Montana agency releases analysis of proposed Alberta-Montana power line

Alberta Electricity Market Reform reshapes policy under the UCP, weighing a capacity market versus energy-only design, AESO reliability rules, renewables targets, coal phase-out, carbon pricing, consumer rates, and investment certainty before AUC decisions.

Key Points

Alberta Electricity Market Reform is the UCP plan to reassess capacity vs energy-only, renewables, and carbon pricing.

✅ Reviews capacity market timeline and AESO procurement

✅ Alters subsidies for renewables; slows wind and solar growth

✅ Adjusts industrial carbon levy; audits Balancing Pool losses

Hearings kicked off this week into the future of the province’s electricity market design, amid an electricity market reshuffle pledged by the province, but a high-stakes decision about the industry’s fate — affecting billions of dollars in investment and consumer costs — won’t be made inside the meeting room of the Alberta Utilities Commission.

Instead, it will take place in the office of Jason Kenney, as the incoming premier prepares to pivot away from the seismic reforms to Alberta’s electricity sector introduced by the Notley government.

The United Conservative Party has promised to adopt market-based policies, reflecting changes to how Alberta produces and pays for power, that will reset how the sector operates, from its approach to renewable energy and carbon pricing to re-evaluating the planned transition to an electricity “capacity market.”

“Every ball in electricity is up in the air right now,” Vittoria Bellissimo, of the Industrial Power Consumers Association of Alberta, said Tuesday during a break in the commission hearings.

Industry players are uncertain how quickly the UCP will change direction on power policies, but there’s little doubt Kenney’s government will take a strikingly different approach to the sector that keeps the lights on in Alberta.

“There’s some things they are going to change that are going to impact the electricity industry significantly,” said Duane Reid-Carlson, chief executive of consultancy EDC Associates.

“But I don’t think it’s going to be upheaval. I think the new government will proceed with caution because electricity is the foundation of our economy.”

Alberta’s electricity market has been turned on its head in recent years due to the recession, power prices dropping to near two-decade lows and several transformative policies initiated by the NDP.

The Notley government’s climate plan included an accelerated phase-out of all coal-fired generation and set targets for more renewable energy.

The most significant, but least-understood, move has been the planned shift to an electricity capacity market in 2021.

Under the strategy, generators will no longer solely be paid for the power produced and sold into the market; they will also receive payments for having electricity capacity available to the grid on demand.

The change was recommended by the Alberta Electric System Operator (AESO) as a way to reduce price volatility and provide more reliability than the current energy-only market, which some argue needs more competition to deliver better outcomes.

The independent system operator and industry officials have spent more than two years planning the transition since the switch was announced in late 2016. Proposed rules for the new system, outlining market changes, are now being discussed at the Alberta Utilities Commission hearings.

However, there is no ironclad guarantee the system remake will go ahead following the UCP’s election victory last week — amid calls to scrap the overhaul from a Calgary retailer — it plans to study the issue further — while other substantive electricity changes are already in store.

The UCP has promised to end “costly subsidies” to renewable energy developments and abandon the NDP’s pledge to have such energy sources make up 30 per cent of all power generation by 2030.

It will remove the planned phase-out of coal-fired electricity generation, although federal regulations for a 2030 prohibition remain in place.

It will also ask the auditor general to conduct a special audit of the massive losses sustained by the province’s Balancing Pool due to power purchase arrangements being handed back to the agency three years ago.

While Kenney has pledged to cancel the provincewide carbon tax, a levy on large industrial greenhouse gas emitters (such has power plants) will still be charged, although at a reduced rate of $20 a tonne.

The biggest unknown remains the power market’s structure, which underpins how the entire system operates.

The UCP has promised to consult on the shift to the capacity market and report back to Albertans within 90 days.

The complex issue may sound like an eye-glazer, but it will have a profound effect on industry investment, as well as how much consumers pay on their monthly electricity bills.

A number of industry players worry the capacity market will lead AESO to procure more power than is necessary, foisting unnecessary costs onto all Albertans.

“I still have concerns for what the impact on consumers is going to be,” said energy market consultant Sheldon Fulton. “I’d love to see the capacity market go away.”

An analysis by EDC Associates found the transition to a capacity market will procure additional electricity before it’s needed, requiring consumers to pay up to 40 per cent more — an extra $1.4 billion — for power in 2021-22 than under the existing market structure.

“I don’t think there’s any prejudged outcome,” said Blake Shaffer, former head trader at TransAlta Corp. and a fellow-in-residence at the C.D. Howe Institute.

“But it really matters about getting this right.”

Evan Bahry, executive director of the Independent Power Producers Society of Alberta, said the fact the UCP’s review was confined to just 90 days is helpful, as it avoids throwing the entire industry into a prolonged period of uncertainty.

As for the greening of Alberta’s power grid, amid growing attention to clean grids and storage, the demise of the NDP’s Renewable Electricity Program will likely slow down the rapid pace of wind and solar development. But it’s unlikely to stop the growth trend as costs continue to fall for such developments.

“Renewables over the last number of years have evolved to the point that they make sense on a subsidy-free basis,” said Dan Balaban, CEO of Greengate Power Corp., which has developed 480 MW of wind power in Alberta and Ontario.

“There is a path to clean electricity ahead.”

Chris Varcoe is a Calgary Herald columnist.

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Idaho Power Valmy Settlement outlines early closure of the North Valmy coal-fired plant in Nevada, accelerated depreciation recovery, a 1.17% base-rate increase, and impacts for customers, NV Energy co-ownership, and Idaho Public Utilities Commission review.

Key Points

A proposed agreement to close North Valmy early, recover costs via a 1.17% rate hike, and seek PUC approval.

✅ Unit 1 closes 2019; Unit 2 closes 2025 in Nevada.

✅ 1.17% base-rate hike; about $1.20 per 1,000 kWh monthly bill.

✅ Idaho PUC comment deadline May 25; NV Energy co-owner.

State regulators have set a May 25 deadline for public comment on a proposed settlement related to the early closure of a coal-fired plant co-owned by Idaho Power, even as some utilities plan to keep a U.S. coal plant running indefinitely in other jurisdictions.

The settlement calls for shuttering Unit 1 of the North Valmy Power Plant in Nevada in 2019, with Unit 2 closing in 2025, amid regional coal unit retirements debates. The units had been slated for closure in 2031 and 2035, respectively.

If approved by the Idaho Public Utilities Commission, the settlement would increase base rates by approximately $13.3 million, or 1.17 percent, in order to allow the company to recover its investment in the plant on an accelerated basis.

That equates to an additional $1.20 on the monthly bill of the typical residential customer using 1,000 kilowatt-hours of energy per month.

Idaho Power, which co-owns the plant with NV Energy, maintains that closing Valmy early rather than continuing to operate it until it is fully depreciated in 2035, will ultimately save customers $103 million in today's dollars.

The company said a significant decrease in market prices for electricity has made it uneconomic to operate the plant except during extremely cold or hot weather, when the demand for energy peaks, a trend underscored by transactions involving the San Juan Generating Station deal elsewhere. The company also said plant balances have increased by approximately $70 million since its last general rate case in 2011, due to routine maintenance and repairs, as well as investments required to meet environmental regulations.

The proposed settlement reflects a number of changes to Idaho Power's original proposal regarding Valmy, and comes in the wake of discussions with interested parties in February and April, against the backdrop of a broader energy debate over plant closures and reliability.

In its initial application, filed in October, Idaho Power proposed closing both units in 2025. The original proposal would have increased base rates by $28.5 million, or about 2.5 percent, in order to allow the company to recover its costs associated with the plant's accelerated depreciation, decommissioning and anticipated investments, with cautionary examples such as the Kemper power plant costs illustrating potential risks.

Concurrently, Idaho Power asked for commission approval to adjust depreciation rates for its other plants and equipment based on the result of a study it conducts every five years, as outlined in Case IPC-E-16-23. The adjustment would have led to a $6.7 million increase to base rates.

The two requests filed in October would have increased customer costs by a total of $35.2 million or 3.1 percent, leading to a $3.08 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

The proposed settlement submitted to the Commission on May 4 calls for $13,285,285 to be recovered from all customer classes through base rates until 2028, all related to the Valmy shutdown. That is an increase of 1.17 percent and would result in a $1.20 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

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EV Subsidies in Canada influence greenhouse-gas emissions based on electricity grid mix; in Ontario and Quebec they reduce pollution, while fossil-fuel grids blunt benefits. Compare costs per tonne with carbon tax and renewable energy policies.

Key Points

Government rebates for electric vehicles, whose emissions impact and cost-effectiveness depend on provincial grid mix.

✅ Impact varies by grid emissions; clean hydro-nuclear cuts CO2.

✅ MEI estimates up to $523 per tonne vs $50 carbon price.

✅ Best value: tax carbon; target renewables, efficiency, hybrids.

Bad ideas sometimes look better, and sell better, than good ones – as with the proclaimed electric-car revolution that policymakers tout today. Not always, or else Canada wouldn’t be the mostly well-run place that it is. But sometimes politicians embrace a less-than-best policy – because its attractive appearance may make it more likely to win the popularity contest, right now, even though it will fail in the long run.

The most seasoned political advisers know it. Pollsters too. Voters, in contrast, don’t know what they don’t know, which is why bad policy often triumphs. At first glance, the wrong sometimes looks like it must be right, while better and best give the appearance of being bad and worst.

This week, the Montreal Economic Institute put out a study on the costs and benefits of taxpayer subsidies for electric cars. They considered the logic of the huge amounts of money being offered to purchasers in the country’s two largest provinces. In Quebec, if you buy an electric vehicle, the government will give you up to $8,000; in Ontario, buying an electric car or truck entitles you to a cheque from the taxpayer of between $6,000 and $14,000. The subsidies are rich because the cars aren’t cheap.

Will putting more electric cars on the road lower greenhouse-gas emissions? Yes – in some provinces, where they can be better for the planet when the grid is clean. But it all depends on how a province generates electricity. In places like Alberta, Saskatchewan, Nova Scotia and Nunavut territory, where most electricity comes from burning fossil fuels, an electric car may actually generate more greenhouse gases than one running on traditional gasoline. The tailpipe of an electric vehicle may not have any emissions. But quite a lot of emissions may have been generated to produce the power that went to the socket that charged it.

A few years ago, University of Toronto engineering professor Christopher Kennedy estimated that electric cars are only less polluting than the gasoline vehicles they replace when the local electrical grid produces a good chunk of its power from renewable sources – thereby lowering emissions to less than roughly 600 tonnes of CO2 per gigawatt hour.

Unfortunately, the electricity-generating systems in lots of places – from India to China to many American states – are well above that threshold. In those jurisdictions, an electric car will be powered in whole or in large part by electricity created from the burning of a fossil fuel, such as coal. As a result, that car, though carrying the green monicker of “electric,” is likely to be more polluting than a less costly model with an internal combustion or hybrid engine.

The same goes for the Canadian juridictions mentioned above. Their electricity is dirtier, so operating an electric car there won’t be very green. Alberta, for example, is aiming to generate 30 per cent of its electricity from renewable sources by 2030 – which means that the other 70 per cent of its electricity will still come from fossil fuels. (Today, the figure is even higher.) An Albertan trading in a gasoline car for an electric vehicle is making a statement – just not the one he or she likely has in mind.

In Ontario and Quebec, however, most electricity is generated from non-polluting sources, even though Canada still produced 18% from fossil fuels in 2019 overall. Nearly all of Quebec’s power comes from hydro, and more than 90 per cent of Ontario’s electricity is from zero-emission generation, mainly hydro and nuclear. British Columbia, Manitoba and Newfoundland and Labrador also produce the bulk of their electricity from hydro. Electric cars in those provinces, powered as they are by mostly clean electricity, should reduce emissions, relative to gas-powered cars.

But here’s the rub: Electric cars are currently expensive, and, as a recent survey shows, consequently not all that popular. Ontario and Quebec introduced those big subsidies in an attempt to get people to buy them. Those subsidies will surely put more electric cars on the road and in the driveways of (mostly wealthy) people. It will be a very visible policy – hey, look at all those electrics on the highway and at the mall!

However, that result will be achieved at great cost. According to the MEI, for Ontario to reach its goal of electrics constituting 5 per cent of new vehicles sold, the province will have to dish out up to $8.6-billion in subsidies over the next 13 years.

And the environmental benefits achieved? Again, according to the MEI estimate, that huge sum will lower the province’s greenhouse-gas emissions by just 2.4 per cent. If the MEI’s estimate is right, that’s far too many bucks for far too small an environmental bang.

Here’s another way to look at it: How much does it cost to reduce greenhouse-gas emissions by other means? Well, B.C.’s current carbon tax is $30 a tonne, or a little less than 7 cents on a litre of gasoline. It has caused GHG emissions per unit of GDP to fall in small but meaningful ways, thanks to consumers and businesses making millions of little, unspectacular decisions to reduce their energy costs. The federal government wants all provinces to impose a cost equivalent to $50 a tonne – and every economic model says that extra cost will make a dent in greenhouse-gas emissions, though in ways that will not involve politicians getting to cut any ribbons or hold parades.

What’s the effective cost of Ontario’s subsidy for electric cars? The MEI pegs it at $523 per tonne. Yes, that subsidy will lower emissions. It just does so in what appears to be the most expensive and inefficient way possible, rather than the cheapest way, namely a simple, boring and mildly painful carbon tax.

Electric vehicles are an amazing technology. But they’ve also become a way of expressing something that’s come to be known as “virtue signalling.” A government that wants to look green sees logic in throwing money at such an obvious, on-brand symbol, or touting a 2035 EV mandate as evidence of ambition. But the result is an off-target policy – and a signal that is mostly noise.

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IVECO BUS hydrogen and electric buses in France accelerate clean mobility, zero-emission public transport, fleet electrification, and fuel cell adoption, with battery-electric ranges, fast charging, hydrogen refueling, lower TCO, and high passenger comfort in cities.

Key Points

Zero-emission buses using battery-electric and fuel cell tech, cutting TCO with fast refueling and urban-ready range.

✅ Zero tailpipe emissions, lower noise, improved air quality

✅ Fast charging and rapid hydrogen refueling infrastructure

✅ Lower TCO via reduced fuel and maintenance costs

IVECO BUS is making significant strides in the French public transportation sector, recently securing contracts for the delivery of hydrogen and battery electric buses. This development underscores the growing commitment of cities and regions in France to transition to cleaner, more sustainable public transportation options, even as electric bus adoption challenges persist. With these new contracts, IVECO BUS is poised to strengthen its position as a leader in the electric mobility market.

Expanding the Green Bus Fleet

The contracts involve the supply of various models of IVECO's hydrogen and electric buses, highlighting a strategic shift towards sustainable transport solutions. France has been proactive in its efforts to reduce carbon emissions and promote environmentally friendly transportation. As part of this initiative, many local authorities are investing in clean bus fleets, which has opened up substantial opportunities for manufacturers like IVECO.

These contracts will provide multiple French cities with advanced vehicles designed to minimize environmental impact while maintaining high performance and passenger comfort. The move towards hydrogen and battery electric buses reflects a broader trend in public transportation, where cities are increasingly adopting green technologies, with lessons from TTC's electric bus fleet informing best practices to meet both regulatory requirements and public demand for cleaner air.

The Role of Hydrogen and Battery Electric Technology

Hydrogen and battery electric buses represent two key technologies in the transition to sustainable transport. Battery electric buses are known for their zero tailpipe emissions, making them ideal for urban environments where air quality is a pressing concern, as demonstrated by the TTC battery-electric rollout in North America. IVECO's battery electric models come equipped with advanced features, including fast charging capabilities and longer ranges, making them suitable for various operational needs.

On the other hand, hydrogen buses offer the advantage of rapid refueling and extended range, addressing some of the limitations associated with battery electric vehicles, as seen with fuel cell buses in Mississauga deployments across transit networks. IVECO’s hydrogen buses utilize cutting-edge fuel cell technology, allowing them to operate efficiently in urban and intercity routes. This flexibility positions them as a viable solution for public transport authorities aiming to diversify their fleets.

Economic and Environmental Benefits

The adoption of hydrogen and battery electric buses is not only beneficial for the environment but also presents economic opportunities. By investing in these technologies, local governments can reduce operating costs associated with traditional diesel buses. Electric and hydrogen buses generally have lower fuel costs and require less maintenance, resulting in long-term savings.

Furthermore, the transition to cleaner buses can help stimulate local economies. As cities invest in electric mobility, new jobs will be created in manufacturing, maintenance, and infrastructure development, such as charging stations and hydrogen fueling networks, including the UK bus charging hub model, which supports large-scale operations. This shift can have a positive ripple effect, contributing to overall economic growth while fostering a cleaner environment.

IVECO BUS's Commitment to Sustainability

IVECO BUS's recent successes in France align with the company’s broader commitment to sustainability and innovation. As part of the CNH Industrial group, IVECO is dedicated to advancing green technologies and reducing the carbon footprint of public transportation. The company has been at the forefront of developing environmentally friendly vehicles, and these new contracts further reinforce its leadership position in the market.

Moreover, IVECO is investing in research and development to enhance the performance and efficiency of its electric and hydrogen buses. This commitment to innovation ensures that the company remains competitive in a rapidly evolving market while meeting the changing needs of public transport authorities.

Future Prospects

As more cities in France and across Europe commit to sustainable transportation, including initiatives like the Berlin zero-emission bus initiative, the demand for hydrogen and battery electric buses is expected to grow. IVECO BUS is well-positioned to capitalize on this trend, with a diverse range of products that cater to various operational requirements.

The successful implementation of these contracts will likely encourage other regions to follow suit, paving the way for a greener future in public transportation. As IVECO continues to innovate and expand its offerings, alongside developments like Volvo electric trucks in Europe, it sets a precedent for the industry, illustrating how commitment to sustainability can drive business success.

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Utility Battery Storage Rankings measure grid-connected capacity, not ownership, highlighting MW, MWh, and watts per customer across PJM, MISO, and California IOUs, featuring Duke Energy, IPL, ancillary services, and frequency regulation benefits.

Key Points

Rankings that track energy storage connected to utility grids, comparing MW, MWh, and W/customer rather than ownership.

✅ Ranks by MW, MWh, and watts per customer, not asset ownership

✅ Highlights PJM, MISO cases and California IOUs' deployments

✅ Examples: Duke Energy, IPL, IID; ancillary services, frequency response

The rankings do not tally how much energy storage a utility built or owns, but how much was connected to their system. So while IPL built and owns the storage facility in its territory, Duke does not own the 16 MW of storage that connected to its system in 2016. Similarly, while California’s utilities are permitted to own some energy storage assets, they do not necessarily own all the storage facilities connected to their systems.

Measured by energy (MWh), IPL ranked fourth with 20 MWh, and Duke Energy Ohio ranked eighth with 6.1 MWh.

Ranked by energy storage watts per customer, IPL and Duke actually beat the California utilities, ranking fifth and sixth with 42 W/customer and 23 W/customer, respectively.

Duke ready for next step

Given Duke’s plans, including projects in Florida that are moving ahead, the utility is likely to stay high in the rankings and be more of a driving force in development. “Battery technology has matured, and we are ready to take the next step,” Duke spokesman Randy Wheeless told Utility Dive. “We can go to regulators and say this makes economic sense.”

Duke began exploring energy storage in 2012, and until now most of its energy storage efforts were focused on commercial projects in competitive markets where it was possible to earn revenues. Those included its 36 MW Notrees battery storage project developed in partnership with the Department of Energy in 2012 that provides frequency regulation for the Electric Reliability Council of Texas market and two 2 MW storage projects at its retired W.C. Beckjord plant in New Richmond, Ohio, that sells ancillary services into the PJM Interconnection market.

On the regulated side, most of Duke’s storage projects have had “an R&D slant to them,” Wheeless said, but “we are moving beyond the R&D concept in our regulated territory and are looking at storage more as a regulated asset.”

“We have done the demos, and they have proved out,” Wheeless said. Storage may not be ready for prime time everywhere, he said, but in certain locations, especially where it can it can be used to do more than one thing, it can make sense.

Wheeless said Duke would be making “a number of energy storage announcements in the next few months in our regulated states.” He could not provide details on those projects.

More flexible resources
Location can be a determining factor when building a storage facility. For IPL, serving the wholesale market was a driving factor in the rationale to build its 20 MW, 20 MWh storage facility in Indianapolis.

IPL built the project to address a need for more flexible resources in light of “recent changes in our resource mix,” including decreasing coal-fired generation and increasing renewables and natural gas-fired generation, as other regions plan to rely on battery storage to meet rising demand, Joan Soller, IPL’s director of resource planning, told Utility Dive in an email. The storage facility is used to provide primary frequency response necessary for grid stability.

The Harding Street storage facility in May. It was the first energy storage project in the Midcontinent ISO. But the regulatory path in MISO is not as clear as it is in PJM, whereas initiatives such as Ontario storage framework are clarifying participation. In November, IPL with the Federal Energy Regulatory Commission, asking the regulator to find that MISO’s rules for energy storage are deficient and should be revised.

Soller said IPL has “no imminent plans to install energy storage in the future but will continue to monitor battery costs and capabilities as potential resources in future Integrated Resource Plans.”

California legislative and regulatory push

In California, energy storage did not have to wait for regulations to catch up with technology. With legislative and regulatory mandates, including CEC long-duration storage funding announced recently, as a push, California’s IOUs took high places in SEPA’s rankings.

Southern California Edison and San Diego Gas & Electric were first and fourth (63.2 MW and 17.2 MW), respectively, in terms of capacity. SoCal Ed and SDG&E were first and second (104 MWh and 28.4 MWh), respectively, and Pacific Gas and Electric was fifth (17 MWh) in terms of energy.

But a public power utility, the Imperial Irrigation District (IID), ended up high in the rankings – second in capacity (30 MW) and third  in energy (20 MWh) – even though as a public power entity it is not subject to the state’s energy storage mandates.

But while IID was not under state mandate, it had a compelling regulatory reason to build the storage project. It was part of a settlement reached with FERC over a September 2011 outage, IID spokeswoman Marion Champion said.

IID agreed to a $12 million fine as part of the settlement, of which $9 million was applied to physical improvements of IID’s system.

IID ended up building a 30 MW, 20 MWh lithium-ion battery storage system at its El Centro generating station. The system went into service in October 2016 and in May, IID used the system’s 44 MW combined-cycle natural gas turbine at the generating station.

Passing savings to customers
The cost of the storage system was about $31 million, and based on its experience with the El Centro project, Champion said IID plans to add to the existing batteries. “We are continuing to see real savings and are passing those savings on to our customers,” she said.

Champion said the battery system gives IID the ability to provide ancillary services without having to run its larger generation units, such as El Centro Unit 4, at its minimum output. With gas prices at $3.59 per million British thermal units, it costs about $26,880 a day to run Unit 4, she said.

IID’s territory is in southeastern California, an area with a lot of renewable resources. IID is also not part of the California ISO and acts as its own balancing authority. The battery system gives the utility greater operational flexibility, in addition to the ability to use more of the surrounding renewable resources, Champion said.

In May, IID’s board gave the utility’s staff approval to enter into contract negotiations for a 7 MW, 4 MWh expansion of its El Centro storage facility. The negotiations are ongoing, but approval could come in the next couple months, Champion said.

The heart of the issue, though, is “the ability of the battery system to lower costs for our ratepayers,” Champion said. “Our planning section will continue to utilize the battery, and we are looking forward to its expansion,” she said.” I expect it will play an even more important role as we continue to increase our percentage of renewables.”

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Nuclear Plant Climate Risks span flood risk, heat stress, and water scarcity, threatening operations, safety systems, and steam generation; resilience depends on mitigation investments, cooling-water management, and adaptive maintenance strategies.

Key Points

Climate-driven threats to nuclear plants: floods, heat, and water stress requiring resilience and mitigation.

✅ Flooding threats to safety and cooling systems

✅ Heat stress reduces thermal efficiency and output

✅ Water scarcity risks limit cooling capacity

Climate change can affect every aspect of nuclear plant operations like fuel handling, power and steam generation and the need for resilient power systems planning, maintenance, safety systems and waste processing, the credit rating agency said.

However, the ultimate credit impact will depend upon the ability of plant operators to invest in carbon-free electricity and other mitigating measures to manage these risks, it added.
Close proximity to large water bodies increase the risk of damage to plant equipment that helps ensure safe operation, the agency said in a note.

Moody’s noted that about 37 gigawatts (GW) of U.S. nuclear capacity is expected to have elevated exposure to flood risk and 48 GW elevated exposure to combined rising heat, extreme heat costs and water stress caused by climate change.

Parts of the Midwest and southern Florida face the highest levels of heat stress, while the Rocky Mountain region and California face the greatest reduction in the availability of future water supply, illustrating the need for adapting power generation to drought strategies, it said.

Nuclear plants seeking to extend their operations by 20, or even 40 years, beyond their existing 40-year licenses in support of sustaining U.S. nuclear power and decarbonization face this climate hazard and may require capital investment adjustments, Moody’s said, as companies such as Duke Energy climate report respond to investor pressure for climate transparency.

“Some of these investments will help prepare for the increasing severity and frequency of extreme weather events, highlighting that the US electric grid is not designed for climate impacts today.”

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