✅ Revenue $1.41B; missed $1.44B estimate

✅ Dividend steady at $0.2415 per share

Hydro One Ltd.'s (H.TO 0.25%) second-quarter profit fell by nearly 23 per cent from last year to $155 million as the electricity utility reported spending more on tree-trimming work due to milder temperatures that also saw customers using less power, notwithstanding other periods where a one-time court ruling gain shaped quarterly results.

The Toronto-based company - which operates most of Ontario's power grid - and whose regulated rates are subject to an OEB decision, says its net earnings attributable to shareholders dropped to 26 cents per share from 34 cents per share when Hydro One had $200 million in net income.

Adjusted net income was also 26 cents per share, down from 33 cents per diluted share in the second quarter of 2018, while executive pay, including the CEO salary, drew public scrutiny during the period.

Revenue was $1.41 billion, down from $1.48 billion, while revenue net of purchased power was $760 million, down from $803 million, and across the sector, Manitoba Hydro's debt has surged as well.

Separately, Ontario introduced a subsidized hydro plan and tax breaks to support economic recovery from COVID-19, which could influence consumption patterns.

Analysts had estimated $1.44 billion of revenue and 27 cents per share of adjusted income, and some investors cite too many unknowns in evaluating the stock, according to financial markets data firm Refinitiv.

The publicly traded company, which saw a share-price drop after leadership changes and of which the Ontario government is the largest shareholder, says its quarterly dividend will remain at 24.15 cents per share for its next payment to shareholders in September.

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Uranium Critical Mineral Reclassification signals a US executive order directing USGS to restore critical status, boosting nuclear energy, domestic uranium mining, streamlined permitting, federal support, and energy security amid import reliance and supply chain risks.

Key Points

A policy relisting uranium as a critical mineral to unlock funding, speed permits, and strengthen U.S. nuclear security.

✅ Directs Interior to have USGS reconsider uranium classification

✅ Speeds permits for domestic uranium mining projects

✅ Targets import dependence and strengthens energy security

In a strategic move to bolster the United States' nuclear energy sector, former President Donald Trump issued an executive order on January 20, 2025, directing the Secretary of the Interior to instruct the U.S. Geological Survey (USGS) to reconsider classifying uranium as a critical mineral. This directive aims to enhance federal support and streamline permitting processes for domestic uranium projects, thereby strengthening U.S. energy security objectives.

Reclassification of Uranium as a Critical Mineral

The USGS had previously removed uranium from its critical minerals list in 2022, categorizing it as a "fuel mineral" that did not qualify for such designation. The recent executive order seeks to reverse this decision, recognizing uranium's strategic importance in the context of the nation's energy infrastructure and geopolitical considerations.

Implications for Domestic Uranium Production

Reclassifying uranium as a critical mineral is expected to unlock federal funding and expedite the permitting process for uranium mining projects within the United States. This initiative is particularly pertinent given the significant decline in domestic uranium production over the past two decades. According to the U.S. Energy Information Administration, domestic production has decreased by 96%, from 4.8 million pounds in 2014 to approximately 121,296 pounds in the third quarter of 2024.

Current Uranium Supply Dynamics

Despite the push for increased domestic production, the U.S. remains heavily reliant on uranium imports. In 2022, 27% of U.S. uranium purchases were sourced from Canada, with an additional 57% imported from countries including Kazakhstan, Uzbekistan, Australia, and Russia; a recent ban on Russian uranium could further disrupt these supply patterns and heighten risks. This reliance on foreign sources has raised concerns about energy security, especially in light of recent geopolitical tensions.

Challenges and Considerations

While the executive order represents a significant step toward revitalizing the U.S. nuclear energy sector, several challenges persist, and energy dominance faces constraints that will shape implementation:

• Regulatory Hurdles: Accelerating the permitting process for uranium mining projects involves navigating complex environmental and regulatory frameworks, though recent permitting reforms for geothermal hint at potential pathways, which can be time-consuming and contentious.

• Market Dynamics: The uranium market is subject to global supply and demand fluctuations, and domestic producers may face competition from established international suppliers.

• Infrastructure Development: Expanding domestic uranium production necessitates substantial investment in mining infrastructure and workforce development, areas that have been underfunded in recent years.

Broader Implications for Nuclear Energy Policy

The executive order aligns with a broader strategy to revitalize the U.S. nuclear energy industry, where ongoing nuclear innovation is critical to delivering stable, low-emission power. The increasing demand for nuclear energy is driven by the global push for zero-emissions energy sources and the need to support power-intensive technologies, such as artificial intelligence servers.

Former President Trump's executive order to reclassify uranium as a critical mineral, aligning with his broader energy agenda and a prior pledge to end the 'war on coal', signifies a pivotal moment for the U.S. nuclear energy sector. By potentially unlocking federal support, including programs advanced by the Nuclear Innovation Act, and streamlining permitting processes, this initiative aims to reduce dependence on foreign uranium sources and enhance national energy security. However, realizing these objectives will require addressing regulatory challenges, market dynamics, and infrastructure needs to ensure the successful revitalization of the domestic uranium industry.

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High Lonesome Wind Farm powers Texas with 500 MW of renewable energy, backed by a 12-year PPA with Danone North America and a Proxy Revenue Swap, cutting CO2 emissions as Enel's largest project to date.

Key Points

A 500 MW Enel wind project in Texas, supplying renewable power via PPAs and hedged by a Proxy Revenue Swap.

✅ 450 MW online; expanding to 500 MW in early 2020

✅ 12-year PPA with Danone North America for 20.6 MW

✅ PRS hedge with Allianz and Nephila stabilizes revenues

Enel, through its US renewable subsidiary Enel Green Power North America, Inc. (“EGPNA”), has started operations of its 450 MW High Lonesome wind farm in Upton and Crockett Counties, in Texas, the largest operational wind project in the Group’s global renewable portfolio, alongside a recent 90 MW Spanish wind build in its European pipeline. Enel also signed a 12-year, renewable energy power purchase agreement (PPA) with food and beverage company Danone North America, a Public Benefit Corporation, for physical delivery of the renewable electricity associated with 20.6 MW, leading to an additional 50 MW expansion of High Lonesome that will increase the plant’s total capacity to 500 MW. The construction of the 50 MW expansion is currently underway and operations are due to start in the first quarter of 2020.

“The start of operations of Enel’s largest wind farm in the world marks a significant achievement for our company and reinforces our global commitment to accelerated renewable energy growth,” said Antonio Cammisecra, CEO of Enel Green Power, referencing the largest wind project constructed in North America as evidence of market momentum. “This milestone is matched with a new partnership with Danone North America to support their renewable goals, a reinforcement of our continued commitment to provide customers with tailored solutions to meet their sustainability goals.”

The agreement between Enel and Danone North America will provide enough electricity to produce the equivalent of almost 800 million cups of yogurt1 and over 80 million gallons2 of milk each year and support the food and beverage company’s commitment to securing 100% of its purchased electricity from renewable sources by 2030, in a market where North Carolina’s first wind farm is now fully operational and expanding access to clean power.

Mariano Lozano, president and CEO of Danone North America, added:“This is an exciting and significant step as we continue to advance our 2030 renewable electricity goals. As a public benefit corporation committed to balancing the needs of our business with those of society and the planet, we truly believe that this agreement makes sense from both a business and sustainability point of view. We’re delighted to be working with Enel Green Power to expand their High Lonesome wind farm and grow the renewable electricity infrastructure, such as New York’s biggest offshore wind projects, here in the US.”

In addition, as more US wind projects come online, such as TransAlta’s 119 MW project, the energy produced by a 295 MW portion of the project will be hedged under a Proxy Revenue Swap (PRS) with insurer Allianz Global Corporate & Specialty, Inc.'s Alternative Risk Transfer unit (Allianz), and Nephila Climate, a provider of weather and climate risk management products. The PRS is a financial derivative agreement designed to produce stable revenues for the project regardless of power price fluctuations and weather-driven intermittency, hedging the project from this kind of risk in addition to that associated with price and volume.

Under the PRS agreement, and as other projects begin operations, like Building Energy’s latest plant, High Lonesome will receive fixed payments based on the expected value of future energy production, with adjustments paid depending on how the realized proxy revenue of the project differs from the fixed payment. The PRS for High Lonesome, which is the largest by capacity for a single plant globally and the first agreement of its kind for Enel, was executed in collaboration with REsurety, Inc.

The investment in the construction of the 500 MW plant amounts to around 720 million US dollars. The wind farm is due to generate around 1.9 TWh annually, comparable to a 280 MW Alberta wind farm’s output, while avoiding the emission of more than 1.2 million tons of CO2 per year.

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