Comverge reaches 126-MW demand reduction deal with Nevada Power

Rolls-Royce SMR UK Approval underscores nuclear innovation as regulators review a 470 MW factory-built modular reactor, aiming for grid power by 2029 to boost energy security, cut fossil fuels, and accelerate decarbonization.

Key Points

UK regulatory clearance for Rolls-Royce's 470 MW modular reactor, targeting grid power by 2029 to support clean energy.

✅ UK design approval expected by mid 2024

✅ First 470 MW unit aims for grid power by 2029

✅ Modular, factory-built; est. £1.8b per 10-acre site

A Rolls-Royce (RR.L) design for a small modular nuclear reactor (SMR) will likely receive UK regulatory approval by mid-2024, reflecting progress seen in the US NRC safety evaluation for NuScale as a regulatory benchmark, and be able to produce grid power by 2029, Paul Stein, chairman of Rolls-Royce Small Modular Reactors.

The British government asked its nuclear regulator to start the approval process in March, in line with the UK's green industrial revolution agenda, having backed Rolls-Royce’s $546 million funding round in November to develop the country’s first SMR reactor.

Policymakers hope SMRs will help cut dependence on fossil fuels and lower carbon emissions, as projects like Ontario's first SMR move ahead in Canada, showing momentum.

Speaking to Reuters in an interview conducted virtually, Stein said the regulatory “process has been kicked off, amid broader moves such as a Canadian SMR initiative to coordinate development, and will likely be complete in the middle of 2024.

“We are trying to work with the UK Government, and others to get going now placing orders, echoing expansions like Darlington SMR plans in Ontario, so we can get power on grid by 2029.”

In the meantime, Rolls-Royce will start manufacturing parts of the design that are most unlikely to change, while advancing partnerships like a MoU with Exelon to support deployment, Stein added.

Each 470 megawatt (MW) SMR unit costs 1.8 billion pounds ($2.34 billion) and would be built on a 10-acre site, the size of around 10 football fields, though projects in New Brunswick SMR debate have prompted questions about costs and timelines.

Unlike traditional reactors, SMRs are cheaper and quicker to build and can also be deployed on ships and aircraft. Their “modular” format means they can be shipped by container from the factory and installed relatively quickly on any proposed site.

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Duke Energy Clean Energy Strategy advances renewables, battery storage, grid modernization, and energy efficiency to cut carbon, retire coal, and target net-zero by 2050 across the Carolinas with robust IRPs and capital investments.

Key Points

Plan to expand renewables, storage, and grid upgrades to cut carbon and reach net-zero electricity by 2050.

✅ 56B investment in renewables, storage, and grid modernization

✅ Targets 50% carbon reduction by 2030 and net-zero by 2050

✅ Retires coal units; expands energy efficiency and IRPs

Duke Energy says that the company will continue advancing its ambitious clean energy goals without the Atlantic Coast Pipeline (ACP) by investing in renewables, battery storage, energy efficiency programs and grid projects that support U.S. electrification efforts.

Duke Energy, the nation's largest electric utility, unveils its new logo. (PRNewsFoto/Duke Energy) (PRNewsfoto/Duke Energy)

Duke Energy's $56 billion capital investment plan will deliver significant customer benefits and create jobs at a time when policymakers at all levels are looking for ways to rebuild the economy in 2020 and beyond. These investments will deliver cleaner energy for customers and communities while enhancing the energy grid to provide greater reliability and resiliency.

"Sustainability and the reduction of carbon emissions are closely tied to our region's success," said Lynn Good, Duke Energy Chair, President and CEO. "In our recent Climate Report, we shared a vision of a cleaner electricity future with an increasing focus on renewables and battery storage in addition to a diverse mix of zero-carbon nuclear, natural gas, hydro and energy efficiency programs.

"Achieving this clean energy vision will require all of us working together to develop a plan that is smart, equitable and ensures the reliability and affordability that will spur economic growth in the region. While we're disappointed that we're not able to move forward with ACP, we will continue exploring ways to help our customers and communities, particularly in eastern North Carolina where the need is great," said Good.

Already a clean-energy leader, Duke Energy has reduced its carbon emissions by 39% from 2005 and remains on track to cut its carbon emissions by at least 50% by 2030, as peers like Alliant's carbon-neutral plan demonstrate broader industry momentum toward decarbonization. The company also has an ambitious clean energy goal of reaching net-zero emissions from electricity generation by 2050. 

In September 2020, Duke Energy plans to file its Integrated Resource Plans (IRP) for the Carolinas after an extensive process of working with the state's leaders, policymakers, customers and other stakeholders. The IRPs will include multiple scenarios to support a path to a cleaner energy future in the Carolinas, reflecting key utility trends shaping resource planning.

Since 2010, Duke Energy has retired 51 coal units totaling more than 6,500 megawatts (MW) and plans to retire at least an additional 900 MW by the end of 2024. In 2019, the company proposed to shorten the book lives of another approximately 7,700 MW of coal capacity in North Carolina and Indiana.

Duke Energy will host an analyst call in early August 2020 to discuss second quarter 2020 financial results and other business and financial updates. The company will also host its inaugural Environmental, Social and Governance (ESG) investor day in October 2020.

Duke Energy

Duke Energy is transforming its customers' experience, modernizing the energy grid, generating cleaner energy and expanding natural gas infrastructure to create a smarter energy future for the people and communities it serves. The Electric Utilities and Infrastructure unit's regulated utilities serve 7.8 million retail electric customers in six states: North Carolina, South Carolina, Florida, Indiana, Ohio and Kentucky. The Gas Utilities and Infrastructure unit distributes natural gas to 1.6 million customers in five states: North Carolina, South Carolina, Tennessee, Ohio and Kentucky. The Duke Energy Renewables unit operates wind and solar generation facilities across the U.S., as well as energy storage and microgrid projects.

Duke Energy was named to Fortune's 2020 "World's Most Admired Companies" list and Forbes' "America's Best Employers" list. More information about the company is available at duke-energy.com. The Duke Energy News Center contains news releases, fact sheets, photos, videos and other materials. Duke Energy's illumination features stories about people, innovations, community topics and environmental issues. Follow Duke Energy on Twitter, LinkedIn, Instagram and Facebook.

Forward-Looking Information

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management's beliefs and assumptions and can often be identified by terms and phrases that include "anticipate," "believe," "intend," "estimate," "expect," "continue," "should," "could," "may," "plan," "project," "predict," "will," "potential," "forecast," "target," "guidance," "outlook" or other similar terminology. Various factors may cause actual results to be materially different than the suggested outcomes within forward-looking statements; accordingly, there is no assurance that such results will be realized. These factors include, but are not limited to:

• The impact of the COVID-19 electricity demand shift on operations and revenues;
• State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements, including those related to climate change, as well as rulings that affect cost and investment recovery or have an impact on rate structures or market prices;
• The extent and timing of costs and liabilities to comply with federal and state laws, regulations and legal requirements related to coal ash remediation, including amounts for required closure of certain ash impoundments, are uncertain and difficult to estimate;
• The ability to recover eligible costs, including amounts associated with coal ash impoundment retirement obligations and costs related to significant weather events, and to earn an adequate return on investment through rate case proceedings and the regulatory process;
• The costs of decommissioning nuclear facilities could prove to be more extensive than amounts estimated and all costs may not be fully recoverable through the regulatory process;
• Costs and effects of legal and administrative proceedings, settlements, investigations and claims;
• Industrial, commercial and residential growth or decline in service territories or customer bases resulting from sustained downturns of the economy and the economic health of our service territories or variations in customer usage patterns, including energy efficiency and demand response efforts and use of alternative energy sources, such as self-generation and distributed generation technologies;
• Federal and state regulations, laws and other efforts designed to promote and expand the use of energy efficiency measures and distributed generation technologies, such as private solar and battery storage, in Duke Energy service territories could result in customers leaving the electric distribution system, excess generation resources as well as stranded costs;
• Advancements in technology;
• Additional competition in electric and natural gas markets and continued industry consolidation;
• The influence of weather and other natural phenomena on operations, including the economic, operational and other effects of severe storms, hurricanes, droughts, earthquakes and tornadoes, including extreme weather associated with climate change;
• The ability to successfully operate electric generating facilities and deliver electricity to customers including direct or indirect effects to the company resulting from an incident that affects the U.S. electric grid or generating resources;
• The ability to obtain the necessary permits and approvals and to complete necessary or desirable pipeline expansion or infrastructure projects in our natural gas business;
• Operational interruptions to our natural gas distribution and transmission activities;
• The availability of adequate interstate pipeline transportation capacity and natural gas supply;
• The impact on facilities and business from a terrorist attack, cybersecurity threats, data security breaches, operational accidents, information technology failures or other catastrophic events, such as fires, explosions, pandemic health events or other similar occurrences;
• The inherent risks associated with the operation of nuclear facilities, including environmental, health, safety, regulatory and financial risks, including the financial stability of third-party service providers;
• The timing and extent of changes in commodity prices and interest rates and the ability to recover such costs through the regulatory process, where appropriate, and their impact on liquidity positions and the value of underlying assets;
• The results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings, interest rate fluctuations, compliance with debt covenants and conditions and general market and economic conditions;
• Credit ratings of the Duke Energy Registrants may be different from what is expected;
• Declines in the market prices of equity and fixed-income securities and resultant cash funding requirements for defined benefit pension plans, other post-retirement benefit plans and nuclear decommissioning trust funds;
• Construction and development risks associated with the completion of the Duke Energy Registrants' capital investment projects, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules and satisfying operating and environmental performance standards, as well as the ability to recover costs from customers in a timely manner, or at all;
• Changes in rules for regional transmission organizations, including FERC debates on coal and nuclear subsidies and new and evolving capacity markets, and risks related to obligations created by the default of other participants;
• The ability to control operation and maintenance costs;
• The level of creditworthiness of counterparties to transactions;
• The ability to obtain adequate insurance at acceptable costs;
• Employee workforce factors, including the potential inability to attract and retain key personnel;
• The ability of subsidiaries to pay dividends or distributions to Duke Energy Corporation holding company (the Parent);
• The performance of projects undertaken by our nonregulated businesses and the success of efforts to invest in and develop new opportunities;
• The effect of accounting pronouncements issued periodically by accounting standard-setting bodies;
• The impact of U.S. tax legislation to our financial condition, results of operations or cash flows and our credit ratings;
• The impacts from potential impairments of goodwill or equity method investment carrying values; and
• The ability to implement our business strategy, including enhancing existing technology systems.
• Additional risks and uncertainties are identified and discussed in the Duke Energy Registrants' reports filed with the SEC and available at the SEC's website at sec.gov. In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than described. Forward-looking statements speak only as of the date they are made and the Duke Energy Registrants expressly disclaim an obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Alberta Rate of Last Resort provides a baseline electricity price, boosting energy reliability, affordability, and consumer protection amid market volatility, aligning with grid modernization, integration, pricing transparency, and oversight from the Alberta Utilities Commission.

Key Points

A fallback electricity rate ensuring affordable, reliable power and consumer protection during market volatility.

✅ Guarantees a stable baseline price when markets spike

✅ Supports vulnerable customers lacking competitive offers

✅ Overseen by AUC to balance protection and competition

The Alberta government has announced significant strides in its electricity market reforms, unveiling a new plan under new electricity rules that aims to enhance energy reliability and affordability for consumers. This initiative, highlighted by the introduction of a "rate of last resort," is a critical response to ongoing challenges in the province's electricity sector, particularly following recent market volatility and increasing consumer concerns about rising electricity prices across the province.

Understanding the Rate of Last Resort

The "rate of last resort" (RLR) is designed to ensure that all Albertans have access to affordable electricity, even when they face challenges securing a competitive rate in the open market. This measure is particularly beneficial for those who may not have the means or the knowledge to navigate complex energy contracts, such as low-income families or seniors.

Under this new plan, the RLR will serve as a safety net, guaranteeing a stable and predictable rate for customers who find themselves without a competitive provider. This move is seen as a crucial step in addressing the needs of vulnerable populations who might otherwise be at risk of being shut out of the energy market.

Market Volatility and Consumer Protection

Alberta's electricity market has faced significant fluctuations over the past few years, and is headed for a reshuffle as policymakers respond to unpredictability in pricing and service availability. The rise in energy costs has caused distress among consumers, with many advocating for stronger protections against sudden price hikes.

The government's recent decision to implement the RLR is a direct acknowledgment of these concerns. By creating a baseline rate, officials aim to provide consumers with peace of mind, knowing that there is a fallback option should market conditions turn unfavorable. This initiative complements other measures aimed at enhancing consumer protections, including improved transparency in pricing, the consumer price cap on power bills being advanced, and the regulation of energy suppliers.

Broader Implications for Alberta’s Energy Landscape

This plan is not only about consumer protection; it also represents a broader shift towards a more sustainable and stable energy market in Alberta, aligning with proposed electricity market changes under consideration. The introduction of the RLR is part of a comprehensive strategy that includes investments in renewable energy and infrastructure improvements. By modernizing the grid and promoting cleaner energy sources, the government aims to reduce dependency on fossil fuels while maintaining reliability and affordability.

Additionally, this move aligns with the province's goals to meet climate targets and transition to a more sustainable energy future as Alberta is changing how it produces and pays for electricity through policy updates. As the demand for clean energy grows, Alberta is positioning itself to be a leader in this transformation, appealing to both residents and businesses committed to sustainability.

Public and Industry Reactions

The announcement has garnered mixed reactions from various stakeholders. While consumer advocacy groups have largely praised the government's efforts to protect consumers and ensure affordable electricity, some industry experts express concerns about potential long-term impacts on competition, arguing the market needs competition to remain dynamic. They argue that while the RLR provides immediate relief, it could disincentivize companies from offering competitive rates, leading to a less dynamic market in the future.

The Alberta Utilities Commission (AUC) is expected to play a pivotal role in overseeing the implementation of the RLR, ensuring that it operates effectively and that any unintended consequences are addressed swiftly. This regulatory oversight will be crucial in balancing consumer protection with the need for a competitive energy market.

Conclusion

As Alberta forges ahead with its electricity market reforms, the introduction of the rate of last resort marks a significant step in enhancing consumer protection and ensuring energy affordability. While challenges remain, the government's proactive approach reflects a commitment to addressing the needs of all Albertans, particularly those most vulnerable to market fluctuations.

In this evolving energy landscape, the RLR will serve not only as a safety net for consumers but also as a foundation for a more sustainable and reliable electricity system. As Alberta continues to adapt to changing energy demands and climate considerations, the effectiveness of these measures will be closely monitored, shaping the future of the province’s electricity market.

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Germany Nuclear Power Extension keeps Isar 2, Neckarwestheim 2, and Emsland running as Olaf Scholz tackles the energy crisis, soaring gas prices, and EU winter demand, prioritizing grid stability amid the Ukraine war.

Key Points

A temporary policy keeping three German reactors online to enhance grid stability and national energy security.

✅ Extends Isar 2, Neckarwestheim 2, and Emsland operations

✅ Addresses EU energy crisis and soaring gas prices

✅ Prioritizes grid stability while coal phase-out advances

German Chancellor Olaf Scholz has ordered the country's three remaining nuclear power stations to keep operating until mid-April, signalling a nuclear U-turn as the energy crisis sparked by Russia's invasion of Ukraine hurts the economy.

Originally Germany planned to phase out all three by the end of this year, continuing its nuclear phaseout policy at the time.

Mr Scholz's order overruled the Greens in his coalition, who wanted two plants kept on standby, to be used if needed.

Nuclear power provides 6% of Germany's electricity.

The decision to phase it out was taken by former chancellor Angela Merkel after Japan's Fukushima nuclear disaster in 2011.

But gas prices have soared since Russia's invasion of Ukraine in February, which disrupted Russia's huge oil and gas exports to the EU, though some officials argue that nuclear would do little to solve the gas issue in the short term. In August Russia turned off the gas flowing to Germany via the Nord Stream 1 undersea pipeline.

After relying so heavily on Russian gas Germany is now scrambling to maintain sufficient reserves for the winter. The crisis has also prompted it to restart mothballed coal-fired power stations, with coal generating about a third of its electricity currently, though the plan is to phase out coal in the drive for green energy.

Last year Germany got 55% of its gas from Russia, but in the summer that dropped to 35% and it is declining further.

EU leaders consider how to cap gas prices
France sends Germany gas for first time amid crisis
Chancellor Scholz's third coalition partner, the liberal Free Democrats (FDP), welcomed his move to keep nuclear power as part of the mix. The three remaining nuclear plants are Isar 2, Neckarwestheim 2 and Emsland, which were ultimately shut down after the extension.

The Social Democrat (SPD) chancellor also called for ministries to present an "ambitious" law to boost energy efficiency and to put into law a phase-out of coal by 2030, aiming for a coal- and nuclear-free economy among major industrial nations.

Last week climate activist Greta Thunberg said it was a "mistake" for Germany to press on with nuclear decommissioning while resorting to coal again, intensifying debate over a nuclear option for climate goals nationwide.

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Ontario EV Battery Storage ROI leverages V2B, V2G, two-way charging, demand response, and second-life batteries to monetize peak pricing, cut GHG emissions, and unlock up to $38,000 in lifetime value for commuters and buildings.

Key Points

The economic return from V2B/V2G two-way charging and second-life storage using EV batteries within Ontario's grid.

✅ Monetize peak pricing via workplace V2B discharging

✅ Earn up to $8,400 per EV over vehicle life

✅ Reduce gas generation and GHGs with demand response

The payback that usually comes to mind when people buy an electric vehicle is to drive an emissions-free, low-maintenance, better-performing mode of transportation.

On top of that, you can now add $38,000.

That, according to a new report from Ontario electric vehicle education and advocacy nonprofit, Plug‘n Drive, is the potential lifetime return for an electric car driven as a commuter vehicle while also being used as an electricity storage option amid an energy storage crunch in Ontario’s electricity system.

“EVs contain large batteries that store electric energy,” says the report. “Besides driving the car, [those] batteries have two other potentially useful applications: mobile storage via vehicle-to-grid while they are installed in the vehicle, and second-life storage after the vehicle batteries are retired.”

Pricing and demand differentials
The study, prepared by the research firm Strategic Policy Economics, modeled a two-stage scenario calculating the total benefits from both mobile and second-life storage when taking advantage of differences in daytime and nighttime electricity pricing and demand.

If done systematically and at scale, the combined benefits to EV owners, building operators and the electricity system in Ontario could reach $129 million per year by 2035, according to the report. Along with the financial gains, the province would also cut GHG emissions by up to 67.2 kilotons annually.

The math might sound complicated, but the concepts are simple. All it requires is for drivers to charge their batteries with low-cost electricity overnight at home, then plug them into two-way EV charging stations at work and discharge their stored electricity for use by the building by day when buying power from the grid is more expensive.

“Workplace buildings could avoid high daytime prices by purchasing electricity from EVs parked onsite and enjoy savings as a result,” says the report.

Based on average commuting distances, EVs in this scenario could make half their storage capacity available for discharge. Drivers would be paid out of the building’s savings, effectively selling electricity back to the grid and earning up to $8,400 over the life of their vehicle.

According to the report, Ontario could have as many as 18,555 vehicles participating in mobile storage by 2030. At this level, the daily electricity demand would be reduced by 565 MWh. This, in turn, would reduce demand for natural gas-fired electricity generation, a fossil-fuel electricity source, avoiding the expense of gas purchases while reducing GHG emissions.

The second-life storage opportunity begins when the vehicle lifespan ends. “EV batteries will still have over 80% of their storage capacity after being driven for 13 years and providing mobile storage,” the report states. “Those-second life batteries could provide a low-cost energy storage solution for the electricity grid and enhance grid stability over time.”

Some of the savings could be shared with EV owners in the form of a rebate worth up to 20 per cent of the batteries’ initial cost.

Call to action
The report concludes with a call to action for EV advocates to press policy makers and other stakeholders to take actions on building codes, the federal Clean Fuel Standard and other business models in order to maximize the benefits of using EV batteries for the electricity system in this way, even as growing adoption could challenge power grids in some regions.

“EVs are often approached as an environmental solution to climate change,” says Cara Clairman, Plug’n Drive president and CEO. “While this is true, there are significant economic opportunities that are often overlooked.”

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PG&E dividend halt for wildfire mitigation directs cash from shareholders to tree clearing, wildfire risk reduction, and probation compliance under Judge William Alsup, amid bankruptcy, Camp Fire liabilities, and power line vegetation management mandates.

Key Points

A court-ordered dividend halt funding vegetation clearance and wildfire mitigation as PG&E meets probation terms.

✅ Judge Alsup bars dividends until mitigation targets met

✅ 375,000 trees cleared near power lines in high-risk zones

✅ Measures tied to probation amid bankruptcy and liabilities

A U.S. judge said on Tuesday that PG&E may not resume paying dividends and must use the money to fund its plan for cutting down trees to reduce the risk of wildfires in California, stopping short of more costly measures he proposed earlier this year.

The new criminal probation terms for PG&E are modest compared with ones the judge had in mind in January and that PG&E said could have cost upwards of $150 billion.

The terms will, however, keep PG&E under the supervision of Judge William Alsup of the U.S. District Court for the Northern District of California and hold the company, which also is in Chapter 11 bankruptcy and whose bankruptcy plan has drawn support from wildfire victims, to its target for clearing areas around its power lines of some 375,000 trees this year.

PG&E's probation stems from its felony conviction after a deadly 2010 natural gas pipeline blast in San Bruno, California, near San Francisco, that killed eight people and injured 58 others.

PG&E filed for bankruptcy protection on Jan. 29 in anticipation of liabilities from wildfires, including a catastrophic 2018 blaze, the Camp Fire, for which PG&E later pleaded guilty to 85 counts in state court. It killed 86 people in the deadliest and most destructive wildfire in California history.

At a January hearing, Alsup, who is overseeing PG&E's probation, said he felt compelled to propose additional probation terms in the aftermath of Camp Fire. San Francisco-based PG&E expects its equipment will be found to have caused the blaze.

The probation process is separate from San Francisco-based PG&E's bankruptcy filing and from operational measures such as its pandemic response and shutoff moratorium implemented to protect customers.

As the company faces $30 billion in wildfire liabilities and bankruptcy proceedings and has opened a wildfire assistance program for affected residents, the energy company is expected to name as its new chief executive Bill Johnson, a source said on Tuesday. Johnson has been the CEO of the Tennessee Valley Authority since 2013 and is retiring on Friday.

Additional probation terms imposed by Alsup on Tuesday will require PG&E to meet goals in a wildfire mitigation plan it unveiled in February.

The goals include removing 375,000 dead, dying or hazardous trees from areas at high risk of wildfires in 2019, compared with 160,000 last year.

The judge said PG&E will not be able to pay shareholders until it complies with his new probation terms.

Shares fell 2% on Tuesday to close at $17.66 on the New York Stock Exchange and are down 63% since November 2018 due to concerns about the company's bankruptcy and wildfire liabilities, though the utility has said rates are set to stabilize in 2025 as part of its long-term plan. The shares traded as low as $5.07 in January.

PG&E in December 2017 suspended its quarterly cash dividend, while continuing to pay significant property taxes to California counties, citing uncertainty about liabilities from wildfires in October of that year that struck Northern California.

PG&E paid $798 million in dividends in 2017 and $925 million in 2016, a period in which the company did a poor job of clearing areas around its power lines of hazardous trees, according to Alsup.

Money meant for shareholders should have been spent on efforts to reduce wildfire risks in recent years, Alsup said at Tuesday's hearing.

"PG&E has started way more than its share of these fires," Alsup said.

"I want to see the people of California safe," the judge added.

Lawyers for PG&E did not contest the new terms, which the company considers more feasible than terms Alsup proposed in January.

To comply with the terms Alsup proposed in January, PG&E said it would have to remove 100 million trees. The company added that shutting power lines during high winds as Alsup proposed would not be feasible because the lines traverse rural areas to service cities and suburbs.

Idling lines could also affect the power grid in other states, PG&E said.

Alsup on Tuesday said he was still considering his proposal to require PG&E to shut down power lines during windy weather to prevent tree branches from making contact and sparking wildfires linked to power lines in the region.

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