“Sticker shock” a concern in nuclear power

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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Germany Solar Cap Removal would accelerate photovoltaics, storage, and renewables, replacing coal and nuclear during phaseout with 10GW per year toward 162GW by 2030, boosting grid resilience, O&M jobs, and domestic clean energy growth.

Key Points

A policy change to scrap the 52GW limit, enabling 10GW/year PV and storage to replace coal and nuclear capacity.

✅ Scrap 52GW cap to prevent post-2020 market slump

✅ Add 10GW PV annually; scale residential, commercial, grid storage

✅ Create jobs in planning, installation, and O&M through 2030

The German Solar Association (BSW) has called on the government to remove barriers to the development of new solar power capacity in Germany and storage capacity needed to replace coal and nuclear generation that is being phased out.

A 52GW cap should be scrapped, otherwise there is a risk that a market slump will occur in the solar industry after 2020, BSW said, especially as U.S. solar expansion plans signal accelerating global demand.

BSW managing director Carsten Körnig said: “Time is running out, and further delays are irresponsible. The 52GW mark will already be reached within a few months.”
A new report from BSW, in cooperation with Bonn-based marketing and social research company EuPD Research and The smarter E Europe initiative, said 10GW a year is needed as well as an increase in battery storage capacity.

This would lead to cumulative photovoltaic capacity of 162GW and 15GW residential, commercial and grid storage systems by 2030, in line with global renewable records being set, leading to new job opportunities.

The number of jobs in the domestic photovoltaic and storage industries could increase to 78,000 by the end of the next decade from today’s level of 26,400, aligning with forecasts of wind and solar reaching 50% by mid-century, said 'The Energy Transition in the Context of the Nuclear and Coal Phaseout – Perspectives in the Electricity Market to 2040' study.

Job growth would take place for the most part in the fields of planning, installation and operations and maintenance of PV systems, as solar uptake in Poland increases, the report said.

In maintenance alone, employment would increase from 9,200 to 26,000, with additional opened up by tapping into the market potential of medium- to long-term storage systems, alongside changing electricity prices in Northern Europe that favor flexibility, it said.

The report added that industry revenue could grow from €5bn to €12.5bn in the coming decade.

The report was supported by BayWa Re E3/DC, Fronius, Goldbeck Solar, IBC Solar, Panasonic, Sharp, Siemens, Sonnen, Suntech, Tesvolt and Varta.

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Maple Ridge Lithium-Ion Battery Plant will be a $1B E-One Moli clean-tech facility in Canada, manufacturing high-performance cells for tools and devices, with federal and provincial funding, creating 450 jobs and boosting battery supply chains.

Key Points

A $1B E-One Moli facility in B.C. producing lithium-ion cells, backed by federal and provincial funding.

✅ $204.5M federal and up to $80M B.C. support committed

✅ E-One Moli to create 450 skilled jobs in Maple Ridge

✅ High-performance cells for tools, medical devices, and equipment

A lithium-ion battery cell production plant costing more than $1 billion will be built in Maple Ridge, B.C., Prime Minister Justin Trudeau and Premier David Eby jointly announced on Tuesday.

Trudeau and Eby say the new E-One Moli facility will bolster Canada's role as a global leader in clean technology, as recent investments in Quebec's EV battery assembly illustrate today.

It will be the largest factory in Canada to manufacture such high-performance batteries, Trudeau said during the announcement, amid other developments such as a new plant in the Niagara Region supporting EV growth.

The B.C. government will contribute up to $80 million, while the federal government plans to contribute up to $204.5 million to the project. E-One Moli and private sources will supply the rest of the funding. 

Trudeau said B.C. has long been known for its innovation in the clean-technology sector, and securing the clean battery manufacturing project, alongside Northvolt's project near Montreal, will build on that expertise.

"The world is looking to Canada. When we support projects like E-One Moli's new facility in Maple Ridge, we bolster Canada's role as a global clean-tech leader, create good jobs and help keep our air clean," he said.

"This is the future we are building together, every single day. Climate policy is economic policy."

Nelson Chang, chairman of E-One Moli Energy, said the company has always been committed to innovation and creativity as creator of the world's first commercialized lithium-metal battery.

E-One Moli has been operating a plant in Maple Ridge since 1990. Its parent company, Taiwan Cement Corp., is based in Taiwan.

"We believe that human freedom is a chance for us to do good for others and appreciate life's fleeing nature, to leave a positive impact on the world," Chang said.

"We believe that [carbon dioxide] reduction is absolutely the key to success for all future businesses," he said.

The new plant will produce high-performance lithium-cell batteries found in numerous products, including vacuums, medical devices, and power and gardening tools, aligning with B.C.'s grid development and job plans already underway, and is expected to create 450 jobs, making E-One Moli the largest private-sector employer in Maple Ridge.

Eby said every industry needs to find ways to reduce their carbon footprint to ensure they have a prosperous future and every province should do the same, with resource plays like Alberta's lithium supporting the EV supply chain today.

It's the responsible thing to do given the record wildfires, extreme heat, and atmospheric rivers that caused catastrophic flooding in B.C., he said, with large-scale battery storage in southwestern Ontario helping grid reliability.

"We know that this is what we have to do. The people who suggest that we have to accept that as the future and stop taking action are simply wrong."

Trudeau, Eby and Chang toured the existing plant in Maple Ridge, east of Vancouver, before making the announcement.

The prime minister wove his way around several machines and apologized to technicians about the commotion his visit was creating.

The Canadian Taxpayers Federation criticized the federal and B.C. governments for the announcement, saying in a statement the multimillion-dollar handout to the battery firm will cost taxpayers hundreds of thousands of dollars for each job.

Federation director Franco Terrazzano said the Trudeau government has recently given "buckets of cash" to corporations such as Volkswagen, Stellantis, the Ford Motor Company and Northvolt.

"Instead of raising taxes on ordinary Canadians and handing out corporate welfare, governments should be cutting red tape and taxes to grow the economy," said Terrazzano. 

Construction is expected to start next June, as EV assembly deals put Canada in the race, and the company plans for the facility to be fully operational in 2028.

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SaskPower Rate Hike 2022-2023 signals higher electricity rates in Saskatchewan as natural gas costs surge; the Rate Review Panel approved increases, affecting residential utility bills amid affordability concerns and government energy policy shifts.

Key Points

An 8% SaskPower electricity rate increase split 4% in Sept 2022 and 4% in Apr 2023, driven by natural gas costs.

✅ 4% increase Sept 1, 2022; +4% on Apr 1, 2023

✅ Panel-approved amid natural gas price surge and higher fuel costs

✅ Avg residential bill up about $5 per step; affordability concerns

The NDP Opposition is condemning the provincial government’s decision to approve the Saskatchewan Rate Review Panel’s recommendation to increase SaskPower’s rates for the first time since 2018, despite a recent 10% rebate pledge by the Sask. Party.

The Crown electrical utility’s rates will increase four per cent this fall, and another four per cent in 2023, a trajectory comparable to BC Hydro increases over two years. According to a government news release issued Thursday, the new rates will result in an average increase of approximately $5 on residential customers’ bills starting on Sept. 1, 2022, and an additional $5 on April 1, 2023.

“The decision to increase rates is not taken lightly and came after a thorough review by the independent Saskatchewan Rate Review Panel,” Minister Responsible for SaskPower Don Morgan said in a news release, amid Nova Scotia’s 14% hike this year. “World events have caused a significant rise in the price of natural gas, and with 42 per cent of Saskatchewan’s electricity coming from natural gas-fueled facilities, SaskPower requires additional revenue to maintain reliable operations.”

But NDP SaskPower critic Aleana Young says the rate hike is coming just as businesses and industries are struggling in an “affordability crisis,” even as Manitoba Hydro scales back a planned increase next year.

She called the announcement of an eight per cent increase in power bills on a summer day before the long weekend “a cowardly move” by the premier and his cabinet, amid comparable changes such as Manitoba’s 2.5% annual hikes now proposed.

“Not to mention the Sask. Party plans to hike natural gas rates by 17% just days from now,” said Young in a news release issued Friday, as Manitoba rate hearings get underway nearby. “If Scott Moe thinks his choices — to not provide Saskatchewan families any affordability relief, to hike taxes and fees, then compound those costs with utility rate hikes — are defensible, he should have the courage to get out of his closed-door meetings and explain himself to the people of this province.”

The province noted natural gas is the largest generation source in SaskPower’s fleet. As federal regulations require the elimination of conventional coal generation in Canada by 2030, SaskPower’s reliance on natural gas generation is expected to grow, with experts in Alberta warning of soaring gas and power prices in the region. Fuel and Purchased Power expense increases are largely driven by increased natural gas prices, and SaskPower’s fuel and purchased power expense is expected to increase from $715 million in 2020-21 to $1.069 billion in 2023-24. This represents a 50 per cent increase in fuel and purchased power expense over three years.

“In the four years since our last increase SaskPower has worked to find internal efficiencies, but at this time we require additional funding to continue to provide reliable and sustainable power,” SaskPower president & CEO Rupen Pandya said in the release “We will continue to be transparent about our rate strategy and the need for regular, moderate increases.”

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Hydro One CEO Pay Cap sets executive compensation at $1.5 million under Ontario's provincial directive, linking incentives to transmission and distribution cost reductions, governance improvements, and board pay limits at the electricity utility.

Key Points

The Hydro One CEO Pay Cap limits pay to $1.5M, linking incentives to cost reductions and defined targets.

✅ Base salary set at $500,000 per year.

✅ Incentives capped at $1,000,000, tied to cost cuts.

✅ Board pay capped: chair $120,000; members $80,000.

Hydro One has agreed to cap the annual compensation of its chief executive at $1.5 million, the provincial utility said Friday, acquiescing to the demands of the Progressive Conservative government.

The CEO's base salary will be set at $500,000 per year, while short-term and long-term incentives are limited to $1 million. Performance targets under the pay plan will include the CEO's contributions to reductions in transmission and distribution costs, even as Hydro One has pursued a bill redesign to clarify charges for customers.

The framework represents a notable political victory for Premier Doug Ford, who vowed to fire Hydro One's CEO and board during the campaign and promised to reduce the annual earnings of Hydro One's board members.

In February, the province issued a directive to the board, ordering it to pay the utility's CEO no more than the $1.5 million figure it has now agreed to, as part of a broader push to lower electricity rates across Ontario.

Hydro One and the government had been at loggerheads over executive compensation, with the company refusing repeated requests to slash the CEO pay below $2,775,000. The board argued it would have difficulty recruiting suitable leaders for anything less, even as customers contend with a recovery rate that could raise hydro bills.

Further, the company agreed to pay the board chair no more than $120,000 annually and board members no more than $80,000 — figures Energy Minister Greg Rickford had outlined in his directive last month, amid calls for cleaning up Ontario's hydro mess from policy commentators.

"Hydro One's compliance with this directive allows us to move forward as a province. It sets the company on the right course for the future, proving that it can operate as a top-class electricity utility while reining in executive compensation and increasing public transparency," Rickford said in a statement issued Friday morning.

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Enbridge Alberta CCS Project targets carbon capture and storage in Alberta, capturing emissions from industrial emitters to advance net-zero goals, leveraging carbon pricing, regulatory support, and a hub model despite a key partner's exit.

Key Points

A proposed Alberta carbon capture hub by Enbridge to store industrial emissions and support net-zero targets.

✅ Seeks emitters across power, oil and gas, and heavy industry

✅ Backed by carbon pricing, regulation, and net-zero mandates

✅ Faces high capex, storage risk, and anchor-tenant uncertainty

Enbridge Inc., a Canadian energy giant, is digging its heels in on its proposed carbon capture and storage (CCS) project in Alberta. This comes despite the recent withdrawal of Capital Power, a major potential emitter that was expected to utilize the CCS technology. Enbridge maintains the project remains viable, but questions linger about its future viability without a cornerstone anchor.

The CCS project, envisioned as a major carbon capture hub in Alberta, aimed to capture emissions from industrial facilities and permanently store them underground. This technology has the potential to play a significant role in reducing greenhouse gas emissions and mitigating the effects of climate change, alongside grid solutions like bridging the Alberta-B.C. electricity gap that can complement decarbonization efforts.

Capital Power's decision to shelve its $2.4 billion Genesee Generating Station project, which was designed to integrate with the CCS hub, threw a wrench into Enbridge's plans. The Genesee project was expected to be a key source of emissions for capture and storage, and its status is being weighed as Ottawa advances the federal coal plan to phase out unabated coal.

Enbridge, however, remains optimistic. The company cites ongoing discussions with other potential emitters interested in utilizing the CCS technology, amid new funding signals such as the U.S. DOE's $110M for CCUS that highlight momentum. They believe the project holds significant value despite Capital Power's departure.

"We are confident in the long-term viability of the project and continue to actively engage with potential customers," said Enbridge spokesperson Rachel Giroux. "Carbon capture and storage is a critical technology for achieving net-zero emissions, and we believe there is a strong business case for our CCS project."

Enbridge's confidence hinges on several factors. Firstly, they believe there is a growing appetite for CCS technology amongst industrial facilities facing increasing pressure to reduce their carbon footprint. Regulations and carbon pricing mechanisms, including new U.S. EPA power plant rules that test CCS readiness, could further incentivize companies to adopt CCS solutions.

Secondly, Enbridge highlights the potential for capturing emissions from not just power plants but also from other industrial sectors like oil and gas production and clean hydrogen projects in Canada, where reforming processes can generate CO2. This broader application could significantly increase the captured carbon volume and strengthen the project's economic viability.

However, skepticism remains. Critics point to the high upfront costs associated with CCS development and the nascent stage of the technology. They argue that without a guaranteed stream of captured emissions, the project might not be financially sound. Additionally, the long-term safety and effectiveness of large-scale carbon storage solutions remain under scrutiny.

The success of Enbridge's CCS project hinges on attracting new emitters. Replacing Capital Power's contribution will be a significant challenge. Enbridge will need to demonstrate the project's economic viability and navigate the complex regulatory landscape surrounding CCS technology.

The Alberta government's position on CCS is crucial. While the government has expressed support for the technology, the level of financial and regulatory incentives offered will significantly impact investor confidence, especially as the IEA net-zero outlook underscores Canada's need for much more electricity. A clear and stable policy framework will be essential for attracting emitters to the project.

The future of Enbridge's CCS project remains uncertain. Capital Power's withdrawal is a setback, but Enbridge's continued commitment suggests they believe the technology holds promise. Whether they can find enough emitters to justify the project's development will be a critical test. The outcome will have significant implications for the future of CCS technology in Alberta and Canada's broader efforts to achieve net-zero emissions, including Canada-Germany clean energy cooperation that seeks to scale low-carbon fuels.

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