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.

Georgia Power is celebrating Generation Appreciation Month, a time to recognize the more than 1,100 team members who “work tirelessly in power plants across state to keep reliable energy flowing to the grid on hot summer days, cold winter mornings and every hour in between.”

“In life, as well as with Georgia Power’s power generation facilities, there is no one-size-fits-all option,” said Rick Anderson, senior vice president and senior production officer for Georgia Power. “From the existing facilities that have powered Georgia for decades, to newer sources of generation such as renewable energy, cleaner natural gas and battery storage, Georgia Power’s diverse generation mix continues to evolve to meet the needs of a growing Georgia. To keep the energy flowing, we need a workforce that is just as advanced and diverse.”

Based on available opportunities, a career in power generation offers many possibilities for those who join the team, Georgia Power said. Career paths exist in the areas of operations, maintenance, electrical, instrumentation, engineering and more. Last year, the company hired over 80 team members across generation facilities and expects the hiring trend to continue in the coming years. Strong training programs exist in Operations, along with apprenticeships in Mechanical and Electrical, which develop experienced journeymen who work safely to keep energy flowing to the grid, 24/7.

Georgia Power also highlighted the “continuous learning” it offers, including the Rockmart training facility where electrical, mechanical, and instrumentation and control technicians hone their skills each year. In 2023, this facility conducted nearly 3,000 hours of both hands-on and classroom instruction. Subject matter experts from both Southern Company and external entities visited to assist in this training program.

The U.S. Department of Energy (DOE) conducted supply chain “deep dives” on renewable energy technologies, including hydropower and large power transformers. Since the deep dives were published, the Water Power Technologies Office (WPTO) has focused on improving its understanding of the hydropower supply chain and developing strategies for addressing supply chain challenges. The report, Hydropower Supply Chain Gap Analysis, was prepared by NREL for DOE and WPTO.

Because the challenges outlined in the deep dives are most acute for large systems greater than 100 MW, NREL’s report focuses on large systems but expects that its recommendations will improve the supply chain for all hydro systems regardless of scale. Additionally, since the federal government owns almost 50% of the nameplate capacity for conventional hydropower systems with 40% (18 GW) of these units being at least 100 MW, the federal fleet is used to prime the development of the supply chain for the rest of the industry, NREL said.

State of the supply chain

The analysis focused on the upstream and midstream sectors of the hydropower supply chain, as they have “limited” domestic capacity, NREL said.

Upstream supply chain components include raw material extraction, concentration, and processing into engineered materials. The U.S. has strong iron mining and steel production capabilities, NREL said, but it has limited to no mining of the trace metals used in steel, and it imports more than 40% of its copper. Additionally, there are only two domestic facilities with forging capabilities for large hydropower shafts (50-75 tons) and a single domestic foundry that can cast large turbine runners greater than 10 tons.

In the midstream supply chain, the first stage is composed of the manufacture and assembly of hydropower components like hydrogenerators and turbines. Some U.S. companies manufacture components, but international competition is “intense,” NREL said, and acquiring components for 100-MW or larger systems is difficult to procure domestically — only one foundry is capable of producing castings greater than 10 tons, and no domestic manufacturers exist for hydrogenerators greater than 20 MW.

Gap analysis

Five “major” gaps in the domestic hydropower supply chain were identified in the report.

1. Unpredictable and variable demand signals

The development of a domestic hydropower supply chain is held back by an unpredictable and highly variable demand for materials and components, NREL said. Hydropower systems typically have long lives, so replacements and refurbishment schedules have cycles that last years or decades.

2. ‘Severely’ limited or nonexistent domestic suppliers for hydropower
materials and components

There are no domestic facilities for hydrogenerator manufacturing greater than 20 MW, and a single facility for less than 20 MW.

The following materials and components only have a single domestic facility or supplier:

• Windings greater than 100 MW for large hydrogenerators
• Large forgings (50-75 tons) for large hydropower shafts
• Foundry with casting capabilities greater than 10 tons for large turbine runners
• Grain oriented-electric steel (GOES) for U.S. transformer manufacturers

Additionally, there are two domestic suppliers of non-oriented electric steel (NOES) for U.S. hydrogenerator manufacturers

3. Federal contracting procedures and domestic content laws

The report identified several procurement regulators and/or general practices that NREL says inhibit the development of the domestic hydropower supply chain, including bonding requirements, specifying pre-contract design work, all-inclusive contracts, and focusing exclusively on the initial capital outlay rather than the total project life cycle cost.

4. Foreign competition, foreign subsidies, and ‘ineffective’ trade policies

NREL said discussions with companies in the hydropower industry highlighted “inequitable” competition from foreign companies and “ineffective” trade policies as other issues in the hydropower supply chain.

Several companies noted that other countries subsidize their steel industries, and China develops “pods” of manufacturing capability to shorten the supply chain, making it more cost-effective.

5. Shortage of skilled workers

Hydropower manufacturing and upstream support industries suffer from a “significant” lack of workers with appropriate expertise, the report said. These industries have been offshored over the last 40 years, leaving skilled workers to retire or move to other industries.

NREL’s recommendations

NREL said DOE and the WPTO should consider the following recommendations to address hydropower supply chain concerns:

Lead with the federal fleet to prime the development of an aggregated, consistent demand signal with the largest producers by examining federal procurement processes and developing best practices for the refurbishment of the domestic fleet. Improve federal procurement processes to include multi-entity or multi-project long-term contracts and ensure that small businesses can compete for federal contracts. Develop best practices for refurbishments to ensure a predictable, steady, demand.

Develop domestic supply chain and end-user datasets to increase awareness of current and expanding capabilities of the domestic supply chain and installed hydropower fleet. WPTO is funding the development of two databases at Oak Ridge National Laboratory: a comprehensive database of suppliers in the hydropower supply chain, and an expansion of the HydroSource tool to provide unit and component-level information on the existing domestic fleet.

Work with other low-carbon technologies to create a “significant,” steady, and predictable demand signal for common materials.

Continue workforce development, including continuing collegiate competitions like the Hydropower Collegiate Competition and Marine Energy Collegiate Competition; in addition to acting on recommendations from the Hydropower Workforce report.

Originally published in Hydro Review.