UN watchdog urges Spanish action on nuclear waste

Electric Buses reduce urban emissions and noise, but require charging infrastructure, grid upgrades, and depot redesigns; they offer lower operating costs and simpler maintenance, with range limits influencing routes, schedules, and on-route fast charging.

Key Points

Battery-electric buses cut emissions and noise while lowering operating and maintenance costs for transit agencies.

✅ Lower emissions, noise; improved rider experience

✅ Requires charging, grid upgrades, depot redesigns

✅ Range limits affect routes; on-route fast charging helps

In lots of ways, the electric bus feels like a technology whose time has come. Transportation is responsible for about a quarter of global emissions, and those emissions are growing faster than in any other sector. While buses are just a small slice of the worldwide vehicle fleet, they have an outsize effect on the environment. That’s partly because they’re so dirty—one Bogotá bus fleet made up just 5 percent of the city’s total vehicles, but a quarter of its CO2, 40 percent of nitrogen oxide, and more than half of all its particulate matter vehicle emissions. And because buses operate exactly where the people are concentrated, we feel the effects that much more acutely.

Enter the electric bus. Depending on the “cleanliness” of the electric grid into which they’re plugged, e-buses are much better for the environment. They’re also just straight up nicer to be around: less vibration, less noise, zero exhaust. Plus, in the long term, e-buses have lower operating costs, and related efforts like US school bus electrification are gathering pace too.

So it makes sense that global e-bus sales increased by 32 percent last year, according to a report from Bloomberg New Energy Finance, as the age of electric cars accelerates across markets worldwide. “You look across the electrification of cars, trucks—it’s buses that are leading this revolution,” says David Warren, the director of sustainable transportation at bus manufacturer New Flyer.

Today, about 17 percent of the world’s buses are electric—425,000 in total. But 99 percent of them are in China, where a national mandate promotes all sorts of electric vehicles. In North America, a few cities have bought a few electric buses, or at least run limited pilots, to test the concept out, and early deployments like Edmonton's first e-bus offer useful lessons as systems ramp up. California has even mandated that by 2029 all buses purchased by its mass transit agencies be zero-emission.

But given all the benefits of e-buses, why aren’t there more? And why aren’t they everywhere?

“We want to be responsive, we want to be innovative, we want to pilot new technologies and we’re committed to doing so as an agency,” says Becky Collins, the manager of corporate initiative at the Southeastern Pennsylvania Transportation Authority, which is currently on its second e-bus pilot program. “But if the diesel bus was a first-generation car phone, we’re verging on smartphone territory right now. It’s not as simple as just flipping a switch.”

One reason is trepidation about the actual electric vehicle. Some of the major bus manufacturers are still getting over their skis, production-wise. During early tests in places like Belo Horizonte, Brazil, e-buses had trouble getting over steep hills with full passenger loads. Albuquerque, New Mexico, canceled a 15-bus deal with the Chinese manufacturer BYD after finding equipment problems during testing. (The city also sued). Today’s buses get around 225 miles per charge, depending on topography and weather conditions, which means they have to re-up about once a day on a shorter route in a dense city. That’s an issue in a lot of places.

If you want to buy an electric bus, you need to buy into an entire electric bus system. The vehicle is just the start.

The number one thing people seem to forget about electric buses is that they need to get charged, and emerging projects such as a bus depot charging hub illustrate how infrastructure can scale. “We talk to many different organizations that get so fixated on the vehicles,” says Camron Gorguinpour, the global senior manager for the electric vehicles at the World Resources Institute, a research organization, which last month released twin reports on electric bus adoption. “The actual charging stations get lost in the mix.”

But charging stations are expensive—about $50,000 for your standard depot-based one. On-route charging stations, an appealing option for longer bus routes, can be two or three times that. And that’s not even counting construction costs. Or the cost of new land: In densely packed urban centers, movements inside bus depots can be tightly orchestrated to accommodate parking and fueling. New electric bus infrastructure means rethinking limited space, and operators can look to Toronto's TTC e-bus fleet for practical lessons on depot design. And it’s a particular pain when agencies are transitioning between diesel and electric buses. “The big issue is just maintaining two sets of fueling infrastructure,” says Hanjiro Ambrose, a doctoral student at UC Davis who studies transportation technology and policy.

“We talk to many different organizations that get so fixated on the vehicles. The actual charging stations get lost in the mix as the American EV boom gathers pace across sectors.”

Then agencies also have to get the actual electricity to their charging stations. This involves lengthy conversations with utilities about grid upgrades, rethinking how systems are wired, occasionally building new substations, and, sometimes, cutting deals on electric output, since electric truck fleets will also strain power systems in parallel. Because an entirely electrified bus fleet? It’s a lot to charge. Warren, the New Flyer executive, estimates it could take 150 megawatt-hours of electricity to keep a 300-bus depot charged up throughout the day. Your typical American household, by contrast, consumes 7 percent of that—per year. “That’s a lot of work by the utility company,” says Warren.

For cities outside of China—many of them still testing out electric buses and figuring out how they fit into their larger fleets—learning about what it takes to run one is part of the process. This, of course, takes money. It also takes time. Optimists say e-buses are more of a question of when than if. Bloomberg New Energy Finance projects that just under 60 percent of all fleet buses will be electric by 2040, compared to under 40 percent of commercial vans and 30 percent of passenger vehicles.

Which means, of course, that the work has just started. “With new technology, it always feels great when it shows up,” says Ambrose. “You really hope that first mile is beautiful, because the shine will come off. That’s always true.”

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ESCC COVID-19 Resource Guide outlines control center continuity, sequestration, social distancing, remote operations, testing priorities, mutual assistance, supply chain risk, and PPE protocols to sustain grid reliability and plant operations during the COVID-19 pandemic.

Key Points

An industry guide to COVID-19 mitigation for the power sector covering control centers, testing, PPE, and mutual aid.

✅ Control center continuity: segregation, remote ops, reserve shifts

✅ Sequestration triggers, testing priorities, and PPE protocols

✅ Mutual assistance, supply chain risk, and workforce planning

The latest version of the Electricity Subsector Coordinating Council’s (ESCC’s) resource guide to assess and mitigate COVID-19 suggests the U.S. power sector continues to grapple with key concerns involving control center continuity, power plant continuity, access to restricted and quarantined areas, mutual assistance, and supply chain challenges, alongside urban demand shifts seen in Ottawa’s electricity demand during closures.

In its fifth and sixth versions of the “ESCC Resource Guide—Assessing and Mitigating the Novel Coronavirus (COVID-19),” released on April 16 and April 20, respectively, the ESCC expanded its guidance as it relates to social distancing and sequestration within tight power sector environments like control centers, crucial mitigation strategies that are designed to avoid attrition of essential workers.

The CEO-led power sector group that serves as a liaison with the federal government during emergencies introduced the guide on March 23, and it provides periodic updates  sourced from “tiger teams,” which are made up of representatives from investor-owned electric companies, public power utilities, electric cooperatives, independent power producers (IPPs), and other stakeholders. Collating regulatory updates and emerging resources, it serves as a general shareable blueprint for generators,  transmission and distribution (T&D) facilities, reliability coordinators, and balancing authorities across the nation on issues the sector is facing as the COVID-19 pandemic endures.

Controlling Spread at Control Centers
While control centers are typically well-isolated, physically secure, and may be conducive to on-site sequestration, the guide is emphatic that staff at these facilities are typically limited and they need long lead times to be trained to properly use the information technology (IT) and operational technology (OT) tools to keep control centers functioning and maintain grid visibility. Control room operators generally include: reliability engineers, dispatchers, area controllers, and their shift supervisors. Staff that directly support these function, also considered critical, consist of employees who maintain and secure the functionality of the IT and OT tools used by the control room operators.

In its latest update, the ESCC notes that many entities took “proactive steps to isolate their control center facilities from external visitors and non-essential employees early in the pandemic, leveraging the presence of back-up control centers, self-quarantining of employees, and multiple shifts to maximize social distancing.” To ensure all levels of logistical and operational challenges posed by the pandemic are addressed, it envisions several scenarios ranging from mild contagion—where a single operator is affected at one of two control center sites to the compromise of both sites.

Previous versions of the guide have set out universal mitigation strategies—such as clear symptom reporting, cleaning, and travel guidance. To ensure continuity even in the most dire of circumstances, for example, it recommends segregating shifts, and even sequestering a “complete healthy shift” as a “reserve” for times when minimum staffing levels cannot be met. It also encourages companies to develop a backup staff of retirees, supervisors, managers, and engineers that could backfill staffing needs.

Meanwhile, though social distancing has always been a universal mitigation strategy, the ESCC last week detailed what social distancing at a control room could look like. It says, for example, that entities should consider if personnel can do their jobs in spaces adjacent to the existing control room; moving workstations to allow at least six feet of space between employees; or designating workstations for individual operators. The guide also suggests remote operations outside of a single control room as an option, and some markets are exploring virtual power plant models in the UK to support flexibility, though it underscores that not all control center operations can be performed remotely, and remote operations increase the potential for security vulnerabilities. “The NERC [North American Electric Reliability Corp.] Reliability Standards address requirements for BES [bulk electric system] control centers and security controls for remote access of systems, applications, or data,” the resource guide notes.

Sequestration—Highly Effective but Difficult
Significantly, the new update also clarifies circumstances that could “trigger” sequestration—or keeping mission-essential workers at facilities. Sequestration, it notes, “is likely to be the most effective means of reducing risk to critical control center employees during a pandemic, but it is also the most resource- and cost-intensive option to implement.”

It is unclear exactly how many power sector workers are currently being sequestered at facilities. According to the  American Public Power Association (APPA), as of last week, the New York Power Authority was sequestering 82 power plant control room and transmission control operator, amid New York City’s shifting electric rhythms during COVID-19; the Sacramento Municipal Utility District (SMUD) in California had begun sequestering critical employees; and the Electric & Gas Utility at the City of Tallahassee had 44 workers being rotated in and out of sequestration. Another 37 workers from the New York ISO were already being sequestered or housed onsite as of April 9. PJM began sequestering a team of operators on April 11, and National Grid was sequestering 200 employees as of April 12. 

Decisions to trigger sequestration at T&D and other grid monitoring facilities are typically driven by entities’ risk assessment, ESCC noted. Considerations may involve: 

The number of people showing symptoms or testing positive as a percentage of the population in a county or municipality where the control center is sited. One organization, for example, is considering a lower threshold of 10% community infection as a trigger of “officer-level decision” to determine whether to sequester. A higher threshold of 20% “mandates a move to sequestration,” ESCC said.
The number of essential workers showing symptoms or having tested positive. “Acceptable risk should be based on the minimum staffing requirements of the control center and should include the availability of a reserve shift for critical position backfills. For example, shift supervisors are commonly certified in all positions in the control center, and the unavailability of more than one-third of a single organization’s shift supervisors could compromise operations,” it said.
The rate of infection spread across a geographic region. In the April 20 version, the guide removes specific mention that cases are doubling “every 3–5 days or more frequently in some areas.” It now says:  “Considering the rapid spread of COVID-19, special care should be taken to identify the point at which control center personnel are more likely than not to come into contact with an infected individual during their off-shift hours.”
Generator Sequestration Measures Vary
Generators, meanwhile, have taken different approaches to sequester generation operators. Some have reacted to statewide outbreaks, others to low reserves, and others still, as with one IPP, to control exposure to smaller staffs, which cannot afford attrition. The IPP, for example, decided sequestration was necessary because it “did not want to wait for confirmed cases in the workforce.” That company sequestered all its control room operators, outside operators, and instrumentation and control technicians.

The ESCC resource guide says workers are being sequestered in several ways. On-site, these could range from housing workers in two separate areas, for example, or in trailers brought in. Off-site, workers may be housed in hotel rooms, which the guide notes, “are plentiful.”

Location makes a difference, it said: “Onsite requires more logistical co-ordination for accommodations, food, room sanitization, linens, and entertainment.”  To accommodate sequestered workers, generators have to consider off-site food and laundry services (left at gates for pick-up)—and even extending Wi-Fi for personal use. Generators are learning from each other about all aspects of sequestration—including how to pay sequestered workers. It suggests sequestered workers should receive pay for all hours inside the plant, including straight time for regularly scheduled hours and time-and-a-half for all other hours. To maintain non-sequestered employees, who are following stay-at-home protocols, pay should remain regularly scheduled, it says.

Testing Remains a Formidable Hurdle
Though decisions to sequester differ among different power entities, they appear commonly complicated by one prominent issue: a dearth of testing.

At the center of a scuffle between the federal and state governments of late, the number of tests has not kept pace with the severity of the pandemic, and while President Trump has for some weeks claimed that “Testing is a local thing,” state officials, business leaders—including from the power sector—and public health experts say that it is far short of the several hundred thousands or perhaps even millions of daily tests it might take to safely restart the economy, even as calls to keep electricity options open grow among policymakers, a three-phase approach for which the Trump administration rolled out this week. While the White House said the approach is “based on the advice of public health experts, the suggestions do not indicate a specific timeframe. Some hard-hit states have committed to keeping current restrictions in place. New York on April 16 said it would maintain a shutdown order through May 15, while California published its own guidelines and states in the Northeast, Midwest, and West Coast entered regional pacts that may involve interstate coordination on COVID-19–related policy going forward.

On Sunday, responding to a call by governors across the political spectrum that insisted the federal government should step up efforts to help states obtain vital supplies for tests, Trump said the federal government will be “using” and “preparing to use” the Defense Production Act to increase swab production.

For the power entities that are part of the ESCC, widespread testing underlies many mitigation strategies. The group’s generation owners and operating companies, which include members from the full power spectrum, have said testing is central to “successful mitigation of risk to control center continuity.”

In the updated guide, the entities recommend requesting that governmental authorities—it is unclear whether the focus should be on the federal or state governments—“direct medical facilities to prioritize testing for asymptomatic generation control room operators, operator technicians, instrument and control technicians, and the operations supervisor (treat comparable to first responders) in advance of sequestered, extended-duration shifts; and obtain state regulatory approval for corporate health services organizations to administer testing for coronavirus to essential employees, if applicable.”

The second priority, as crucial, involves asking the government to direct medical facilities to prioritize testing for control room operators before they are sequestered or go into extended-duration shifts.

Generators also want local, regional, state, and federal governments to ensure operators of generating facilities are allowed to move freely if “populace-wide quarantine/curfew or other travel restrictions” are enacted. Meanwhile,  they have also asked federal agencies and state permitting agencies to allow for non-compliance operations of generating facilities in case enough workers are not available.

Lower on its list, but still “medium priority,” is that the government should obtain authority for priority supply of sanitizing supplies and personal protective equipment (PPE) for generating facilities. They are also asking states to allow power plant employees (as opposed to crucially redirected medical personnel) to administer health questionnaires and temperature checks without Americans with Disabilities Act or other legal constraints. Newly highlighted in the update, meanwhile, is an emphasis on enough fire retardant (FR) vests and hoods and PPE, including masks and face coverings, so technicians don’t have to share them.

The worst-case scenario envisioned for generators involves a 40% workforce attrition, a nine-month pandemic, and no mutual assistance. As the update suggests, along with universal mitigation strategies, some power companies are eliminating non-essential work that would require close contact, altering assignments so work tasks are done by paired teams that do not rotate, and ensuring workers wear masks. The resource guide includes case studies and lessons learned so far, and all suggest pandemic planning was crucial to response. 

Gearing Up for Mutual Assistance—Even for Generation—During COVID-19
Meanwhile, though the guide recognizes that protecting employees is a key priority for many entities, it also lauds the crucial role mutual assistance plays in the sector’s collective response to the pandemic, even as coal and nuclear plant closures test just transition planning across regions. Mutual assistance is a long-standing power sector practice in the U.S. Last week, for example, as severe weather impacted the southern and eastern portions of the U.S., causing power outages for 1.3 million customers at the peak, the sector demonstrated the “versatility of mutual assistance processes,” bringing in additional workers and equipment from nearby utilities and contractors to assist with assessment and repair. “Crews utilized PPE and social distancing per the CDC [Centers for Disease Control and Prevention] and OSHA [Occupational Safety and Health Administration] guidelines to perform their restoration duties,” the Energy Department told POWER.

But as the ESCC’s guide points out, mutual assistance has traditionally been deployed to help restore electric service to customers, typically focused on T&D infrastructure. The COVID-19 pandemic, uniquely, “has motivated generation entities to consider the use of mutual assistance for generation plant operation” it notes. As with the model it proposes to ensure continuity of control centers, mutual aid poses key challenges, such as for task variance, knowledge of operational practice, system customization, and legal indemnification.

Among guidelines ESCC proposes for generators are to use existing employee work stoppage plans as a resource in planning for the use of personnel not currently assigned to plant operation. It urges, for example, that generators keep a list of workers with skills who can be called from corporate/tech support (such as former operators or plant engineers/managers), or retirees and other individuals who could be called upon to help operate the control room first. ESCC also recommends considering the use of third-party contractor operations to supplement plant operations.

Key to these efforts is to “Create a thorough list of experience and qualifications needed to operate a particular unit. Important details include fuel type, OEM [original equipment manufacturer] technology, DCS [distributed control system] type, environmental controls, certifications, etc,” it says. “Consider proactively sharing this information internally within your company first and then with neighboring companies”—and that includes sufficient detail from manufacturers (such as Emerson Ovation, GE Mark VI, ABB, Honeywell)—“without exposing proprietary information.” One way to control this information is to develop a mutual assistance agreement with “strategic” companies within the region or system, it says.

Of specific interest is that the ESCC also recommends that generators consider “leaving units in extended or planned maintenance outage in that state as long as possible.” That’s because, “Operators at these offline sites could be considered available for a site responding to pandemic challenges,” it says.

However, these guidelines differ by resource. Nuclear generators, for example, already have robust emergency plans that include minimum staffing requirements, and owing to regulations, mutual aid is managed by each license holder, it says. However, to provide possible relief for attrition at operating nuclear plants, the Nuclear Regulatory Commission (NRC) on March 28 outlined a streamlined process that could allow nuclear operators to obtain exemptions from work hour rules, while organizations also point to IAEA low-carbon electricity lessons for future planning.

Uncertainty of Supply Chain Endurance
As the guide stresses, operational continuity during the pandemic will require that all power entities maintain supply of inputs and physical equipment. To help entities plan ahead—by determining volumes needed and geographic location of suppliers—it lists the most important materials needed for power delivery and bulk chemicals. “Clearly, the extent and duration of this emergency will influence the importance of one supply chain component compared to another,” it says.

As Massachusetts Institute of Technology supply chain expert David Simchi-Levi noted on April 13, global supply chains have been heavily taxed by the pandemic, and manufacturing activities in the European Union and North America are still going offline. China is showing signs of slow recovery. Even in the best-case scenario, however—even if North America and Europe manage to control and reduce the pandemic—the supply chain will likely experience significant logistical capacity shortages, from transportation to warehousing. Owing to variability in timing, he suggested that companies plan to reconfigure supply chains and reposition inventory in case suppliers go out of business or face quarantine, while some industry groups urge investing in hydropower as part of resilient recovery strategies.

Also in short supply, according to ESCC, is industry-critical PPE. “While our sector recognizes that the priority is to ensure that PPE is available for workers in the healthcare sector and first responders, a reliable energy supply is required for healthcare and other sectors to deliver their critical services,” its resource guide notes. “The sector is not looking for PPE for the entire workforce. Rather, we are working to prioritize supplies for mission-essential workers – a subset of highly skilled energy workers who are unable to work remotely and who are mission-essential during this extraordinary time.”

Among critical industry PPE needs are nitrile gloves, shoe covers, Tyvek suits, goggles/glasses, hand sanitizer, dust masks, N95 respirators, antibacterial soap, and trashbags. While it provides a list of non-governmental PPE vendors and suppliers, the guide also provides several “creative” solutions. These include, for example, formulations for effective hand sanitizer; 3D printer face shield files; methods for decontaminating face piece respirators and other PPE; and instructions for homemade masks with pockets for high-efficiency particulate air (HEPA) filter inserts.

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Jersey Electricity Standby Charge proposes a grid-backup fee for commercial self-generators of renewable energy, with a review delaying implementation; potential tariff impacts include 10-15 percent price rises, cost recovery, and network reliability.

Key Points

A grid-backup fee for Jersey self-generating businesses to share network costs fairly and curb electricity price rises.

✅ Applies to commercial self-generation using renewables or not

✅ Excludes full exporters and pre-charge installations

✅ Aims to recover grid costs and avoid 10-15% price rises

Electricity prices could rise by ten to 15 per cent if a standby charge for some commercial customers is not implemented, the chief executive of Jersey Electricity has warned.

Jersey Electricity has proposed extending a monthly fee to commercial customers who generate their own power through renewable means but still wish to be connected to Jersey’s grid as a back-up, echoing Ontario energy storage efforts to shore up reliability.

The States recently unanimously backed a proposal lodged by Deputy Carolyn Labey to delay administering the levy until a review could be carried out, as seen in the UK grid's net-zero transformation debates influencing policy. The charge, was due to be implemented next month but will now not be introduced until May, or later if the review has not concluded.

But Chris Ambler, JE chief executive, warned that failing to implement the standby charge could lead to additional costs for customers.

Some of JE’s commercial customers have already been charged a standby fee after generating their own power through non-renewable means.

The charge does not apply to businesses which export all of their electricity back into the system as part of a buy-back scheme or those which install self-generation facilities before the charge is implemented.

Deputy Labey argued that the Island had done ‘absolutely nothing’ to support the use of renewable energies and instead were discouraging locally generated power by allowing JE to set a standby charge.

She added that she was pleased that the Council of Ministers had already starting reviewing the charges but the debate needed to go ahead to ensure the work continued after the May election.

During a States debate last month, she said: ‘It is increasingly concerning that we, as an island in the 21st century, are happy for our electricity to be provided to us by an unregulated, publicly listed for-profit company with a monopoly on energy.

‘I also think that introducing a charge on renewables at a time when the world is experiencing a revolution in renewable energies, including offshore vessel charging solutions, which are becoming increasingly economic, is something that needs to be investigated.

‘Jersey should be looking to diversify our electricity production and supply, to help protect us from price and currency fluctuations and to ensure that we, as an island, receive the best deal possible for Islanders.’

Mr Ambler said that any price increase would be dependent on the future take-up and use of renewable-energy technology in Jersey.

He said: ‘The cost impact would not be significant in the short term but in the long term it could be significant. I think that we are obliged to let our customers know that.

‘It is very difficult to assess but if we are not able to levy a fair charge, then, as electricity shortages in Canada have shown, we could see prices rise by ten to 15 per cent over time.’

Mr Ambler added that his company was in favour of the use of renewable energy, with a third of the company’s electricity being generated by hydroelectric sources, but that the costs of implementing it needed to be fairly distributed, given how big battery rule changes can affect project viability elsewhere in the market.

And he said that, while it was difficult to quantify how much could be lost if the standby charge was not implemented, it could cost the company over £10 million.

‘In 2014, we only increased our prices by one per cent,’ he said. ‘We are reviewing our prices at the moment but if we did put an increase in place it would be modest and it would not be linked to the standby charge.’

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Alliant Energy Net-Zero Carbon Plan outlines carbon-neutral electricity by 2050, coal retirements by 2040, major solar and wind additions, gas transition, battery storage, hydrogen, and carbon credits to reduce emissions and lower customer costs.

Key Points

Alliant Energy's strategy to reach carbon-neutral power by 2050 via coal phaseout, renewables, storage, and offsets.

✅ Targets net-zero electricity by 2050

✅ Retires all coal by 2040; expands solar and wind

✅ Uses storage, hydrogen, and offsets to bridge gaps

Alliant Energy has joined a small but growing group of utilities aiming for carbon-neutral electricity by 2050.

In a report released Wednesday, the Madison-based company announced a goal of “net-zero carbon dioxide emissions” from its electricity generation along with plans to eliminate all coal-powered generation by 2040, a decade earlier than the company’s previous target.

Alliant, which is pursuing plans that would make it the largest solar energy generator in Wisconsin, said it is on track to cut its 2005 carbon emissions in half by 2030.

Both goals are in line with targets an international group of scientists warn is necessary to avoid the most catastrophic impacts of climate change. But reducing greenhouse gasses was not the primary motivation, said executive vice president and general counsel Jim Gallegos.

“The primary driver is focused on our customers and communities and setting them up … to be competitive,” Gallegos said. “We do think renewables are going to do it better than fossil fuels.”

Alliant has told regulators it can save customers up to $6.5 billion over the next 35 years by adding more than 1,600 megawatts of renewable generation, closing one of its two remaining Wisconsin coal plants and taking other undisclosed actions.

In a statement, Alliant chairman and CEO John Larsen said the goal is part of broader corporate and social responsibility efforts “guided by our strategy and designed to deliver on our purpose — to serve customers and build stronger communities.”

Coal out; gas remains
The goal applies only to Alliant’s electricity generation — the company has no plans to stop distributing natural gas for heating — and is “net-zero,” meaning the company could use some form of carbon capture or purchase carbon credits to offset continuing emissions.

The plan relies heavily on renewable generation — seen in regions embracing clean power across North America — including the addition of up to 1,000 megawatts of new Wisconsin solar plants by the end of 2023 and 1,000 megawatts of Iowa wind generation added over the past four years — as well as natural gas generators to replace its aging coal fleet.

But Jeff Hanson, Alliant’s director of sustainability, said eliminating or offsetting all carbon emissions will require new tools, such as battery storage or possibly carbon-free fuels such as hydrogen, and awareness of the Three Mile Island debate over the role of nuclear power in the mix.

“Getting to the 2040 goals, that’s all based on the technologies of today,” Hanson said. “Can we get to net zero today? The challenge would be a pretty high bar to clear.”

Gallegos said the plan does not call for the construction of more large-scale natural gas generators like the recently completed $700 million West Riverside Energy Center in Beloit, though natural gas will remain a key piece of Alliant’s generation portfolio.

Alliant announced plans in May to close its 400-megawatt Edgewater plant in Sheboygan by the end of 2022, echoing how Alberta is retiring coal by 2023 as markets shift, but has not provided a date for the shutdown of the jointly owned 1,100-megawatt Columbia Energy Center near Portage, which received about $1 billion worth of pollution-control upgrades in the past decade.

Alliant’s Iowa subsidiary plans to convert its 52-year-old, 200-megawatt Burlington plant to natural gas by the end of next year and a pair of small coal-fired generators in Linn County by 2025. That leaves the 250-megawatt plant in Lansing, which is now 43 years old, and the 734-megawatt Ottumwa plant as the remaining coal-fired generators, even as others keep a U.S. coal plant running indefinitely elsewhere.

Earlier this year, the utility asked regulators to approve a roughly $900 million investment in six solar farms across the state with a total capacity of 675 megawatts, similar to plans in Ontario to seek new wind and solar to address supply needs. The company plans to apply next year for permission to add up to 325 additional megawatts.

Alliant said the carbon-neutral plan, which entails closing Edgewater along with other undisclosed actions, would save customers between $2 billion and $6.5 billion through 2055 compared to the status quo.

Tom Content, executive director of the Citizens Utility Board, said the consumer advocacy group wants to ensure that ratepayers aren’t forced to continue paying for coal plants that are no longer needed while also paying for new energy sources and would like to see a bigger role for energy efficiency and more transparency about the utilities’ pathways to decarbonization.

‘They could do better’
Environmental groups said the announcement is a step in the right direction, though they say utilities need to do even more to protect the environment and consumers.

Amid competition from cheaper natural gas and renewable energy and pressure from environmentally conscious investors, U.S. utilities have been closing coal plants at a record pace in recent years, as industry CEOs say a coal comeback is unlikely in the U.S., a trend that is expected to continue through the next decade.

“This is not industry leadership when we’re talking about emission reductions,” said Elizabeth Katt Reinders, regional campaign director for the Sierra Club, which has called on Alliant to retire the Columbia plant by 2026.

Closing Edgewater and Columbia would get Alliant nearly halfway to its emissions goals while saving customers more than $250 million over the next decade, according to a Sierra Club study released earlier this year.

“Retiring Edgewater was a really good decision. Investing in 1,000 megawatts of new solar is game-changing for Wisconsin,” Katt Reinders said. “In the same breath we can say this emissions reduction goal is unambitious. Our analysis has shown they can do far more far sooner.”

Scott Blankman, a former Alliant executive who now works as director of energy and air programs for Clean Wisconsin, said Alliant should not run the Columbia plant for another 20 years.

“If they’re saying they’re looking to get out of coal by 2040 in Wisconsin I’d be very disappointed,” Blankman said. “I do think they could do better.”

Alliant is the 15th U.S. investor-owned utility to set a net-zero target, according to the Natural Resources Defense Council, joining Madison Gas and Electric, which announced a similar goal last year. Minnesota-based Xcel Energy, which serves customers in western Wisconsin, was the first large investor-owned utility to set such a target, as state utilities report declining returns in coal operations.

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UK Nuclear Free Electricity Incentive proposes community benefits near reactors, echoing France, supporting net zero goals, energy security, and streamlined planning, while addressing regulation and judicial review challenges for Sizewell C and future nuclear projects.

Key Points

A proposed policy to give free power to residents near reactors, supporting net zero and energy security.

✅ Free power for communities near nuclear plants

✅ Aligns with net zero and energy security goals

✅ Seeks streamlined planning and fewer approvals

UK Business Secretary Jacob Rees-Mogg has endorsed a French-style nuclear system that sees people living near nuclear power stations receive free electricity.

Speaking at an event organised by Policy Exchange think tank, Jacob Rees-Mogg said: “Nuclear power is just fundamental. There’s no way we can get to net zero emissions, or even have an intelligent electricity strategy and grid reform in the UK, without nuclear.”

Highlighting that this was his view and not a government policy announcement, he said: “We should copy the French. As I understand, if you live near a nuclear power station in France, you get free electricity and that’s great because then, I’ll have two in my garden if I get free electricity for my children as well.

“I think you want to recognise that things you do that are in the national interest, such as a state-owned generation company, must benefit those who make the sacrifice for the national interest.”

Earlier Mr Rees-Mogg stressed that he would like to see a simpler development consent process for new nuclear power plants to enable the next waves of reactors in the UK, amid concerns that Europe is losing nuclear power just when it really needs energy.

He said: “That’s a lot of regulation around that, as seen when nuclear plant plans collapsed in Wales and impacted the local economy. Did you know that Sizewell C will require 140 individual approvals from arms of the state, each one of which is potentially subject to judicial review.”

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BC Hydro Rate Freeze delivers immediate relief on electricity rates in British Columbia, reversing a planned 3% hike, as BCUC oversight, a utility review, and Site C project debates shape provincial energy policy.

Key Points

A one-year provincial policy halting BC Hydro electricity rate hikes while a utility review finds cost savings.

✅ Freeze replaces planned 3% hike approved by BCUC.

✅ Government to conduct comprehensive BC Hydro review.

✅ Critics warn $150M revenue loss impacts capital projects.

British Columbia's NDP government has announced it will freeze BC Hydro rates effective immediately, fulfilling a key election promise.

Energy, Mines and Petroleum Resources Minister Michelle Mungall says hydro rates have gone up by more than 24 per cent in the last four years and by more than 70 per cent since 2001, reflecting proposals such as a 3.75% increase over two years announced previously.

"After years of escalating electricity costs, British Columbians deserve a break on their bills," Mungall said in a news release.

BC Hydro had been approved by the B.C. Utilities Commission to increase the rate by three per cent next year, but Mungall said it will pull back its request in order to comply with the freeze.

In the meantime, the government says it will undertake a comprehensive review of the utility meant to identify cost-savings measures for customers often asked to pay an extra $2 a month on electricity bills.

The Liberal critic, Tracy Redies, says the one year rate freeze is going to cost BC Hydro, calling it a distraction from the bigger issue of the future of the Site C project and the oversight of a BC Hydro fund surplus as well.

"A one year rate freeze costs Hydro $150 million," Redies said. "That means there's $150 million less to invest in capital projects and other investments that the utility needs to make."

"This is putting off decisions that should be made today to the future."

Recommendations from the review — including possible new rates — will be implemented starting in April 2019.

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