Malfunction causes shutdown of nuclear power reactor in South Korea

BPA Privatization would sell the Bonneville Power Administration's transmission lines, raising FERC-regulated grid rates for ratepayers, impacting hydropower and the California-Oregon Intertie under the Trump 2018 budget proposal in the Pacific Northwest region.

Key Points

Selling Bonneville's transmission grid to private owners, raising rates and returns, shifting costs to ratepayers.

✅ Trump 2018 budget targets BPA transmission assets for sale.

✅ Higher capital costs, taxes, and profit would raise transmission rates.

✅ California-Oregon Intertie and hydropower flows face price impacts.

President Trump's 2018 budget proposal is so chock-full of noxious elements — replacing food stamps with "food boxes," drastically cutting Medicaid and Medicare, for a start — that it's unsurprising that one of its most misguided pieces has slipped under the radar.

That's the proposal to privatize the government-owned Bonneville Power Administration, which owns about three-quarters of the high-voltage electric transmission lines in a region that includes California, Washington state and Oregon, serving more than 13.5 million customers. By one authoritative estimate, any such sale would drive up the cost of transmission by 26%-44%.

The $5.2-billon price cited by the Trump administration, moreover, is nearly 20% below the actual value of the Bonneville grid — meaning that a private buyer would pocket an immediate windfall of $1.2 billion, at the expense of federal taxpayers and Bonneville customers.

Trump's plan for Portland, Ore.-based Bonneville is part of a larger proposal to sell off other government-owned electricity bodies, including the Colorado-based Western Area Power Administration and the Oklahoma-based Southwestern Power Administration. But Bonneville is by far the largest of the three, accounting for nearly 90% of the total $5.8 billion the budget anticipates collecting from the sales. The proposal is also part of the administration's

Both plans are said to be politically dead-on-arrival in Washington. But they offer a window into the thinking in the Trump White House.

"The word 'muddle' comes to mind," says Robert McCullough, a respected Portland energy consultant, referring to the justification for the privatization sale included in the Trump budget.

The White House suggests that selling the Bonneville grid would result in lower costs. But that narrative, McCullough wrote in a blistering assessment of the proposal, "displays a severe lack of understanding about the process of setting transmission rates."

McCullough's assessment is an update of a similar analysis he performed when the privatization scheme was first raised by the Trump administration last year. In that analysis issued in June, McCullough said the proposal "raises the question of why these valuable assets would be sold at a discount — and who would get the benefit of the discounted price."

The implications of a sale could be dire for Californians. Bonneville is the majority owner of the California-Oregon Intertie, an electrical transmission system that carries power, including Columbia River-generated hydropower and other clean-energy generation in British Columbia that supports the regional exchange, south to California in the summer and excess California generation to the Pacific Northwest in the winter.

But the idea has drawn fire throughout the region. When it was first broached last year, the Public Power Council, an association of utilities in the Northwest, assailed it as an apparent "transfer of value from the people of the Northwest to the U.S. Treasury," drawing parallels to Manitoba Hydro governance issues elsewhere.

The region's political leaders had especially harsh words for the idea this time around. "Oregonians raised hell last year when Trump tried to raise power bills for Pacific Northwesterners by selling off Bonneville Power, and yet his administration is back at it again," Sen. Ron Wyden (D-Ore.) said after the idea reappeared. "Our investment shouldn't be put up for sale to free up money for runaway military spending or tax cuts for billionaires." Sen. Maria Cantwell (D-Wash.) promised in a statement to work to "stop this bad idea in its tracks."

The notion of privatizing Bonneville predates the Trump administration; it was raised by Bill Clinton and again by George W. Bush, who thought the public would gain if the administration could sell its power at market rates. Both initiatives failed.

The same free-enterprise ideology underlies the Trump proposal. Privatizing the transmission lines "encourages a more efficient allocation of economic resources and mitigates unnecessary risk to taxpayers," the budget asserts. "Ownership of transmission assets is best carried out by the private sector where there are appropriate market and regulatory incentives."

But that's based on a misunderstanding of how transmission rates are set, McCullough says. Transmission is essentially a monopoly enterprise, with rates overseen by the Federal Energy Regulatory Commission based on the grid's costs, and with federal scrutiny of public utilities such as the TVA underscoring that oversight. There's very little in the way of market "incentives" involved in transmission, since no one has come forward to build a competing grid.

Those include the owners' cost of capital — which would be much higher for a private owner than a government agency, McCullough observes, as Hydro One investor uncertainty demonstrates in practice. A private owner, unlike the government-owned Bonneville, also would owe federal income taxes, which would be passed on to consumers.

Then there's the profit motive. Bonneville "currently sells and delivers its power at cost," McCullough wrote last year. "Under a private regime, an investor-owned utility would likely charge a higher rate of return, a pattern seen when UK network profits drew regulatory rebukes."

None of these considerations appears to have been factored into the White House budget proposal. "Either there's an unsophisticated person at the Office of Management and Budget thinking up these numbers himself," McCullough told me, "or there would seem to be ongoing negotiations with an unidentified third party." No such buyer has emerged in the past, however.

What's left is a blind faith in the magic of the market, compounded by ignorance about how the transmission market operates. Put it together, and there's reason to wonder if Trump is even serious about this plan.

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U.S. Power Sector Outlook 2022 previews clean energy targets, grid reliability and resilience upgrades, transmission expansion, renewable integration, EV charging networks, and decarbonization policies shaping utilities, markets, and climate strategies amid extreme weather risks.

Key Points

An outlook on clean energy goals, grid resilience, transmission, and EV infrastructure shaping U.S. decarbonization.

✅ States set 100% clean power targets; equity plans deepen.

✅ Grid reforms, transmission builds, and RTO debates intensify.

✅ EV plants, batteries, and charging corridors accelerate.

As sweeping climate legislation stalled in Congress this year, states and utilities were busy aiming to reshape the future of electricity.

States expanded clean energy goals and developed blueprints on how to reach them. Electric vehicles got a boost from new battery charging and factory plans.

The U.S. power sector also is sorting through billions of dollars of damage that will be paid for by customers over time. States coped with everything from blackouts during a winter storm to heat waves, hurricanes, wildfires and tornadoes. The barrage has added urgency to a push for increased grid reliability and resilience, especially as the power generation mix evolves, EV grid challenges grow as electricity is used to power cars and the climate changes.

“The magnitude of our inability to serve with these sort of discontinuous jumps in heat or cold or threats like wildfires and flooding has made it really clear that we can’t take the grid for granted anymore — and that we need to do something,” said Alison Silverstein, a Texas-based energy consultant.

Many of the announcements in 2021 could see further developments next year as legislatures, utilities and regulators flesh out details on everything from renewable projects to ways to make the grid more resilient.

On the policy front, the patchwork of state renewable energy and carbon reduction goals stands out considering Congress’ failure so far to advance a key piece of President Biden’s agenda — the "Build Back Better Act," which proposed about $550 billion for climate action. Criticism from fellow Democrats has rained on Sen. Joe Manchin (D-W.Va.) since he announced his opposition this month to that legislation (E&E Daily, Dec. 21).

The Biden administration has taken some steps to advance its priorities as it looks to decarbonize the U.S. power sector by 2035. That includes promoting electric vehicles, which are part of a goal to make the United States have net-zero emissions economywide no later than 2050. The administration has called for a national network of 500,000 EV charging stations as the American EV boom raises power-supply questions, and mandated the government begin buying only EVs by 2035.

Still, the fate of federal legislation and spending is uncertain. States and utility plans are considered a critical factor in whether Biden’s targets come to fruition. Silverstein also stressed the importance of regional cooperation as policymakers examine the grid and challenges ahead.

“Our comfort as individuals and as households and as an economy depends on the grid staying up,” Silverstein said, “and that’s no longer a given.”

Here are three areas of the electricity sector that saw changes in 2021, and could see significant developments next year:

1. Clean energy
The list of states with new or revamped clean energy goals expanded again in 2021, with Oregon and Illinois joining the ranks requiring 100 percent zero-carbon electricity in 2040 and 2050, respectively.

Washington state passed a cap-and-trade bill. Massachusetts and Rhode Island adopted 2050 net-zero goals.

North Carolina adopted a law requiring a 70 percent cut in carbon emissions by 2030 from 2005 levels and establishing a midcentury net-zero goal.

Nebraska didn’t adopt a statewide policy, but its three public power districts voted separately to approve clean energy goals, actions that will collectively have the same effect. Even the governor of fossil-fuel-heavy North Dakota, during an oil conference speech, declared a goal of making the state carbon-neutral by the end of the decade.

These and other states join hundreds of local governments, big energy users and utilities, which were also busy establishing and reworking renewable energy and climate goals this year in response to public and investor pressure.

However, many of the details on how states will reach those targets are still to be determined, including factors such as how much natural gas will remain online and how many renewable projects will connect to the grid.

Decisions on clean energy that could be made in 2022 include a key one in Arizona, which has seen support rise and fall over the years for a proposal to lead to 100 percent clean power for regulated electric utilities. The Arizona Corporation Commission could discuss the matter in January, though final approval of the plan is not a sure thing. Eyes also are on California, where a much bigger grid for EVs will be needed, as it ponders a recent proposal on rooftop solar that has supporters of renewables worried about added costs that could hamper the industry.

In the wake of the major energy bill North Carolina passed in 2021, observers are waiting for Duke Energy Corp.’s filing of its carbon-reduction plan with state utility regulators. That plan will help determine the future electricity mix in the state.

Warren Leon, executive director of the Clean Energy States Alliance (CESA), said that without federal action, state goals are “going to be more difficult to achieve.”

State and federal policies are complementary, not substitutes, he said. And Washington can provide a tailwind and help states achieve their goals more quickly and easily.

“Progress is going to be most rapid if both the states and the federal government are moving in the same direction, but either of them operating independently of the others can still make a difference,” he said.

While emissions reductions and renewable energy goals were centerpieces of the state energy and climate policies adopted this year, there were some other common threads that could continue in 2022.

One that’s gone largely unnoticed is that an increasing number of states went beyond just setting targets for clean energy and have developed plans, or road maps, for how to meet their goals, Leon said.

Like the New Year resolutions that millions of Americans are planning — pledges to eat healthier or exercise more — it’s far easier to set ambitious goals than to achieve them.

According to CESA, California, Colorado, Nevada, Maine, Rhode Island, Massachusetts and Washington state all established plans for how to achieve their clean energy goals. Prior to late 2020, only two states — New York and New Jersey — had done so.

Another trend in state energy and climate policies: Equity and energy justice provisions factored heavily in new laws in places such as Maine, Illinois and Oregon.

Equity isn’t a new concern for states, Leon said. But state plans have become more detailed in terms of their response to ways the energy transition may affect vulnerable populations.

“They’re putting much more concrete actions in place,” he said. “And they are really figuring out how they go about electricity system planning to make sure there are new voices at the table, that the processes are different, and there are things that are going to be measured to determine whether they’re actually making progress toward equity.”

2. Grid
Climate change and natural disasters have been a growing worry for grid planners, and 2021 was a year the issue affected many Americans directly.

Texas’ main power grid suffered massive outages during a deadly February winter storm, and it wasn’t far from an uncontrolled blackout that could have required weeks or months of recovery.

Consumers elsewhere in the country watched as millions of Texans lost grid power and heat amid a bitter cold snap. Other parts of the central United States saw more limited power outages in February.

“I think people care about the grid a lot more this year than they did last year,” Silverstein said, adding, “All of a sudden people are realizing that electricity’s not as easy as they’ve assumed it was and … that we need to invest more.”

Many of the challenges are not specific to one state, she added.

“It seems to me that the state regulators need to put a lot — and utilities need to put a lot — more commitment into working together to solve broad regional problems in cooperative regional ways,” Silverstein said.

In 2022, multiple decisions could affect the grid, including state oversight of spending on upgrades and market proposals that could sway the amount of clean energy brought online.

A focal point will be Texas, where state regulators are examining further changes to the Electric Reliability Council of Texas’ market design. That could have major implications for how renewables develop in the state. Leaders in other parts of the country will likely keep tabs on adjustments in Texas as they ponder their own changes.

Texas has already embarked on reforms to help improve the power sector and its coordination with the natural gas system, which is critical to keeping plants running. But its primary power grid, operated by ERCOT, remains largely isolated and hasn’t been able to rule out power shortages this winter if there are extreme conditions (Energywire, Nov. 22).

Transmission also remains a key issue outside of the Lone Star State, both for resilience and to connect new wind and solar farms. In many areas of the country, the job of planning these new regional lines and figuring out how to allocate billions of dollars in costs falls to regional grid operators (Energywire, Dec. 13).

In the central U.S., the issue led to tension between states in the Midwest and the Gulf South (Energywire, Oct. 15).

In the Northeast, a Maine environmental commissioner last month suspended a permit for a major transmission project that could send hydropower to the region from Canada (Greenwire, Nov. 24). The project’s developers are now battling the state in court to force construction of the line — a process that could be resolved in 2022 — after Mainers signaled opposition in a November vote.

Advocates of a regional transmission organization for Western states, meanwhile, hope to keep building momentum even as critics question the cost savings promoted by supporters of organized markets. Among those in existing markets, states such as Louisiana are expected to monitor the costs and benefits of being associated with the Midcontinent Independent System Operator.

In other states, more details are expected to emerge in 2022 about plans announced this year.

In California, where policymakers are also exploring EVs for grid stability alongside wildfire prevention, Pacific Gas & Electric Co. announced a plan over the summer to spend billions of dollars to underground some 10,000 miles of power lines to help prevent wildfires, for example (Greenwire, July 22).

Several Southeastern utilities, including Dominion Energy Inc., Duke Energy, Southern Co. and the Tennessee Valley Authority, won FERC approval to create a new grid plan — the Southeast Energy Exchange Market, or SEEM — that they say will boost renewable energy.

SEEM is an electricity trading platform that will facilitate trading close to the times when the power is used. The new market is slated to include two time zones, which would allow excess renewables such as solar and wind to be funneled to other parts of the country to be used during peak demand times.

SEEM is significant because the Southeast does not have an organized market structure like other parts of the country, although some utilities such as Dominion and Duke do have some operations in the region managed by PJM Interconnection LLC, the largest U.S. regional grid operator.

SEEM is not a regional transmission organization (RTO) or energy imbalance market. Critics argue that because it doesn’t include a traditional independent monitor, SEEM lacks safeguards against actions that could manipulate energy prices.

Others have said the electric companies that formed SEEM did so to stave off pressure to develop an RTO. Some of the regulated electric companies involved in the new market have denied that claim.

3. Electric vehicles
With electric vehicles, the Midwest and Southeast gained momentum in 2021 as hubs for electrifying the transportation sector, as EVs hit an inflection point in mainstream adoption, and the Biden administration simultaneously worked to boost infrastructure to help get more EVs on the road.

From battery makers to EV startups to major auto manufacturers, companies along the entire EV supply chain spectrum moved to or expanded in those two regions, solidifying their footprint in the fast-growing sector.

A wave of industry announcements capped off in December with California-based Rivian Automotive Inc. declaring it would build a $5 billion electric truck, SUV and van factory in Georgia. Toyota Motor Corp. picked North Carolina for its first U.S.-based battery plant. General Motors Co. and a partner plan to build a $2.5 billion battery plant in GM’s home state of Michigan. And Proterra Inc. has unveiled plans to build a new battery factory in South Carolina.

Advocates hope the EV shift by automakers in the Midwest and Southeast will widen the options for customers. Automakers and startups also have been targeting states with zero-emission vehicle targets to launch new and more models because there’s an inherent demand for them.

“The states that have adopted those standards are getting more vehicles,” said Anne Blair, senior EV policy manager for the Electrification Coalition.

EV advocates say they hope those policies could help bring products like Ford’s electrified signature truck line on the road and into rural areas. Ford also is partnering with Korean partner SK Innovation Co. Ltd. to build two massive battery plants in Kentucky.

Regardless of the fanfare about new vehicles, more jobs and must-needed economic growth, barriers to EV adoption remain. Many states have tacked on annual fees, which some elected officials argue are needed to replace revenues secured from a gasoline tax.

Other states do not allow automakers to sell directly to consumers, preventing companies like Lordstown Motors Corp. and Rivian to effectively do business there.

“It’s about consumer choice and consumers having the capacity to buy the vehicles that they want and that are coming out, in new and innovative ways,” Blair told E&E News. Blair said direct sales also will help boost EV sales at traditional dealerships.

In 2022, advocates will be closely watching progress with the National Electric Highway Coalition, amid tensions over charging control among utilities and networks, which was formed by more than 50 U.S. power companies to build a coast-to-coast fast-charging network for EVs along major U.S. travel corridors by the end of 2023 (Energywire, Dec. 7).

A number of states also will be holding legislative sessions, and they could include new efforts to promote EVs — or change benefits that currently go to owners of alternative vehicles.

EV advocates will be pushing for lawmakers to remove barriers that they argue are preventing customers from buying alternative vehicles.

Conversations already have begun in Georgia to let startup EV makers sell their cars and trucks directly to consumers. In Florida, lawmakers will try again to start a framework that will create a network of charging stations as charging networks jostle for position under federal electrification efforts, as well as add annual fees to alternative vehicles to ease concerns over lost gasoline tax revenue.

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Rio Tinto waste heat-to-electricity initiative captures underground mining thermal energy at Resolution Copper, Arizona, converting it to renewable power for cooling systems and microgrids, advancing decarbonization, energy efficiency, and the miner's 2050 carbon-neutral goal.

Key Points

A program converting underground thermal energy into on-site electricity to cut emissions and support mine cooling.

✅ Captures low-grade heat from rock and geothermal water.

✅ Generates electricity for ventilation, refrigeration, microgrids.

✅ Scalable, safe, and grid- or storage-ready for peak demand.

The world’s second-largest miner, Rio Tinto announced that it is accepting proposals for solutions that transform waste heat into electricity for reuse from its underground operations.

In a press release, the company said this initiative is aimed at drastically reducing greenhouse gas emissions, even as energy-intensive projects like bitcoin mining operations expand, so that it can achieve its goal of becoming carbon neutral by 2050.

Initially, the project would be implemented at the Resolution copper mine in Arizona, which Rio owns together with BHP (ASX, LON: BHP). At this site, massive electrically-driven refrigeration and ventilation systems, aligned with broader electrified mining practices, are in charge of cooling the work environment because of the latent heat from the underground rock and groundwater. 

THE INITIATIVE IS AIMED AT REDUCING GREENHOUSE GAS EMISSIONS SO THAT RIO CAN ACHIEVE ITS GOAL OF BECOMING CARBON NEUTRAL BY 2050

“When operating, the Resolution copper mine will be a deep underground block cave mine some 7,000 feet (~2 kilometres) deep, with ambient air temperatures ranging between 168°F to 180°F (76°C to 82°C), conditions that, during heat waves, when bitcoin mining power demand can strain local grids, further heighten cooling needs, and underground water at approximately 194°F (90°C),” the media brief states.

“Rio Tinto is seeking solutions to capture and reuse the heat from underground, contributing towards powering the equipment needed to cool the operations. The solution to capture and convert this thermal energy into electrical energy, such as emerging thin-film thermoelectrics, should be safe, environmentally friendly and cost-effective.”

The miner also said that, besides capturing heat for reuse, the solution should generate electrical energy from low range temperatures below the virgin rock temperature and/or from the high thermal water coming from the underground rock, similar to using transformer waste heat for heating in the power sector. 

At the same time, the solution should be scalable and easily transported through the many miles of underground tunnels that will be built to ventilate, extract and move copper ore to the surface.

Rio requires proposals to offer the possibility of distributing the electrical energy generated back into the electrical grid from the mining operation or stored and used at a later stage when energy is required during peak use periods, especially as jurisdictions aim to use more electricity for heat in colder seasons. 

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Canada Wind Energy Costs are plunging as renewable energy auctions, CfD contracts, and efficient turbines drive prices to 2-4 cents/kWh across Alberta and Saskatchewan, outcompeting grid power via competitive bidding and improved capacity factors.

Key Points

Averaging 2-4 cents/kWh via auctions, CfD support, and bigger turbines, wind is now cost-competitive across Canada.

✅ Alberta CfD bids as low as 3.9 cents/kWh.

✅ Turbine outputs rose from 1 MW to 3.3 MW per tower.

✅ Competitive auctions cut costs ~70% over nine years.

It's taken a decade of technological improvement and a new competitive bidding process for electrical generation contracts, but wind may have finally come into its own as one of the cheapest ways to create power.

Ten years ago, Ontario was developing new wind power projects at a cost of 28 cents per kilowatt hour (kWh), the kind of above-market rate that the U.K., Portugal and other countries were offering to try to kick-start development of renewables. 

Now some wind companies say they've brought generation costs down to between 2 and 4 cents — something that appeals to provinces that are looking to significantly increase their renewable energy deployment plans.

The cost of electricity varies across Canada, by province and time of day, from an average of 6.5 cents per kWh in Quebec to as much as 15 cents in Halifax.

Capital Power, an Edmonton-based company, recently won a contract for the Whitla 298.8-megawatt (MW) wind project near Medicine Hat, Alta., with a bid of 3.9 cents per kWh, at a time when three new solar facilities in Alberta have been contracted at lower cost than natural gas, underscoring the trend. That price covers capital costs, transmission and connection to the grid, as well as the cost of building the project.

Jerry Bellikka, director of government relations, said Capital Power has been building wind projects for a decade, in the U.S., Alberta, B.C. and other provinces. In that time the price of wind generation equipment has been declining continually, while the efficiency of wind turbines increases.

Increased efficiency

"It used to be one tower was 1 MW; now each turbine generates 3.3 MW. There's more electricity generated per tower than several years ago," he said.

One wild card for Whitla may be steel prices — because of the U.S. and Canada slapping tariffs on one other's steel and aluminum products. Whitla's towers are set to come from Colorado, and many of the smaller components from China.

Canada introduces new surtaxes to curb flood of steel imports

"We haven't yet taken delivery of the steel. It remains to be seen if we are affected by the tariffs." Belikka said.

Another company had owned the site and had several years of meteorological data, including wind speeds at various heights on the site, which is in a part of southern Alberta known for its strong winds.

But the choice of site was also dependent on the municipality, with rural Forty Mile County eager for the development, Belikka said.

Alberta aims for 30% electricity from wind by 2030

Alberta wants 30 per cent of its electricity to come from renewable sources by 2030 and, as an energy powerhouse, is encouraging that with a guaranteed pricing mechanism in what is otherwise a market-bidding process.

While the cost of generating energy for the Alberta Electric System Operator (AESO) fluctuates hourly and can be a lot higher when there is high demand, the winners of the renewable energy contracts are guaranteed their fixed-bid price.

The average pool price of electricity last year in Alberta was 5 cents per kWh; in boom times it rose to closer to 8 cents. But if the price rises that high after the wind farm is operating, the renewable generator won't get it, instead rebating anything over 3.9 cents back to the government.

On the other hand, if the average or pool price is a low 2 cents kWh, the province will top up their return to 3.9 cents.

This contract-for-differences (CfD) payment mechanism has been tested in renewable contracts in the U.K. and other jurisdictions, including some U.S. states, according to AESO.

Competitive bidding in Saskatchewan

In Saskatchewan, the plan is to double its capacity of renewable electricity, to 50 per cent of generation capacity, by 2030, and it uses an open bidding system between the private sector generator and publicly owned SaskPower.

In bidding last year on a renewable contract, 15 renewable power developers submitted bids, with an average price of 4.2 cents per kWh.

One low bidder was Potentia with a proposal for a 200 MW project, which should provide electricity for 90,000 homes in the province, at less than 3 cents kWh, according to Robert Hornung of the Canadian Wind Energy Association.

"The cost of wind energy has fallen 70 per cent in the last nine years," he says. "In the last decade, more wind energy has been built than any other form of electricity."

Ontario remains the leading user of wind with 4,902 MW of wind generation as of December 2017, most of that capacity built under a system that offered an above-market price for renewable power, put in place by the previous Liberal government.

In June of last year, the new Conservative government of Doug Ford halted more than 700 renewable-energy projects, one of them a wind farm that is sitting half-built, even as plans to reintroduce renewable projects continue to advance.

The feed-in tariff system that offered a higher rate to early builders of renewable generation ended in 2016, but early contracts with guaranteed prices could last up to 20 years.

Hornung says Ontario now has an excess of generating capacity, as it went on building when the 2008-9 bust cut market consumption dramatically.

But he insists wind can compete in the open market, offering low prices for generation when Ontario needs new  capacity.

"I expect there will be competitive processes put in place. I'm quite confident wind projects will continue to go ahead. We're well positioned to do that."

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Texas wholesale electricity price spike disrupts ERCOT markets as Griddy and other retail energy providers face surge pricing; customers confront spot market exposure, fixed-rate plan switching, demand response appeals, and deep-freeze grid constraints across Texas.

Key Points

An extreme ERCOT market surge sending real-time rates to caps, exposing Griddy users and driving provider-switch pleas.

✅ Wholesale index plans pass through $9,000/MWh scarcity pricing.

✅ Retailers urge switching; some halt enrollments amid volatility.

✅ Demand response incentives and conservation pleas reduce load.

Some retail power companies in Texas are making an unusual plea to their customers amid a winter storm that has sent electricity prices skyrocketing: Please, leave us.

Power supplier, Griddy, told all 29,000 of its customers that they should switch to another provider as spot electricity prices soared to as high as $9,000 a megawatt-hour. Griddy’s customers are fully exposed to the real-time swings in wholesale power markets, so those who don’t leave soon will face extraordinarily high electricity bills.

“We made the unprecedented decision to tell our customers — whom we worked really hard to get — that they are better off in the near term with another provider,” said Michael Fallquist, chief executive officer of Griddy. “We want what’s right by our consumers, so we are encouraging them to leave. We believe that transparency and that honesty will bring them back” once prices return to normal.

Texas is home to the most competitive electricity market in America. Homeowners and businesses shopping for electricity churn power providers there like credit cards. In the face of such cutthroat competition, retail power providers in the region have grown accustomed to offering new customers incredibly low rates, incentives and, at least in Griddy’s case, unusual plans that allow customers to pay wholesale power prices as opposed to fixed ones.

The ruthless nature of the business has power traders speculating over which firms might have been caught short this week in the most dramatic run-up in spot power prices they’ve ever seen, and even talk of a market bailout has surfaced.

Not all companies are asking customers to leave. Others are just pleading for them to cut back to reduce blackout risks during extreme weather.

Pulse Power, based in The Woodlands, Texas, is offering customers a chance to win a Tesla Model 3, or free electricity for up to a year if they reduce their power usage by 10% in the coming days. Austin-based Bulb is offering $2 per kilowatts-hour, up to $200, for any energy customers save.

Griddy, however, is in a different position. Its service is simple — and controversial. Members pay a $9.99 monthly fee and then pay the cost of spot power traded on Texas’s power grid based on the time of day they use it. Earlier this month, that meant customers were saving money — and at times even getting paid — to use electricity at night. But in recent days, the cost of their power has soared from about 5 to 6 cents a kilowatt-hour to $1 or more. That’s when Fallquist knew it was time to urge his customers to leave.

“I can tell you it was probably one of the hardest decisions we’ve ever made,” he said. “Nobody ever wants to see customers go.”

Griddy isn’t the only one out there actively encouraging its customers to leave. People were posting similar pleas on Twitter over the holiday weekend from other Texas utilities and retail power providers offering everything from $100 rebates to waived cancellation fees as incentives to switch.

Customers may not even be able to switch. Rizwan Nabi, president of energy consultancy Riz Energy in Houston, said several power providers in Texas have told him they aren’t accepting new customers due to this week’s volatile prices, while grid improvements are debated statewide.

Hector Torres, an energy trader in Texas, who is a Griddy customer himself, said he tried to switch services over the long weekend but couldn’t find a company willing to take him until Wednesday, when the weather is forecast to turn warmer.

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Europe's Nuclear Energy Policy shapes responses to the energy crisis, soaring gas prices, EU taxonomy rules, net-zero goals, renewables integration, baseload security, SMRs, and Russia-Ukraine geopolitics, exposing cultural, financial, and environmental divides.

Key Points

A policy guiding nuclear exits or expansion to balance energy security, net-zero goals, costs, and EU taxonomy.

✅ Divergent national stances: phase-outs vs. new builds

✅ Costs, delays, and waste challenge large reactors

✅ SMRs, renewables, and gas shape net-zero pathways

As the Fukushima disaster unfolded in Japan in 2011, then-German Chancellor Angela Merkel made a dramatic decision that delighted her country’s anti-nuclear movement: all reactors would be ditched.

What couldn’t have been predicted was that Europe would find itself mired in one of the worst energy crises in its history. A decade later, the continent’s biggest economy has shut down almost all its capacity already. The rest will be switched off at the end of 2022 — at the worst possible time.

Wholesale power prices are more than four times what they were at the start of the coronavirus pandemic. Governments are having to take emergency action to support domestic and industrial consumers faced with crippling bills, which could rise higher if the tension over Ukraine escalates. The crunch has not only exposed Europe’s supply vulnerabilities, but also the entrenched cultural and political divisions over the nuclear industry and a failure to forge a collective vision. 

Other regions meanwhile are cracking on, challenging the idea that nuclear power is in decline worldwide. China is moving fast on nuclear to try to clean up its air quality. Its suite of reactors is on track to surpass that of the U.S., the world’s largest, by as soon as the middle of this decade. Russia is moving forward with new stations at home and has more than 20 reactors confirmed or planned for export construction, according to the World Nuclear Association.

“I don’t think we’re ever going to see consensus across Europe with regards to the continued running of existing assets, let alone the construction of new ones,” said Peter Osbaldstone, research director for power and renewables at Wood Mackenzie Group Ltd. in the U.K. “It’s such a massive polarizer of opinions that national energy policy is required in strength over a sustained period to support new nuclear investment.” 

France, Europe’s most prolific nuclear energy producer, is promising an atomic renaissance as its output becomes less reliable. Britain plans to replace aging plants in the quest for cleaner, more reliable energy sources. The Netherlands wants to add more capacity, Poland also is seeking to join the nuclear club, and Finland is starting to produce electricity later this month from its first new plant in four decades. 

Belgium and Spain, meanwhile, are following Germany’s lead in abandoning nuclear, albeit on different timeframes. Austria rejected it in a referendum in 1978.

Nuclear power is seen by its proponents as vital to reaching net-zero targets worldwide. Once built, reactors supply low-carbon electricity all the time, unlike intermittent wind or solar.

Plants, though, take a decade or more to construct at best and the risk is high of running over time and over budget. Finland’s new Olkiluoto-3 unit is coming on line after a 12-year delay and billions of euros in financial overruns. 

Then there’s the waste, which stays hazardous for 100,000 years. For those reasons European Union members are still quarreling over whether nuclear even counts as sustainable.

Electorates are also split. Polling by YouGov Plc published in December found that Danes, Germans and Italians were far more nuclear-skeptic than the French, British or Spanish. 

“It comes down to politics,” said Vince Zabielski, partner at New York-based law firm Pillsbury Winthrop Shaw Pittman LLP, who was a nuclear engineer for 15 years. “Everything political ebbs and flows, but when the lights start going off people have a completely different perspective.”

What’s Behind Europe’s Skyrocketing Energy Prices

Indeed, there’s a risk of rolling blackouts this winter. Supply concerns plaguing Europe have sent gas and electricity prices to record levels and inflation has ballooned. There’s also mounting tension with Russia over a possible invasion of Ukraine, which could lead to disrupted supplies of gas. All this is strengthening the argument that Europe needs to reduce its dependence on international sources of gas.

Europe will need to invest 500 billion euros ($568 billion) in nuclear over the next 30 years to meet growing demand for electricity and achieve its carbon reduction targets, according to Thierry Breton, the EU’s internal market commissioner. His comments come after the bloc unveiled plans last month to allow certain natural gas and nuclear energy projects to be classified as sustainable investments. 

“Nuclear power is a very long-term investment and investors need some kind of guarantee that it will generate a payoff,” said Elina Brutschin at the International Institute for Applied Systems Analysis. In order to survive in liberalized economies like the EU, the technology needs policy support to help protect investors, she said.

That already looks like a tall order. The European Commission has been told by a key expert group that the labeling risks raising greenhouse gas emissions and undermining the bloc’s reputation as a bastion for environmentally friendly finance.

Austria has threatened to sue the European Commission over attempts to label atomic energy as green. The nation previously attempted a legal challenge, when the U.K. was still an EU member, to stop the construction of Electricite de France SA’s Hinkley Point C plant, in the west of England. It has also commenced litigation against new Russia-backed projects in neighboring Hungary.

Germany, which has missed its carbon emissions targets for the past two years, has been criticized by some environmentalists and climate scientists for shutting down a supply of clean power at the worst time, despite arguments for a nuclear option for climate policy. Its final three reactors will be halted this year. Yet that was never going to be reversed with the Greens part of the new coalition government. 

The contribution of renewables in Germany has almost tripled since the year before Fukushima, and was 42% of supply last year. That’s a drop from 46% from the year before and means the country’s new government will have to install some 3 gigawatts of renewables — equivalent to the generating capacity of three nuclear reactors — every year this decade to hit the country's 80% goal.

“Other countries don’t have this strong political background that goes back to three decades of anti-nuclear protests,” said Manuel Koehler, managing director of Aurora Energy Research Ltd., a company analyzing power markets and founded by Oxford University academics. 

At the heart of the issue is that countries with a history of nuclear weapons will be more likely to use the fuel for power generation. They will also have built an industry and jobs in civil engineering around that.

Germany’s Greens grew out of anti-nuclear protest movements against the stationing of U.S. nuclear missiles in West Germany. The 1986 Chernobyl meltdown, which sent plumes of radioactive fallout wafting over parts of western Europe, helped galvanize the broader population. Nuclear phase-out plans were originally laid out in 2002, but were put on hold by the country's conservative governments. The 2011 Fukushima meltdowns reinvigorated public debate, ultimately prompting Merkel to implement them.

It’s not easy to undo that commitment, said Mark Hibbs, a Bonn, Germany-based nuclear analyst at Carnegie Endowment for International Peace, or to envision any resurgence of nuclear in Germany soon: “These are strategic decisions, that have been taken long in advance.”

In France, President Emmanuel Macron is about to embark on a renewed embrace of nuclear power, even as a Franco-German nuclear dispute complicates the debate. The nation produces about two-thirds of its power from reactors and is the biggest exporter of electricity in Europe. Notably, that includes anti-nuclear Germany and Austria.

EDF, the world’s biggest nuclear plant operator, is urging the French government to support construction of six new large-scale reactors at an estimated cost of about 50 billion euros. The first of them would start generating in 2035.

But even France has faced setbacks. Development of new projects has been put on hold after years of technical issues at the Flamanville-3 project in Normandy. The plant is now scheduled to be completed next year. 

In the U.K., Business Secretary Kwasi Kwarteng said that the global gas price crisis underscores the need for more home-generated clean power. By 2024, five of Britain’s eight plants will be shuttered because they are too old. Hinkley Point C is due to be finished in 2026 and the government will make a final decision on another station before an election due in 2024. 

One solution is to build small modular reactors, or SMRs, which are quicker to construct and cheaper. The U.S. is at the forefront of efforts to design smaller nuclear systems with plans also underway in the U.K. and France. Yet they too have faced delays. SMR designs have existed for decades though face the same challenging economic metrics and safety and security regulations of big plants.

The trouble, as ever, is time. “Any investment decisions you make now aren’t going to come to fruition until the 2030s,” said Osbaldstone, the research director at Wood Mackenzie. “Nuclear isn’t an answer to the current energy crisis.”

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