The power station operates two nuclear reactors in Louisa County, Va. Dominion Energy’s Surry Power Station previously received NRC approval in 2021 to extend its operating license through 2053. Combined, Surry and North Anna generate 40% of Virginia’s electricity and account for about 90% of the carbon-free power in the state.

“For more than 50 years, nuclear power has been the most reliable workhorse of our fleet and the largest source of carbon-free power in Virginia,” said Eric Carr, Dominion Energy’s chief nuclear officer. “North Anna operates around the clock and generates the reliable, clean energy that powers our customers’ homes and businesses every day. With this 20-year extension, our customers can continue counting on North Anna for reliable, carbon-free power for another generation to come.”

Dominion Energy said it is conducting numerous upgrades at the station, including replacing the reactors’ main generators and condensers, refurbishing reactor coolant pumps, and converting instrument and control systems from analog to digital. The company is also implementing 80 enhancements to station procedures, such as additional inspections and equipment testing.

The North Anna units were originally licensed to operate for 40 years in 1978 and 1980. Their licenses were renewed for an additional 20 years in 2003, after a federal review process. Under its current licenses, North Anna reactors 1 and 2 could have operated through 2038 and 2040, respectively. With the renewed licenses, the units can operate through 2058 and 2060, respectively. 

Dominion Energy said it plans to seek recovery of the costs associated with the license extension from the Virginia State Corporation Commission later this year.

The nuclear units at North Anna Power Station are both three-loop Westinghouse pressurized water reactors – capable of providing nearly 2,000 MW at peak capacity, or about 17% of the electricity delivered to Dominion Energy Virginia customers.

Dominion Energy’s affiliated companies also plan to seek NRC approval to extend to 80 years the operating licenses of the V.C. Summer Power Station in South Carolina and Millstone Power Station in Connecticut.

Earlier this year, Dominion Energy Virginia issued a Request for Proposals (RFP) from nuclear technology companies to evaluate the feasibility of developing a small modular reactor (SMR) at the North Anna Power Station. While Dominion stressed the RFP is not a commitment to build this SMR, the company said it is an important first step in evaluating the technology and the North Anna site.

Fund V will invest in power and energy infrastructure assets, platforms, and companies, LS Power said.

“Demand for electricity in the United States is growing at the fastest rate in decades, driven by electrification, data center proliferation, and an American manufacturing renaissance.,” Paul Segal, CEO of LS Power, said. “Our portfolio of assets and businesses—which spans generation, transmission, and decarbonization solutions—is designed to ensure the reliability and affordability of electricity while accelerating the energy transition. We look forward to investing this capital to help meet the historic challenges facing the U.S. energy sector.”

Since its inception, LS Power has raised $60 billion in debt and equity capital and developed and acquired more than 47 GW and 160 power generation projects to support North American energy infrastructure. In addition, LS Power Grid has developed 16 transmission projects, including 6 utilities in operation across 5 ISO/RTOs that serve 185 million people. These projects include 780+ miles of high voltage transmission, beyond which LS Power Grid has another 350+ miles in development. 

LS Power said it will leverage its market knowledge, industry network, and in-house expertise to invest Fund V’s capital. To date, Fund V has invested or committed approximately $1.6 billion across renewable and gas-fired generation, renewable fuels, and green hydrogen, with an extensive pipeline of additional opportunities. Recent investments include the announced acquisition of Algonquin Power & Utilities Corp.’s North American renewable energy business, comprised of 3 GW of operating projects and an 8 GW development pipeline spanning 12 states, 4 provinces, and 5 U.S. power markets.

“Over the past thirty years, LS Power has built a platform to meet this moment in the energy transition,” said Darpan Kapadia, Chief Operating Officer of LS Power. “The success of this fundraise is a testament to our team’s deep expertise and strong track record through multiple market cycles. We are grateful to our investors, both new and long-standing, for their partnership.”

Consumers Energy is closing all three coal units of the complex by 2025, 15 years earlier than originally planned. The utility said this closure will mark the company as one of the first U.S. utility providers to eliminate coal burning and is part of its Clean Energy Plan for a carbon-neutral energy grid by 2040.

The Campbell complex is slated to close by June 1, 2025. It is made up of three units that were built in 1962, 1967 and 1980. They are the last of 12 coal-fired units ― including those at the Cobb (Muskegon County), Whiting (Monroe County), Weadock (Bay County), and most recently, Karn (Bay County) plants ― that started closing in 2016.

As with the other plants, Campbell complex employees will be offered other job opportunities with the company. In partnership with community leaders, the site will be redeveloped following its demolition in 2026 or later.

In the meantime, Consumers Energy plans to offer bus tours of the Campbell complex on Sept. 21. People must sign up in advance for scheduled times, which are available on a first-come, first-served basis. The free tours will last about an hour, including an opportunity to go inside.

“We’re excited to give our friends and neighbors the opportunity to look inside Campbell as we make this major energy transition,” said Norm Kapala, Consumers Energy’s vice president of generation operations. “Our Campbell complex and the people who work here have served our state faithfully with reliable energy for generations. We want to provide an opportunity to understand and appreciate that legacy.”

The company purchased and started operating the 1,200 MW natural gas-fired Covert Generating Station in Southwest Michigan’s Van Buren County last year, matching most of the energy that Campbell provides. Consumers Energy continues to develop clean energy projects, including five Michigan wind farms and the Muskegon Solar Energy Center, which is slated to begin operations in 2026.

“We will be busy the next nine months as we continue to operate Campbell right up until it closes. We’re committed to a useful future for this property, but not before we take the time to reflect on the complex’s important work serving Michigan,” Kapala said.

The amount of coal transported in the United States decreased 8% in 2023, continuing a trend in which coal shipments have generally decreased over the past two decades as coal’s share of power generation has declined in the United States. The amount of coal transported to power plants, which are often located far from mines, decreased by more than half, falling from 957 million tons in 2010 to 422 million tons in 2023.

However, the U.S. Energy Information Administration (EIA) expects the decline in coal consumption to reverse this year. In its recently published July update to the Short-Term Energy Outlook, EIA forecast an increase in use of coal to generate electricity in the United States this year, with use dropping back to about 2023 amounts in 2025.

Westinghouse said this development allows better nuclear fuel efficiency, longer times between reactor refuels and lower operating costs.

U.S. pressurized water reactors currently operate on 18-month fuel cycles, and Westinghouse said this new higher burnup fuel will enable reductions in feed batch size, thereby improving fuel cycle economics. This is the first time nuclear fuel batch reloads in the United States will be able to exceed a burnup limit of 62 GWd/MTU.

“We are very pleased to receive approval from the Nuclear Regulatory Commission for incremental burnup in our nuclear fuel,” said Tarik Choho, Westinghouse President of Nuclear Fuel. “This milestone marks the start of production of nuclear fuel with increased capacity for Pressurized Water Reactors, vastly improving fuel costs for U.S. utility customers.”

The incremental burnup approval also represents a milestone for the Encore Accident Tolerant Fuel Program, an initiative started in 2012 and funded by the Department of Energy, aimed at increasing performance and safety of nuclear reactors in support of U.S. energy security and climate goals.

Sage has entered into a land use agreement with San Miguel Electric Cooperative Inc. (SMECI) for the 3 MW Geopressured Geothermal System (GGS) energy storage facility. The 3 MW EarthStore system will be in Christine, Texas near the SMECI lignite coal power plant. Sage will operate as a merchant, buying and selling electricity to the ERCOT grid.

Later this year, Sage will launch the EarthStore facility, which it says will utilize the earth’s “natural capacity for energy storage” to produce dispatchable electricity on demand through a power source that works independent of weather conditions.

“Once operational, our EarthStore facility in Christine will be the first geothermal energy storage system to store potential energy deep in the earth and supply electrons to a power grid,” said Cindy Taff, CEO of Sage Geosystems. “Geothermal energy storage is a viable solution for long-duration storage and an alternative for short-duration lithium-ion batteries. Electric utilities and co-ops like SMECI, will be able to use our technology to complement wind and solar, and stabilize the grid.”

The facility will use Sage’s proprietary technology to store energy, targeting 6-to-10-hour storage durations and delivering a round-trip efficiency (RTE) of 70-75%, Sage said. In addition, water losses are targeted to be less than 2%. At scale, this energy storage system will be paired with renewable energy to provide baseload and dispatchable power to the electric grid. When combined with solar power, Sage’s EarthStore facility enables 24/7 electricity generation at a blended Levelized Cost of Energy (LCOE) well under $0.10/kWh, it said.

“Long-duration energy storage is crucial for the ERCOT utility grid, especially with the increasing integration of intermittent wind and solar power generation,” said Craig Courter, CEO, San Miguel Electric Cooperative. “We are excited to be part of this innovative project that showcases the potential of geothermal energy storage.”

Sage will be applying for two drilling permits in Texas. The first permit is in Atascosa County for the EarthStore facility in Christine and the second permit is in Starr County, adjacent to the company’s existing test well.

Geothermal electricity generation taps high-energy-content steam at temperatures of 300-700 degrees Fahrenheit and requires drilling to depths that are as much as tens of thousands of feet below the surface.

The process works by drilling sets of both injection wells and production wells. Cold water is pumped down the injection well and then flows through the geothermal reservoir to the production well. The water returns to the surface at a high enough temperature for the energy to be captured at the surface and enter an electric generation cycle.

GO DEEPER: Fervo Energy co-founder and CEO Tim Latimer joined the Texas Power Podcast with Doug Lewin to discuss a hoped-for resurgence in the geothermal energy industry. Subscribe wherever you get your podcasts.

Compared to older, traditional geothermal energy sites, it’s much more challenging, and expensive, to find heat resources suitable for electricity generation today. That’s why companies like Fervo Energy and Sage are incorporating techniques from the oil and gas industry to give the geothermal industry new life.

Although Texas doesn’t have any geothermal projects of its own yet, several companies headquartered in Houston, including Fervo Energy and Sage, are hoping to change that. Some former oil and gas industry professionals are now championing geothermal as a new resource for reliability, especially given the crossover between equipment and techniques from the oil drilling industry, the Texas Tribune reports.

Atura Power, a subsidiary of Ontario Power Generation, is expanding the power generation capacity at its 900 MW Napanee Generating Station in the Town of Greater Napanee, Ontario. The planned expansion has a targeted completion by 2028.

Atura Power will add an M501JAC combustion turbine from Mitsubishi Power Americas, that will operate in simple cycle and provide up to 430 MW of additional electricity. Mitsubishi Power Americas said its M501JAC is known for its operational flexibility and startup times, and can also operate as a peaker. The turbine will join two M501GAC units already operating in combined cycle at the site. This will be the fifth Mitsubishi Power M501JAC turbine in Canada.

In 2019, Ontario Power Generation acquired the Napanee Generating Station and two other gas-fired plants in a $2.8 billion deal with TC Energy (formerly known as TransCanada). The facilities included the 683 MW Halton Hills power plant, the 900 MW Napanee generating station which was nearing completion at the time, and TC Energy’s 50% interest in the 550 MW Portlands Energy Center.

The deal was subject to a number of closing conditions which included regulatory approvals and Napanee reaching commercial operations as outlined in the agreement.

Since the end of 2023, 8 Rivers and Siemens Energy have collaborated on development of direct-fired super critical CO₂ turbines across a range of applications and fuel types. 8 Rivers, a developer of decarbonization technology and projects, said the ongoing turbine development program provides line of sight to future commercial projects. 

Siemens Energy has selected the commercially available generator that will be used with the Allam-Fetvedt Cycle (AFC) turbine. Siemens Energy will also provide related equipment, services, compression and grid technologies.

However, 8 Rivers said it has completed a study with a commercial party which assessed the feasibility of a biomass fueled Allam-Fetvedt Cycle negative emissions power system (Biome). This resulted in the recent signing of an MoU with the aim of commercial deployment, the company said.

8 Rivers argues that biome as a power system allows for the generation of low-cost, reliable, negative emissions power while simultaneously generating large volumes of carbon dioxide removal (CDR).  

North Carolina-based 8 Rivers develops zero-carbon technologies such as hydrogen, carbon capture and biomass carbon removal. It jointly owns NET Power, whose Allam-Fetvedt Cycle combusts natural gas with oxygen (rather than air) to fuel a supercritical CO₂ cycle that generates electricity.

The technology reuses most of the carbon dioxide produced and captures the rest, meaning it emits virtually nothing into the atmosphere. NET Power has said its plants should cost no more to build and operate than a traditional natural gas plant.

In 2018, we reported NET Power successfully achieved first fire of its demonstration plant and test facility in La Porte, Texas. At that time, the company had targeted the global deployment of 300 MW capacity commercial-scale plants beginning as early as 2021.

Through the agreement, which kicked off in July, FirstLight will deliver Burlington more than 54 GWh of hydropower and associated VT-1 renewable energy credits through 2025 from FirstLight’s Shepaug Generating Station in Connecticut.

Shepaug is Connecticut’s largest hydroelectric generation station and is also the second largest source of carbon-free electricity in the state, located on the Housatonic River in Newtown and Southbury. Built in 1955, it has a 42.6 MW capacity.

“Our new collaboration with FirstLight serves as another example of Burlington Electric Department’s and the City of Burlington’s commitment to continuing to source 100% of our power from a mix of different types of renewable generation, while maintaining reliability for our customers,” said Darren Springer, BED General Manager.

BED has purchased 100% of its power supply from renewable sources since 2014. As the city transitions away from fossil fuels in the thermal and ground transportation sectors largely through electrification, it expects electricity demand to grow.

To support this increased demand while ensuring its energy mix remains 100% renewable, BED is looking to strategic partnerships like this new PPA with FirstLight to secure additional clean power generation.

“As we electrify more of our heating and transportation needs, BED will continue to look for opportunities to source renewable power to meet demand,” he said.

“We are grateful for thoughtful partners like FirstLight, whose reliable, cost-competitive, clean electricity generation supports our climate goals in Burlington and helps to decarbonize the New England grid.”

FirstLight has a diversified portfolio that includes over 1.65 GW of operating renewable energy and energy storage technologies and a development pipeline with more than 4 GW of solar, battery, hydro, onshore wind and offshore wind projects. FirstLight specializes in hybrid solutions that pair hydroelectric, pumped hydro storage, utility-scale solar, large-scale battery and wind assets. The company’s mission is to accelerate the decarbonization of the electric grid by supporting the development, operation and integration of renewable energy and storage to meet the world’s growing clean energy needs and deliver an electric system that is clean, reliable, affordable and equitable.

Aypa Power intends to develop, own, and operate a 150 MW/600 MWh battery storage facility in Kuna, Idaho just outside the capital of Boise. Aypa’s secured financing package includes a $233 million green loan, including a construction and term loan, a tax equity bridge loan, and a letter of credit facility. Additionally, the project secured $90 million in tax equity, bringing the total financing to $323 million. The company secured a 20-year agreement with Idaho Power last year and hopes to bring it online in 2025.

Renewable Energy World asked Aypa Power to see if the Idaho battery storage project requires any additional state or local approval and is awaiting a response. It’s a natural question for any clean energy project proposed in Idaho given a recent trend of local opposition.

Kuna residents recently came out in force against the 2,385-acre Powers Butte Energy Center solar project developed by Savion, Idaho News 6 reports. The proposed solar farm would be located in a rural farming area, much to the annoyance of the opposition, who say the farm would be a blight on the surrounding area.

Kuna residents attended the second public hearing on the Powers Butte Energy Center project, but Ada County Commissioners did not make a decision on the project’s future. By the end of the month, the Ada County Commission moved to halt on the project, BoiseDev reports, citing public opposition and their own feelings in their decision. Commissioners said the project would come with environmental concerns and unfavorable views.

Ryan Davidson, an Ada County Commissioner, called the decision “tough” and said the board he serves on is “not anti-solar.” He said the commission previously approved a Savion solar project that was developed “out in the desert,” instead of near residents.

It’s not just solar that faces an uphill battle in Idaho: a controversial wind project is facing another obstacle after Sen. Jim Risch introduced legislation to delay the 1,000 MW Lava Ridge Wind project, which is located on federal land near the Minidoka National Historic Site. The project’s opponents claim that the wind farm will “visually compromise” the historic site honoring more than 13,000 Japanese-Americans who were incarcerated during World War II.

Opposition to the Lava Ridge Wind project led the Bureau of Land Management to suggest nearly halving the size of the project from 400 turbines to 241 as part of the “preferred alternative” plan. Idaho’s state legislature unanimously passed a resolution in March 2023 expressing opposition to the Lava Ridge Wind Energy Project.

Based on local reporting, Idaho residents haven’t appeared to have objected to any battery storage project, though Aypa’s would be the state’s first utility-scale facility.

Idaho Power, the investor-owned utility providing electricity to most of the state, sees energy storage serving a key role in the future. Last year, the utility laid out a plan to acquire 101 MW of energy storage to address potential capacity shortfalls driven by limited third-party transmission capacity, load growth, and declining peak performance from several resources, NewsData reports. Some of that load growth will come from a Meta data center that’s expected to be completed in 2025.

While opponents of wind and solar — referred to unaffectionately as “NIMBYs,” an acronym for Not in My Backyard — have successfully fought projects across the country, the majority of Americas don’t mind living near clean energy projects, according to polling data.

A Washington Post-University of Maryland poll found around 75% of Americans are comfortable living near solar projects. Wind projects faired slightly worse at 70%. The poll did not ask about energy storage projects.

Despite broad support for clean energy projects in the U.S., at least 15% of counties have “halted new utility-scale wind, solar, or both,” according to a USA Today report, by implementing “outright bans, moratoriums, construction impediments, and other conditions.”

“We are pleased to announce this important transaction with LS Power, which is the result of a highly competitive strategic sale process,” said Chris Huskilson, CEO of AQN. “This major milestone, coupled with our previously announced agreement to support the sale of our Atlantica shares, delivers on our plan to transform AQN into a pure play regulated utility, optimize our regulated business activities, strengthen our balance sheet, and enhance our quality of earnings. We are confident that our path towards a pure play regulated utility supports our objective to create long term value for our customers and shareholders.”

The sale is subject to the satisfaction of customary closing conditions, including the approval of the U.S. Federal Energy Regulatory Commission and approval under applicable competition laws. The Company expects the transaction to close in the fourth quarter of 2024 or the first quarter of 2025 and to receive estimated cash proceeds of approximately $1.6 billion (excluding the earn out) after repaying construction financing, and net of taxes, transaction fees, and other closing adjustments.

Algonquin Power & Utilities isn’t the only company to shed its utility-scale renewables business lately. Last year, Brookfield Renewable announced it would buy Duke Energy’s utility-scale renewable energy business for $2.8 billion.

Duke began shopping its renewables division in September 2022 as it sought to focus on the growth of its regulated businesses. The sale agreement included more than 3,400 MWac of utility-scale solar, wind, and battery storage across the U.S., net of joint venture partners ownership, in addition to operations, new project development, and current projects under construction.

Also last year, RWE AG finalized its $6.8 billion acquisition of all shares in Con Edison Clean Energy Businesses. The transaction made the newly dubbed RWE Clean Energy one of the five largest renewable energy companies in the U.S. and the country’s second-largest solar owner and operator.

The acquisition included a portfolio of 8 GW of renewable energy projects and a development platform of more than 24 GW. Around 60% of the portfolio is onshore wind and 40% solar. Con Edison said it continues to invest in clean energy transmission projects, building electrification, energy efficiency, electric vehicle infrastructure, battery storage, and other technologies. The utility said it also wants to invest in and operate renewable generation in New York.

Originally published in Renewable Energy World.