DOE calls for bigger nuclear waste dump

UK Coal-Free Grid Streak highlights record hours without coal, as renewable energy, wind and solar boost electricity generation, cutting CO2 emissions, reducing fossil fuel reliance, and accelerating grid decarbonization amid volatile gas markets.

Key Points

It is the UKs longest coal-free power run, driven by renewables, signaling decarbonization and reduced gas reliance.

✅ Record-breaking hours of electricity with zero coal generation

✅ Enabled by wind, solar, and growing offshore wind capacity

✅ Highlights need to cut gas use and expand renewable investment

Today is the fourth the UK has entered with not a watt of electricity generated by coal.

It’s the longest such streak since the 1880s and comes only days after the last modern era coal-free power record of 55 hours was set.

That represents good news for those of us who have children and would rather like there to be a planet for them to live on when we’re gone.

Coal generated power is dirty power, and not just through the carbon that gets pumped into the atmosphere when it burns.

The fact that the UK is increasingly able to call upon cleaner alternatives for its requirements, to the extent that records are being regularly broken and coal's share has fallen to record lows, is a welcome development.

The trouble is one of those alternatives is gas, and while it is better than coal it still throws off CO2, among other pollutants. The UK’s use of it, for electricity generation and most of its heating, comes with the added disadvantage of leaving it in hock to volatile international markets and producers that aren’t always friendly.

It was only last month, with the country in the middle of a cold snap, that the Grid was issuing a deficit warning (its first in eight years).

As I wrote at the time, we need to burn less of the stuff as low-carbon progress stalled in 2019 shows, too.

As such, Greenpeace’s call for more investment in renewable energy technology and generation, including solar, onshore wind and offshore wind, which is making an increasing contribution as wind beat coal in 2016 demonstrated, was well made.

Those who complain about onshore wind farms, particularly when they are built in windy places that are pretty, seem willfully blind to the pollution caused by gas.

The need to be listened to less. So do those, like British Gas owner Centrica, that bellyache about green taxes.

It bears repeating that fossil fuels are subsidised still more. It’s just that the subsidies are typically hidden.

A report issued last year by a coalition of environmental organisations found the UK provided $972m (£695m) of annual financing for fossil fuels on average between 2013 and 2015, compared with $172m for renewable energy.

But while they come up with wildly varying amounts as a result of wildly varying approaches, the OECD, the IMF and the International Energy Agency have all quantified substantial subsidies for fossils fuels. Their annual estimates have ranged from $160bn to $5.3tn (yes you read that rate and the number was the IMF’s) globally.

So by all means celebrate coal free days, and a full week without coal power as milestones. But we need more of them more quickly and we need more renewable energy to pick up the slack. As such, the philosophy and approach of government needs to change.

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Ontario ICI Electricity Pricing Freeze helps Industrial Conservation Initiative (ICI) participants by stabilizing Global Adjustment charges, suspending peak hours curtailment, and reducing COVID-19-related electricity cost volatility to support large employers returning operations to full capacity.

Key Points

A two-year policy stabilizing GA costs and pausing peak-hour cuts to aid industrial and commercial recovery.

✅ GA cost share frozen for two years

✅ No peak-hour curtailment obligations

✅ Supports industrial and commercial restart

The Ontario government is helping large industrial and commercial companies return to full levels of operation without the fear of electricity costs spiking by providing more stable electricity pricing for two years. Effective immediately, companies that participate in the Industrial Conservation Initiative (ICI) will not be required to reduce their electricity usage during peak hours or shift some load to ultra-low overnight pricing where applicable, as their proportion of Global Adjustment (GA) charges for these companies will be frozen.

"Ontario's industrial and commercial electricity consumers continue to experience unprecedented economic challenges during COVID-19, with electricity relief for households and small businesses introduced to help," said Greg Rickford, Minister of Energy, Northern Development and Mines. "Today's announcement will allow large industrial employers to focus on getting their operations up and running and employees back to work, instead of adjusting operations in response to peak electricity demand hours."

Due to COVID-19, electricity consumption in Ontario has been below average as fall in demand as people stayed home across the province, and the province is forecast to have a reliable supply of electricity, supported by the system operator's staffing contingency plans during the pandemic, to accommodate increased usage. Peak hours generally occur during the summer when the weather is hot and electricity demand from cooling systems is high.

"Today's action will reduce the burden of anticipating and responding to peak hours for more than 1,300 ICI participants with 2,000 primarily industrial facilities in Ontario," said Bill Walker, Associate Minister of Energy. "Now these large employers can focus on getting their operations back up and running at full tilt and explore new energy-efficiency programs to manage costs."

The government previously announced it was providing temporary relief for industrial and commercial electricity consumers that do not participate in the Regulated Price Plan (RPP) by deferring a portion of GA charges for April, May and June 2020 and by extending off-peak rates for many customers, as well as a disconnect moratorium extension for residential electricity users.

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Ukraine Electricity Exports resume as the EU grid links stabilize; ENTSO-E caps, megawatt capacity, renewables, and infrastructure repairs enable power flows to Moldova, Poland, Slovakia, and Romania despite ongoing Russian strikes.

Key Points

Resumed cross-border power sales showing grid stability under ENTSO-E limits and surplus generation.

✅ Exports restart to Moldova; Poland, Slovakia, Romania next.

✅ ENTSO-E cap limits to 400 MW; more capacity under negotiation.

✅ Revenues fund grid repairs after Russian strikes.

Ukraine began resuming electricity exports to European countries on Tuesday, its energy minister said, a dramatic turnaround from six months ago when fierce Russian bombardment of power stations plunged much of the country into darkness in a bid to demoralize the population.

The announcement by Energy Minister Herman Halushchenko that Ukraine was not only meeting domestic consumption demands but also ready to restart exports to its neighbors was a clear message that Moscow’s attempt to weaken Ukraine by targeting its infrastructure did not work.

Ukraine’s domestic energy demand is “100%” supplied, he told The Associated Press in an interview, and it has reserves to export due to the “titanic work” of its engineers and international partners.

Russia ramped up infrastructure attacks in September, when waves of missiles and exploding drones destroyed about half of Ukraine's energy system, even as it built lines to reactivate the Zaporizhzhia plant in occupied territory. Power cuts were common across the country as temperatures dropped below freezing and tens of millions struggled to keep warm.

Moscow said the strikes were aimed at weakening Ukraine’s ability to defend itself, and both sides have floated a possible agreement on power plant attacks amid mounting civilian harm, while Western officials said the blackouts that caused civilians to suffer amounted to war crimes. Ukrainians said the timing was designed to destroy their morale as the war marked its first anniversary.

Ukraine had to stop exporting electricity in October to meet domestic needs.

Engineers worked around the clock, often risking their lives to come into work at power plants and keep the electricity flowing. Kyiv’s allies also provided help. In December, U.S. Secretary of State Antony Blinken announced $53 million in bilateral aid to help the country acquire electricity grid equipment, on top of $55 million for energy sector support.

Much more work remains to be done, Halushchenko said. Ukraine needs funding to repair damaged generation and transmission lines, and revenue from electricity exports would be one way to do that.

The first country to receive Ukraine’s energy exports will be Moldova, he said.

Besides the heroic work by engineers and Western aid, warmer temperatures are enabling the resumption of exports by making domestic demand lower, and across Europe initiatives like virtual power plants for homes are helping balance grids. Nationwide consumption was already down at least 30% due to the war, Halushchenko said, with many industries having to operate with less power.

Renewables like solar and wind power also come into play as temperatures rise, taking some pressure off nuclear and coal-fired power plants.

But it’s unclear if Ukraine can keep up exports amid the constant threat of Russian bombardment.

“Unfortunately now a lot of things depend on the war,” Halushchenko said. “I would say we feel quite confident now until the next winter.”

Exports to Poland, Slovakia and Romania are also on schedule to resume, he said.

“Today we are starting with Moldova, and we are talking about Poland, we are talking about Slovakia and Romania,” Halushchenko added, noting that how much will depend on their needs.

“For Poland, we have only one line that allows us to export 200 megawatts, but I think this month we will finish another line which will increase this to an additional 400 MW, so these figures could change,” he said.

Export revenue will depend on fluctuating electricity prices in Europe, where stunted hydro and nuclear output may hobble recovery efforts. In 2022, while Ukraine was still able to export energy, Ukrainian companies averaged 40 million to 70 million euros a month depending on prices, Halushchenko said.

“Even if it’s 20 (million euros) it’s still good money. We need financial resources now to restore generation and transmission lines,” he said.

Ukraine has the ability to export more than the 400 megawatt capacity limit imposed by the European Network of Transmission System Operators for Electricity, or ENTSO-E, and rising EU wind and solar output is reshaping cross-border flows. “We are in negotiations to increase this cap because today we can export even more, we have the necessary reserves in the system,” the minister said.

The current capacity limit is in line with what Ukraine was exporting in September 2022 before Ukraine diverted resources to meet domestic needs amid the Russian onslaught.

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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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Hydro One-Avista Merger outlines a utility acquisition shaped by Washington regulators, Colstrip coal plant depreciation, and plans for renewables, clean energy, and emissions cuts, while Montana reviews implications for jobs, ratepayers, and a 2027 closure.

Key Points

A utility deal setting Colstrip depreciation and renewables, without committing to an early coal plant closure.

✅ Washington sets 2027 depreciation for Colstrip units

✅ Montana reviews jobs, ratepayer impacts, community fund

✅ Avista seeks renewables; no binding shutdown commitment

The Washington power company Hydro One is buying will be ready to close its huge coal-fired generating station ahead of schedule, thanks to conditions put on the corporate merger by state regulators there.

Not that we actually plan to do that, the company is telling other regulators in Montana, where coal unit retirements are under debate, the huge coal-fired generating station in question employs hundreds of people. We’ll be in the coal business for a good long time yet.

Hydro One, in which the Ontario government now owns a big minority stake, is still working on its purchase of Avista, a private power utility based in Spokane. The $6.7-billion deal, which Hydro One announced in July, includes a 15 per cent share in two of the four generating units in a coal plant in Colstrip, Montana, one of the biggest in the western United States. Avista gets most of its electricity from hydro dams and gas but uses the Colstrip plant when demand for power is high and water levels at its dams are low.

#google#

Colstrip’s a town of fewer than 2,500 people whose industries are the power plant and the open-pit mines that feed it about 10 million tonnes of coal a year. Two of Colstrip’s generators, older ones Avista doesn’t have any stake in, are closing in 2022. The other two will be all that keep the town in business.

In Washington, they don’t like the coal plant and its pollution. In Montana, the future of Colstrip is a much bigger concern. The companies have to satisfy regulators in both places that letting Hydro One buy Avista is in the public interest.

Ontario proudly closed the last of our coal plants in 2014 and outlawed new ones as environmental menaces, and Alberta's coal phase-out is now slated to finish by 2023. When Hydro One said it was buying Avista, which makes about $100 million in profit a year, Premier Kathleen Wynne said she hoped Ontario’s “value system” would spread to Avista’s operations.

The settlement is “an important step towards bringing together two historic companies,” Hydro One’s chief executive Mayo Schmidt said in announcing it.

The deal has approval from the Washington Utilities and Transportation Commission staff but is subject to a vote by the group’s three commissioners. It doesn’t commit Avista to closing anything at Colstrip or selling its share. But Avista and Hydro One will budget as if the Colstrip coal burners will close in 2027, instead of running into the 2040s as their owners had once planned, a timeline that echoes debates over the San Juan Generating Station in New Mexico.

In accounting terms, they’ll depreciate the value of their share of the plant to zero over the next nine years, reflecting what they say is the end of the plant’s “useful life.” Another of Colstrip’s owners, Puget Sound Energy, has previously agreed with Washington regulators that it’ll budget for a Colstrip closure in 2027 as well.

Avista and Hydro One will look for sources of 50 megawatts of renewable electricity, including independent power projects where feasible, in the next four years and another 90 megawatts to supplement Avista’s supply once the Colstrip plant eventually closes, they promise in Washington. They’ll put $3 million into a “community transition fund” for Colstrip.

The money will come from the companies’ profits and cash, the agreement says. “Hydro One will not seek cost recovery for such funds from ratepayers in Ontario,” it says specifically.

“Ontario has always been a global leader in the transition away from dirty coal power and towards clean energy,” said Doug Howell, an anti-coal campaigner with the Sierra Club, which is a party to the agreement. “This settlement continues that tradition, paving the way for the closure of the largest single source of climate pollution in the American West by 2027, if not earlier.”

Montanans aren’t as thrilled. That state has its own public services commission, doing its own examination of the corporate merger, which has asked Hydro One and Avista to explain in detail why they want to write off the value of the Colstrip burners early. The City of Colstrip has filed a petition saying it wants in on Montana hearings because “the potential closure of (Avista’s units) would be devastating to our community.”

Don’t get too worked up, an Avista vice-president urged the Montana commission just before Easter.

“Just because an asset is depreciated does not mean that one would otherwise remove that asset from service if the asset is still performing as intended,” Jason Thackston testified in a session that dealt only with what the deal with Washington state would mean to Colstrip. We’re talking strictly about an accounting manoeuvre, not an operational commitment.

Six joint owners will have to agree to close the Colstrip generators and there’s “no other tacit understanding or unstated agreement” to do that, he said.

Besides Washington and Montana, state regulators in Idaho, including those overseeing the Idaho Power settlement process, Alaska and Oregon and multiple federal authorities have to sign off on the deal before it can happen. Hydro One hopes it’ll be done in the second half of this year.

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BC Hydro electricity demand decline reflects COVID-19 impacts across British Columbia, with reduced industrial load, full reservoirs, strategic spilling, and potential rate increases, as hydropower plants adjust operations at Seven Mile, Revelstoke, and Site C.

Key Points

A 10% COVID-19-driven drop in BC power use, prompting reservoir spilling, plant curtailment, and potential rate hikes.

✅ 10% load drop; industrial demand down 7% since mid-March

✅ Reservoirs near capacity; controlled spilling to mitigate risk

✅ Possible rate hikes; Site C construction continues

Elecricity demand is down 10 per cent across British Columbia, an unprecedented decline in commercial electricity consumption sparked by the COVID-19 pandemic, according to a BC Hydro report.

Power demand across hotels, offices, recreational facilities and restaurants have dwindled as British Columbians self isolate, and bill relief for residents and businesses was introduced during this period.

The shortfall means there's a surplus of water in reservoirs across the province.

"This drop in load in addition to the spring snow melt is causing our reservoirs to reach near capacity, which could lead to environmental concerns, as well as public safety risks if we don't address the challenges now," said spokesperson Tanya Fish.

Crews will have to strategically spill reservoirs to keep them from overflowing, a process that can have negative impacts on downstream ecosystems. Excessive spilling can increase fish mortality rates.

Spilling is currently underway at the Seven Mile and Revelstoke reservoirs. In addition, several small plants have been shut down.

Site C and hydro rates
According to the report, titled Demand Dilemma, the decline could continue into April 2021 and drop by another two per cent, even as a regulator report alleged BC Hydro misled oversight bodies.

Major industry — forestry, mining and oil and gas — accounts for about 30 per cent of BC Hydro's overall electricity load. Energy demand from these customers has dropped by seven per cent since mid-March, while in Manitoba a Consumers Coalition has urged rejection of proposed rate increases.

BC Hydro says a prolonged drop in demand could have an impact on future rates, which could potentially go up as the power provider looks to recoup deferred operating costs and financial losses.

In Manitoba, Manitoba Hydro's debt has grown significantly, underscoring the financial risks utilities face during demand shocks.

Fish said the crown corporation still expects there to be increased demand in the long-term. She said construction of the Site C Dam is continuing as planned to support clean-energy generation in the province. There are currently nearly 1,000 workers on-site.

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