Tighter power plant rules urged after blast

By Associated Press


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A panel studying a deadly power plant explosion wants state regulators to consider stronger licensing and training rules on a common industrial pipe-cleaning practice used nationwide.

If adopted, the regulations would make Connecticut the first state to add extra oversight to the "gas blow" procedure, in which high-pressure natural gas is blown through pipes in some power plants and factories to clear debris.

Five workers were killed instantly and a sixth man died later of injuries from the February 7 blast at the under-construction Kleen Energy Systems plant in Middletown.

The plant exploded when something ignited the 400,000 cubic feet of gas and air that had accumulated in tight quarters during the gas blow procedure. The ignition source is still under investigation.

Retired U.S. District Court Judge Alan Nevas, chairman of the Connecticut panel that issued its recommendations Thursday, said government agency leaders in the group found that permits were in place for all of the regulated procedures at the plant.

But they also discovered that state law doesn't require special training, licensing or oversight for employees performing the gas blow — and their research found no such special regulations in other states, he said.

"This is a process that appears, to me at least, to have fallen between the cracks," Nevas said. "We live in a very highly regulated society, and to find that this was not regulated was surprising."

The law doesn't require companies to notify regulators and nearby residents before performing a gas blow.

It also doesn't address whether materials used have to meet certain standards, whether it should be prohibited during certain weather conditions that could affect how the gas disperses, and whether workers' hours should be limited so they aren't fatigued when they start the procedure.

State reviews of work records from contractors at the Kleen Energy plant found a majority of workers were on the job for more than 40 hours a week, and that some worked as many as 90 hours per week.

Linda Agnew, acting commissioner of the state Department of Labor, said there are no laws limiting work hours at private workplaces. She said their review found minor violations in record-keeping, but nothing suggesting those violations could be blamed for the long work hours or blast.

Gov. M. Jodi Rell created the panel to review the explosion and make recommendations to a second commission, which now receives the report that was just finalized. The second commission will report to Connecticut legislators in time for possible action in the 2011 legislative session, which starts in January.

Kleen Energy's permit for its Middletown plant construction expires November 30 of this year, so no new laws would be in place before it applies for renewal or an extension.

The panel advised the Connecticut Siting Council, which handles those permits, to include its recommendations as mandatory conditions if it renews the Kleen Energy permits.

Middletown detectives and state police are investigating whether any people or businesses should face criminal charges in connection with the explosion and deaths.

Robert Reardon, one of four attorneys representing 10 injured and deceased workers in civil lawsuits, said there is "no question in our minds" that the blast could have been avoided if the general contractor had faced the kind of stricter regulations that the commission advised.

"I think that the commission is on the right track. Unfortunately, sometimes industry has to be regulated by the state and federal government when they fail to regulate themselves properly, and this is one of these instances," Reardon said.

The U.S. Chemical Safety Board, which criticizes gas blows as inherently unsafe, also is investigating and plans to hold a June 28 public hearing in Portland, Conn., about dangers and alternatives to the procedure.

Several other industrial accidents involving natural gas have occurred in recent years, including one that killed four people last year at the ConAgra Foods Inc. plant in Garner, North Carolina, and another in 1999 at a Ford Motor Co. power plant in Dearborn, Michigan, that killed six.

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US looks to decommission Alaskan military reactor

SM-1A Nuclear Plant Decommissioning details the US Army Corps of Engineers' removal of the Fort Greely reactor, Cold War facility dismantling, environmental monitoring, remote-site power history, and timeline to 2026 under a deactivated nuclear program.

 

Key Points

Army Corps plan to dismantle Fort Greely's SM-1A reactor and complete decommissioning of remaining systems by 2026.

✅ Built for remote Arctic radar support during the Cold War

✅ High costs beat diesel; program later deemed impractical

✅ Reactor parts removed; residuals monitored; removal by 2026

 

The US Army Corps of Engineers has begun decommissioning Alaska’s only nuclear power plant, SM-1A, which is located at Fort Greely, even as new US reactors continue to take shape nationwide. The $17m plant closed in 1972 after ten years of sporadic operation. It was out of commission from 1967 to 1969 for extensive repairs. Much of has already been dismantled and sent for disposal, and the rest, which is encased in concrete, is now to be removed.

The plant was built as part of an experimental programme to determine whether nuclear facilities, akin to next-generation nuclear concepts, could be built and operated at remote sites more cheaply than diesel-fuelled plants.

"The main approach was to reduce significant fuel-transportation costs by having a nuclear reactor that could operate for long terms, a concept echoed in the NuScale SMR safety evaluation process, with just one nuclear core," Brian Hearty said. Hearty manages the Army Corps of Engineers’ Deactivated Nuclear Power Plant Program.

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He said the Army built SM-1A in 1962 hoping to provide power reliably at remote Arctic radar sites, where in similarly isolated regions today new US coal plants may still be considered, intended to detect incoming missiles from the Soviet Union at the height of the Cold War. He added that the programme worked but not as well as Pentagon officials had hoped. While SM-1A could be built and operated in a cold and remote location, its upfront costs were much higher than anticipated, and it costs more to maintain than a diesel power plant. Moreover, the programme became irrelevant because of advances in Soviet rocket science and the development of intercontinental ballistic missiles.

Hearty said the reactor was partially dismantled soon after it was shut down. “All of the fuel in the reactor core was removed and shipped back to the Atomic Energy Commission (AEC) for them to either reprocess or dispose of,” he noted. “The highly activated control and absorber rods were also removed and shipped back to the AEC.”

The SM-1A plant produced 1.8MWe and 20MWt, including steam, which was used to heat the post. Because that part of the system was still needed, Army officials removed most of the nuclear-power system and linked the heat and steam components to a diesel-fired boiler. However, several parts of the nuclear system remained, including the reactor pressure vessel and reactor coolant pumps. “Those were either kept in place, or they were cut off and laid down in the tall vapour-containment building there,” Hearty said. “And then they were grouted and concreted in place.” The Corps of Engineers wants to remove all that remains of the plant, but it is as yet unclear whether that will be feasible.

Meanwhile, monitoring for radioactivity around the facility shows that it remains at acceptable levels. “It would be safe to say there’s no threat to human health in the environment,” said Brenda Barber, project manager for the decommissioning. Work is still in its early stages and is due to be completed in 2026 at the earliest. Barber said the Corps awarded the $4.6m contract in December to a Virginia-based firm to develop a long-range plan for the project, similar in scope to large reactor refurbishment efforts elsewhere. Among other things, this will help officials determine how much of the SM-1A will remain after it’s decommissioned. “There will still be buildings there,” she said. “There will still be components of some of the old structure there that may likely remain.”

 

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Company Becomes UK's Second-Largest Electricity Operator

Second-Largest UK Grid Operator advancing electricity networks modernization, smart grid deployment, renewable integration, and resilient distribution, leveraging acquisitions, data analytics, and infrastructure upgrades to boost reliability, efficiency, and service quality across regions and energy sector.

 

Key Points

A growing electricity networks operator advancing smart grids, renewable integration, and reliability.

✅ Expanded via acquisitions and regional growth

✅ Investing in smart grid, data analytics, automation

✅ Enhancing reliability, resilience, renewable integration

 

In a significant shift within the UK’s energy sector, a major company has recently ascended to become the second-largest electricity networks operator in the country. This milestone marks a pivotal moment in the industry, reflecting ongoing changes and competitive dynamics in the energy landscape, such as the shift toward an independent system operator in Great Britain. The company's ascent underscores its growing influence and its role in shaping the future of energy distribution across the UK.

The company, whose identity is a result of strategic acquisitions and operational expansions, now holds a substantial position within the electricity networks sector. This new ranking is the result of a series of investments and strategic moves aimed at strengthening its network capabilities and, amid efforts to fast-track grid connections across the UK, expanding its geographical reach. By achieving this status, the company is set to play a crucial role in managing and maintaining the electricity infrastructure that serves millions of households and businesses across the UK.

The rise to the second-largest position follows a period of significant growth and transformation for the company. Recent acquisitions have enabled it to enhance its network infrastructure, integrate advanced technologies, adopting a more digital grid approach, and improve service delivery. These developments come at a time when the UK is undergoing a significant transition in its energy sector, driven by the need for modernization, sustainability, and resilience in response to evolving energy demands.

One of the key factors contributing to the company's new status is its focus on upgrading and expanding its electricity networks. Investments in modernizing infrastructure, such as the commissioning of a 2GW substation to boost capacity, incorporating smart grid technologies, and enhancing operational efficiencies have been central to its strategy. By leveraging cutting-edge technology and data analytics, the company is able to optimize network performance, reduce outages, and improve overall reliability.

The company’s expansion into new regions has also played a crucial role in its growth. By extending its network coverage, including assets like the London electricity tunnel that enhance supply routes, the company has been able to provide electricity to a larger customer base, increasing its market share and influence in the sector. This expansion not only enhances its position as a major player in the industry but also supports the broader goal of ensuring reliable and efficient electricity distribution across the UK.

The shift to becoming the second-largest operator also reflects broader trends in the UK energy sector. The industry is experiencing a period of consolidation and transformation, driven by regulatory changes, technological advancements, and the push towards decarbonization, with similar momentum seen in British Columbia's clean energy shift that underscores global trends. The company’s ascent is indicative of these broader dynamics, as firms adapt to new challenges and opportunities in a rapidly evolving market.

In addition to operational and strategic advancements, the company’s rise is aligned with the UK’s broader energy goals. The government has set ambitious targets for reducing carbon emissions and increasing the use of renewable energy sources. As a major electricity networks operator, the company is positioned to support these goals by integrating renewable energy into the grid, including projects like the Scotland-to-England subsea link that carry remote generation, enhancing energy efficiency, and contributing to the transition towards a low-carbon energy system.

The company’s new status also brings with it a range of responsibilities and opportunities. As one of the largest operators in the sector, it will have a significant role in shaping the future of electricity distribution in the UK. This includes addressing challenges such as grid reliability, energy security, and the integration of emerging technologies. The company’s ability to manage these responsibilities effectively will be crucial in ensuring that it continues to deliver value to customers and stakeholders.

The transition to becoming the second-largest operator is not without its challenges. The company will need to navigate a complex regulatory environment, manage stakeholder expectations, and address any operational issues that may arise from its expanded network. Additionally, the competitive nature of the energy sector means that the company will need to continuously innovate and adapt to maintain its position and drive further growth.

In summary, the company’s achievement of becoming the second-largest electricity networks operator in the UK represents a significant milestone in the energy sector. Through strategic acquisitions, infrastructure investments, and operational enhancements, the company has strengthened its position and expanded its reach. This development highlights the evolving landscape of the UK energy sector and underscores the importance of modernization and innovation in meeting the country’s energy needs. As the company moves forward, it will play a key role in shaping the future of electricity distribution and supporting the UK’s energy transition goals.

 

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Six key trends that shaped Europe's electricity markets in 2020

European Electricity Market Trends 2020 highlight decarbonisation, rising renewables, EV adoption, shifting energy mix, COVID-19 impacts, fuel switching, hydro, wind and solar growth, gas price dynamics, and wholesale electricity price increases.

 

Key Points

EU power in 2020 saw lower emissions, more renewables, EV growth, demand shifts, and higher wholesale prices.

✅ Power sector CO2 down 14% on higher renewables, lower coal

✅ Renewables 39% vs fossil 36%; hydro, wind, solar expanded

✅ EV share hit 17%; wholesale prices rose with gas, ETS costs

 

According to the Market Observatory for Energy DG Energy report, the COVID-19 pandemic and favorable weather conditions are the two key drivers of the trends experienced within the European electricity market in 2020. However, the two drivers were exceptional or seasonal.

The key trends within Europe’s electricity market include:


1. Decrease in power sector’s carbon emissions

As a result of the increase in renewables generation and decrease in fossil-fueled power generation in 2020, the power sector was able to reduce its carbon footprint by 14% in 2020. The decrease in the sector’s carbon footprint in 2020 is similar to trends witnessed in 2019 when fuel switching was the main factor behind the decarbonisation trend.

However, most of the drivers in 2020 were exceptional or seasonal (the pandemic, warm winter, high
hydro generation). However, the opposite is expected in 2021, with the first months of 2021 having relatively cold weather, lower wind speeds and higher gas prices, with stunted hydro and nuclear output also cited, developments which suggest that the carbon emissions and intensity of the power sector could rise.

The European Union is targeting to completely decarbonise its power sector by 2050 through the introduction of supporting policies such as the EU Emissions Trading Scheme, the Renewable Energy Directive and legislation addressing air pollutant emissions from industrial installations, with expectations that low-emissions sources will cover most demand growth in the coming years.

According to the European Environment Agency, Europe halved its power sector’s carbon emissions in 2019 from 1990 levels.


2. Changes in energy consumption

EU consumption of electricity fell by -4% as majority of industries did not operate at full level during the first half of 2020. Although majority of EU residents stayed at home, meaning an increase in residential energy use, rising demand by households could not reverse falls in other sectors of the economy.

However, as countries renewed COVID-19 restrictions, energy consumption during the 4th quarter was closer to the “normal levels” than in the first three quarters of 2020. 

The increase in energy consumption in the fourth quarter of 2020 was also partly due to colder temperatures compared to 2019 and signs of surging electricity demand in global markets.


3. Increase in demand for EVs

As the electrification of the transport system intensifies, the demand for electric vehicles increased in 2020 with almost half a million new registrations in the fourth quarter of 2020. This was the highest figure on record and translated into an unprecedented 17% market share, more than two times higher than in China and six times higher than in the United States.

However, the European Environment Agency (EEA)argues that the EV registrations were lower in 2020 compared to 2019. EEA states that in 2019, electric car registrations were close to 550 000 units, having reached 300 000 units in 2018.


4. Changes in the region’s energy mix and increase in renewable energy generation

The structure of the region’s energy mix changed in 2020, according to the report.

Owing to favorable weather conditions, hydro energy generation was very high and Europe was able to expand its portfolio of renewable energy generation such that renewables (39%) exceeded the share of fossil fuels (36%) for the first time ever in the EU energy mix.

Rising renewable generation was greatly assisted by 29 GW of wind and solar capacity additions in 2020, which is comparable to 2019 levels. Despite disrupting the supply chains of wind and solar resulting in project delays, the pandemic did not significantly slow down renewables’ expansion.

In fact, coal and lignite energy generation fell by 22% (-87 TWh) and nuclear output dropped by 11% (-79 TWh). On the other hand, gas energy generation was not significantly impacted owing to favorable prices which intensified coal-to-gas and lignite-to-gas switching, even as renewables crowd out gas in parts of the market.


5. Retirement of coal energy generation intensify

 As the outlook for emission-intensive technologies worsens and carbon prices rise, more and more early coal retirements have been announced. Utilities in Europe are expected to continue transitioning from coal energy generation under efforts to meet stringent carbon emissions reduction targets and as they try to prepare themselves for future business models that they anticipate to be entirely low-carbon reliant.

6. Increase in wholesale electricity prices

In recent months, more expensive emission allowances, along with rising gas prices, have driven up wholesale electricity prices on many European markets to levels last seen at the beginning of 2019. The effect was most pronounced in countries that are dependent on coal and lignite. The wholesale electricity prices dynamic is expected to filter through to retail prices.

The rapid sales growth in the EVs sector was accompanied by expanding charging infrastructure. The number of high-power charging points per 100 km of highways rose from 12 to 20 in 2020.

 

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Site C mega dam billions over budget but will go ahead: B.C. premier

Site C Dam Update outlines hydroelectric budget overruns, geotechnical risks, COVID-19 construction delays, BC Hydro timelines, cancellation costs, and First Nations treaty rights concerns affecting renewable energy, ratepayers, and Peace Valley impacts.

 

Key Points

Overview of Site C costs, delays, geotechnical risks, and concerns shaping BC Hydro hydroelectric plans.

✅ Cost to cancel estimated at least $10B

✅ Final budget now about $16B; completion pushed to 2025

✅ COVID-19 and geotechnical risks drove delays and redesigns

 

The cost to cancel a massive B.C. energy development project would be at least $10 billion, provincial officials revealed in an update on the future of Site C.

Thus the project will go ahead, Premier John Horgan and Energy Minister Bruce Ralston announced Friday, but with an increased budget and timeline.

Horgan and Ralston spoke at a news conference in Victoria about the findings of a status report into the hydroelectric dam project in northeastern B.C.

Peter Milburn, former deputy finance minister, finished the report earlier this year, but the findings were not initially made public.

$10B more than initial estimate
On Friday, it was announced that the project's final price tag has once again ballooned by billions of dollars.

Site C was initially estimated to cost $6 billion, and the first approved budget, back in 2014, was $8.775 billion. The budget increased to $10.8 billion in 2018.

But the latest update suggests it will cost about $16 billion in total.

And, in addition to a higher budget, the date of completion has been pushed back to 2025 – a year later than the initial target.

Among the reasons for the revisions, according to the province, is the impact of COVID-19. While officials did not get into details, there have been multiple cases of the disease publicly reported at Site C work camps.

Additionally, fewer workers were permitted on site to allow for physical distancing, and construction was scaled back.

Also cited as a cause for the increased cost were "unforeseeable" geotechnical issues at the site, which required installation of an enhanced drainage system.

Speaking to reporters Friday, the premier deflected blame.

“Managing the contract the BC Liberals signed has been difficult because it transfers the vast majority of the geotechnical risk back to BC Hydro,” said Horgan.

Former Premier Christy Clark vowed to get the project to a point of no return, and in 2017 the NDP decided to continue with the project because of the cost of cancelling it.

The Liberals now say the clean energy project should continue, but deny they shoulder any of the blame.

“Someone has to take ownership – and it's got to be government in power,” said MLA Tom Shypitka, BC Liberal critic for energy. 

There are also several reviews underway, including how to change contractor schedules to reflect delays and potential cost impacts from COVID-19, and how to keep the work environment safe during the pandemic.

A total of 17 recommendations were made in Milburn's report, all of which have been accepted by BC Hydro and the province.

Among these recommendations is a restructured project assurance board with a focus on skill-specific membership and autonomy from BC Hydro.

Cost of cancelling the project
The report looked into whether it would be better to scrap the project altogether, but the cost of cancelling it at this point would be at least $10 billion, Horgan and Ralston said.

That cost does not include replacing lost energy and capacity that Site C's electricity would have provided, according to the province.

A study conducted in 2019 suggested B.C. will need to double its electricity production by 2055, especially as drought conditions are forcing BC Hydro to adapt power generation. 

The NDP government says the cost to ratepayers of cancelling the project would be $216 a year for 10 years. Going forward will still have a cost, but instead, that payment will be split over more than 70 years, the estimated lifetime of Site C, meaning BC Hydro customers will pay about $36 more a year once the site goes live, the NDP says, even as cryptocurrency mining raises questions about electricity use.

“We will not put jobs at risk; we will not shock people's hydro bills,” said Horgan.

"Our government has taken this situation very seriously, and with the advice of independent experts guiding us, I am confident in the path forward for Site C," Ralston said.

"B.C. needs more renewable energy to bridge the electricity gap with Alberta and electrify our economy, transition away from fossil fuels and meet our climate targets."

The minister said the site is currently employing about 4,500 people.

Arguments against Site C
While there are benefits to the project, there has also been vocal opposition.

In a statement released following the announcement that the project would go ahead, the Union of B.C. Indian Chiefs suggested the decision violated the premier's commitment to a UN declaration.

"The Site C dam has never had the free, prior and informed consent of all impacted First Nations, and proceeding with the project is a clear infringement of the treaty rights of the West Moberly First Nation," the UBCIC's secretary treasurer said.

Kukpi7 Judy Wilson said the UN's Committee on the Elimination of Racial Discrimination has called for a suspension of the project until it has the consent of Indigenous peoples.

"B.C. did not even attempt to engage First Nations about the safety risks associated with the stability of the dam in the recent reviews," she said.

"It is unfathomable that such clear human rights violations are somehow OK by this government."

Chief Roland Wilson of the West Moberly First Nation said he was disappointed the province didn’t consult his and other communities prior to making this announcement. In an interview with CTV News, he said he was offered an opportunity to join a call this morning.

“We signed a treaty in 1814,” he said. “Our treaty rights are being trampled on.”

Wilson said his nation has ongoing concerns about safety issues and the plans to flood the Peace Valley. West Moberly is in a bitter court battle with the province.

At the BC Legislature, Green Party Leader Sonia Furstenau slammed the government’s decision.

“It is an astonishingly terrible business case in any circumstances, but considering that we lose the agricultural land, the biodiversity, the traditional treaty lands of Treaty 8, this is particularly catastrophic,” she told reporters.

She went on to accuse the NDP government of keeping bad news from the public. She alleged the NDP knew of serious problems before last fall’s unscheduled election, but chose not to release information.

Prior to the decision former BC Hydro president and a former federal fisheries minister are among those who added their voices to calls to halt work on the dam.

They were among 18 Canadians who wrote an open letter to the province calling for an independent team of experts to explore geotechnical problems at the site.

In the letter, signed in September, the group that also included Grand Chief Stewart Phillip of the UBCIC wrote that going ahead would be a "costly and potentially catastrophic mistake." 

According to Friday's update, independent experts have confirmed the site is safe, though improvements have been recommended to enhance oversight and risk management.

Earlier in the project, a B.C. First Nation claimed it was a $1-billion treaty violation, though an agreement was reached in 2020 after the province promised to improve land management and restore traditional place names in areas of cultural significance.

The Prophet River First Nation will also receive payments while the site is operating, and some Crown land will be transferred to the nation as part of the agreement. 

Additionally, residents of a tiny community not far from the site is suing the province over two slow-moving landslides they claim caused property values to plummet.

Nearly three dozen residents of Old Fort are behind the allegations of negligence and breach of their charter right to security of person. The claim is tied to two landslides, in 2018 and 2020, that the group alleges were caused by ground destabilization from construction related to Site C.

One of the landslides damaged the only road into the community, leaving residents under evacuation for a month.

 

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B.C. Diverting Critical Minerals, Energy from U.S

Canadian Softwood Lumber Tariffs challenge British Columbia's forestry sector, strain U.S.-Canada trade, and risk redirecting critical minerals and energy resources, threatening North American supply chains, manufacturing, and energy security across integrated markets.

 

Key Points

Duties imposed by the U.S. on Canadian lumber, affecting BC forestry, trade flows, and North American energy security.

✅ U.S. duties strain BC forestry and cross-border supply chains

✅ Risks redirecting critical minerals and energy exports

✅ Tariff rollback could bolster North American energy security

 

British Columbia Premier David Eby has raised concerns that U.S. tariffs on Canadian softwood lumber are prompting the province to redirect its critical minerals and energy resources, while B.C. challenges Alberta's electricity export restrictions domestically, away from the United States. In a recent interview, Eby emphasized the broader implications of these tariffs, suggesting they could undermine North American energy security and put electricity exports at risk across the border.

Since 2017, the U.S. Department of Commerce has imposed tariffs on Canadian softwood lumber imports, alleging that Canadian producers benefit from unfair subsidies. These duties have been a persistent source of tension between the two nations, coinciding with Canadian support for energy and mineral tariffs and significantly impacting British Columbia's forestry sector—a cornerstone of the province's economy.

Premier Eby highlighted that the financial strain imposed by these tariffs not only jeopardizes the Canadian forestry industry but also has unintended repercussions for the United States. He pointed out that the economic challenges faced by Canadian producers might lead them to seek alternative markets for their critical minerals and energy resources, as tariff threats boost support for Canadian energy projects domestically, thereby reducing the supply to the U.S. British Columbia is endowed with an abundance of critical minerals essential for various industries, including technology and defense.

The potential redirection of these resources could have significant consequences for American industries that depend on a stable and affordable supply of critical minerals and energy. Eby suggested that the tariffs might incentivize Canadian producers to explore other international markets, even as experts advise against cutting Quebec's energy exports amid the tariff dispute, diminishing the availability of these vital resources to the U.S.

In light of these concerns, Premier Eby has advocated for a reassessment of the tariffs, urging a more cooperative approach between Canada and the United States. He contends that eliminating the tariffs would be mutually beneficial, aligning with views that Biden is better for Canada's energy sector and cross-border collaboration, ensuring a consistent supply of critical resources and fostering economic growth in both countries.

The issue of U.S. tariffs on Canadian softwood lumber remains complex and contentious, with far-reaching implications for trade relations and resource distribution between the two nations. As discussions continue, stakeholders on both sides of the border are closely monitoring the situation, noting that Ford has threatened to cut U.S. electricity exports amid trade tensions, recognizing the importance of collaboration in addressing shared economic and security challenges.

 

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California scorns fossil fuel but can't keep the lights on without it

California fossil fuel grid reliability plan addresses heat wave demand, rolling blackouts, and grid stability by temporarily procuring gas generation while accelerating renewables, storage, and transmission to meet clean energy and carbon-neutral targets by 2045.

 

Key Points

A stop-gap policy to prevent blackouts by buying fossil power while fast-tracking renewables, storage, and grid upgrades.

✅ Temporary procurement of gas to avoid rolling blackouts

✅ Accelerates renewables, storage, transmission permitting

✅ Aims for carbon neutrality by 2045 without new gas plants

 

California wants to quit fossil fuels. Just not yet Faced with a fragile electrical grid and the prospect of summertime blackouts, the state agreed to put aside hundreds of millions of dollars to buy power from fossil fuel plants that are scheduled to shut down as soon as next year.

That has prompted a backlash from environmental groups and lawmakers who say Democratic Gov. Gavin Newsom’s approach could end up extending the life of gas plants that have been on-track to close for more than a decade and could threaten the state’s goal to be carbon neutral by 2045.

“The emphasis that the governor has been making is ‘We’re going to be Climate Leaders; we’re going to do 100 percent clean energy; we’re going to lead the nation and the world,’” said V. John White, executive director of the Sacramento-based Center for Energy Efficiency and Renewable Technologies, a non-profit group of environmental advocates and clean energy companies. “Yet, at least a part of this plan means going the opposite direction.”

That plan was a last-minute addition to the state’s energy budget, which lawmakers in the Democratic-controlled Legislature reluctantly passed. Backers say it’s necessary to avoid the rolling blackouts like the state experienced during a heat wave in 2020. Critics see a muddled strategy on energy, and not what they expected from a nationally ambitious governor who has made climate action a centerpiece of his agenda.

The legislation, which some Democrats labeled as “lousy” and “crappy,” reflects the reality of climate change. Heat waves are already straining power capacity, and the transition to cleaner energy isn’t coming fast enough to meet immediate needs in the nation’s most populous state.

Officials have warned that outages would be possible this summer, as the grid faces heat wave tests again, with as many as 3.75 million California homes losing power in a worst-case scenario of a West-wide heat wave and insufficient electrical supplies, particularly in the evenings.

It’s also an acknowledgment of the political reality that blackout politics are hazardous to elected officials, even in a state dominated by one party.

Newsom emphasized that the money to prop up the power grid, part of a larger $4.3 billion energy spending package, is meant as a stop-gap measure. The bill allows the Department of Water Resources to spend $2.2 billion on “new emergency and temporary generators, new storage systems, clean generation projects, and funding on extension of existing generation operations, if any occur,” the governor said in a statement after signing the bill.

“Action is needed now to maintain reliable energy service as the State accelerates the transition to clean energy,” Newsom said.

Following the signing, the governor called for the state California Air Resources Board to add a set of ambitious goals to its 2022 Scoping Plan, which lays out California’s path for reducing carbon emissions.

Among Newsom’s requested changes is a move away from fossil fuels, asking state agencies to prepare for an energy transition that avoids the need for new natural gas plants.

Alex Stack, a spokesman for the governor, said in a statement that California has been a global leader in reducing pollution and exporting energy policies across Western states, and pointed to Newsom’s recent letter to the Air Resources Board as well as one sent to President Joe Biden outlining how states can work with the federal government to combat climate change.

“California took action to streamline permitting for clean energy projects to accelerate the build out of clean energy that is needed to meet our climate goals and help maintain reliability in the face of extreme heat, wildfires, and drought,” Stack said.

But the prospect of using state money on fossil fuel power, even in the short term, has raised ire among the state’s many environmental advocacy groups, and raised questions about whether California will be able to achieve its goals.

“What is so frustrating about an energy bill like this is that we are at crunch time to meet these goals,” said Mary Creasman, CEO of California Environmental Voters. “And we’re investing a scale of funding into things that exacerbate those goals.”
 
Emmanuelle Chriqui and Mary Creasman speak during the 2021 Environmental Media Association IMPACT Summit at Pendry West Hollywood on September 2, 2021 in West Hollywood, California. | Jesse Grant/Getty Images for Environmental Media Association

With climate change-induced drought and high temperatures continuing to ravage the West, California anticipates the demand on the grid will only continue to grow. Despite more than a decade of bold posturing and efforts to transition to solar, wind and hydropower, the state worries it doesn’t have enough renewable energy sources on hand to keep the power on in an emergency right now, amid a looming shortage that will test reliability.

The specter of power outages poses a hazard to Newsom, and Democrats in general, especially ahead of November. While the governor is widely expected to sail to reelection, rolling blackouts are a serious political liability — in 2003, they were the catalyst for recalling Democratic Gov. Gray Davis. A lack of power isn’t just about people sweating in the dark, said Steven Maviglio, a longtime Democratic consultant who served as communications director for Davis, it can affect businesses, travel and have an outsized impact on the economy.

It behooves any state official to keep the power on, but, unlike Davis, Newsom is under serious pressure to make sure the state also adheres to its climate goals.

“Gavin Newsom’s brand is based on climate change and clean air, so it’s a little more difficult for him to say ‘well that’s not as important as keeping the power on,’” Maviglio said.

The same bill effectively ends local government control over those projects, for the time being. It hopes to speed up the state’s production of renewable energy sources by giving exclusive authority over the siting of those projects to a single state agency for the next seven years.

Environmental advocates say the state is now scrambling to address an issue they’ve long known was coming. In 2010, California officials set a schedule to retire a number of coastal gas plants that rely on what’s known as once-through cooling systems, which are damaging to the environment, especially marine life, even as regulators weigh more power plants to maintain reliability today. Many of those plants have been retired since 2010, but others have received extensions.

The remaining plants have various deadlines for when they must cease operations, with the soonest being the end of 2023.

Also at issue is the embattled Diablo Canyon nuclear power plant, California’s largest electricity source. The Pacific Gas & Electric-owned plant is scheduled to close in 2025, but the strain on the grid has officials considering the possibility of seeking an extension. Newsom said earlier this spring he would be open to extending the life of the plant. Doing so would also require federal approval.

Al Muratsuchi stands and talks into a microphone with a mask on. 
Assemblyman Al Muratsuchi speaks during an Assembly session in Sacramento, Calif., on Jan. 31, 2022. | Rich Pedroncelli/AP Photo

The International Brotherhood of Electrical Workers 1245, a labor union, sees the energy package as a way to preserve Diablo Canyon, and jobs at the plant.

“The value to 1245 PG&E members at Diablo Canyon is clear — funding to keep the plant open,” the union said of the bill.

Assemblymember Al Muratsuchi (D-Los Angeles) criticized the bill as “crappy” when it came to the floor in late June, describing it as “a rushed, unvetted and fossil-fuel-heavy response” to the state’s need to bolster the grid.

“The state has had over 12 years to procure and bring online renewable energy generation to replace these once through cooling gas power plants,” Muratsuchi said. “Yet, the state has reneged on its promise to shut down these plants, not once, but twice already.”

Not all details of the state’s energy budget are final. Lawmakers still have $3.8 billion to allocate when they return on Aug. 1 for the final stretch of the year.

Creasman, at California Environmental Voters, said she wants lawmakers to set specific guidelines for how and where it will spend the $2.2 billion when they return in August to dole out the remaining money in the budget. Newsom and legislators also need to ensure that this is the last time California has to spend money on fossil fuel, she said.

“Californians deserve to see what the plan is to make sure we’re not in this position again of having to choose between making climate impacts worse or keeping our lights on,” Creasman said. “That’s a false choice.”

 

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