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.

CenterPoint said respondents are encouraged to submit proposals that include utility-scale solar, wind and storage projects (standalone or paired), along with thermal generation, load-modifying resources, demand-side resources and other innovative solutions

“This RFP allows us to explore a wide range of technologies that can contribute to our long-term generation strategy,” said Shane Bradford, CenterPoint’s Vice President for Indiana Electric.

Proposals are due October 8, 2024, the company said.

Last year CenterPoint released its resource plan for Indiana, calling to reduce carbon emissions from its generation fleet by more than 95% over the next 20 years. This would include ending its use of Indiana coal by 2027.

At the time, the company said by 2030, it expected more than 80% of CenterPoint Energy’s electricity to be generated by solar and wind, with the rest provided by natural gas.

The Cambridge Energy Storage Project in Cambridge, Minnesota will deploy Form Energy’s iron-air battery technology, capable of storing energy for up to 100 hours, or several days, the company said.

Form Energy said this is the first commercial deployment of the company’s iron-air battery. The system will be manufactured at the company’s Form Factory 1 in Weirton, West Virginia, and is expected to be operational by late 2025.

Following the project’s completion, Great River Energy plans to conduct a multi-year study to evaluate the system’s performance and potential for broader deployment. 

Iron-air battery technology uses the principle of reversible rusting. The battery cells contain iron and air electrodes and are filled with a water-based, nonflammable electrolyte solution. While discharging, the battery absorbs oxygen from the air and converts iron metal to rust.

While charging, the application of an electrical current converts the rust back to iron and the battery emits oxygen. The technology has lower costs compared to lithium-ion battery production.

Form Energy has several iron-air battery projects underway across the U.S.

One plan is to deploy 10 MW/1,000 MWh systems at two retiring Xcel Energy coal plants: The Sherburne County Generating Station in Becker, Minnesota and the Comanche Generating Station in Pueblo, Colorado.

Form Energy also has an agreement with Georgia Power to deploy a 15 MW/1500 MWh iron-air battery system in Georgia. The multi-day battery system could come online as early as 2026. 

Company co-founder and CEO Mateo Jaramillo appeared on the Factor This! podcast last year, where he discussed the company’s history and its recent efforts to commercialize its 100-hour battery.

Episode 54 of the Factor This! podcast features Form Energy co-founder and CEO Mateo Jaramillo, a former Tesla executive pushing for deep decarbonization on the grid. Subscribe wherever you get your podcasts.

ATLANTA (AP) — Utility regulators on Tuesday approved a plan for Georgia Power Co. to expand a power plant southwest of Atlanta.

The Georgia Public Service Commission voted 5-0 for the unit of Atlanta-based Southern Co. to build three new fossil-fuel burning units at Plant Yates, near Newnan.

The company has declined to say how much it will spend on the plants, which will burn either natural gas or diesel fuel to generate electricity, but commission staff members have said similar recent plants in other states have cost $800 million or more.

The commission greenlighted building the plants in April, when it approved a special plan to add generating capacity because the utility said demand was increasing more rapidly than previous projections, driven in part by a boom in computer data centers locating in Georgia. The company won permission to build the units itself, without seeking outside bids for electrical generation, because its projections show it needs more electricity by the end 2026.

“Simply put, we need to build these units and we need to build them now,” Georgia Power lawyer Steve Hewitson told commissioners Thursday during a committee meeting.

Normally, commissioners approve long-term generating and rate plans for Georgia Power once every three years, but this approval came mid-cycle. Because the regular generating and rate plans will be up for consideration next year, customers will see no change in bills because of Plant Yates until 2026.

Georgia Power customers have seen their bills rise sharply in recent years because of higher natural gas costs, the cost of construction projects, including two new nuclear reactors at Plant Vogtle near Augusta, and other factors. A typical Georgia Power residential customer now pays more than $173 a month, including taxes.

Environmentalists and customer advocates questioned letting Georgia Power build new fossil fuel plants without going through a competitive process. Using those sources would mean Georgia Power emits more climate-altering carbon dioxide than using solar generation, other renewable sources and conservation.

They also argue that it leaves customers more exposed to the risk of rising natural gas costs, which have been a big ingredient in recent bill increases. The units would mostly run on natural gas but would switch to diesel when electrical demand is at peak and more natural gas can’t be purchased or delivered by pipeline.

Curt Thompson, a lawyer representing the Sierra Club and the Southern Alliance for Clean Energy, argued Thursday that Georgia Power should bear some of the risks of rising natural gas costs. In Georgia, the company has been allowed to pass through the entire costs of fuel for its plants, including the combustion turbines it wants to build at Yates.

“The utility industry in general and Georgia Power, in particular, have become increasingly reliant on gas,” Thompson said. “The Yates CTs would only deepen that gas addiction.”

Opponents had again asked the commission to wait until it could examine bids to provide generation, even though commissioners had approved the Yates plan in April.

“Those resources may well be cheaper, cleaner, and a better fit for Georgia Power customers,” Thompson said.

Georgia Power agreed it wouldn’t charge for cost overruns for the turbines unless they are caused by factors outside the company’s “reasonable control.” It’s supposed to submit reports on construction progress every six months.

The assessment focuses on the viability of the council’s 2021 Power Plan resource strategy and finds implementing it — specifically achieving energy efficiency consistent with the high end of the council’s target, pursuing renewable deployment of around 6,600 MW by 2029, and ensuring sufficient balancing resources and demand response — will provide for an adequate system.

That analysis comes with a caveat, however. Pursuing the low end of the council’s energy efficiency target would not provide for an adequate system, and if data center load growth accelerates and more closely aligns with utility projections in the region by 2029, the resource strategy will be insufficient, indicates the report.

The council uses an adequacy model called GENESYS to simulate the region’s bulk power system. In each simulation (which represents one year), a simulated shortfall event occurs over a time period when load cannot be served by resources in the model. Each modeled shortfall signals that emergency measures are necessary to avoid a blackout, like expensive cost resources not in an active utility portfolio, high-priced market purchases above normal import limit (such as those that occurred during January 2024’s winter storm event), calls for conservation by government officials (as in September 2022 California heatwave), or curtailment of fish and wildlife hydro operations (as happened during the 2001 Energy Crisis).

The assessment accounts for system changes that will be implemented by 2029, including load growth, in-region resource developments, and out-of-region market fundamentals. Electric load is expected to substantially increase by 2029, thanks to data centers and electric vehicles. However, announced changes to thermal plant retirements, such as Valmy 1 & 2 and Jim Bridger 1 & 2 conversions from coal to gas fueling, and anticipated transmission expansion throughout the WECC, including Boardman-to-Hemingway in the region, appear to alleviate some of the challenges associated with the increased loads when coupled with the 2021 Plan’s resource strategy.

The Pacific Northwest’s hydroelectric system provides more than half the grid’s nameplate capacity. The region has historically had an excess of peaking capacity but continues to be limited by the water supply that powers the hydroelectric system. Due to significant increases in variable energy resources, changes in hydroelectric operating constraints, and other added complexities, the region can no longer assume that it has sufficient capacity to meet all demand; thus, it is important to include a metric to protect against excessively high-capacity shortfalls, argues the report.

From an adequacy perspective, while hydropower is slightly reduced, based on the limited subset of studies used for a comparative study, the changes do not lead to a significantly different regional adequacy result. Offsetting the reduced hydropower is a small increase in regional thermal generation and market reliance, yet within the market reliance limit, throughout most of the year, especially at night.

The 2021 Power Plan’s resource strategy recommends that between 750 and 1,000 average MW of cost-effective energy efficiency, at least 3,500 MW of renewable resources, and 720 MW of low-cost and frequently deployable demand response be acquired, as well as increasing balancing up reserve requirements to 6,000 MW to respond to growing short-term uncertainty in variable energy resources (primarily wind and solar) by 2027.

The report acknowledges other changes to the regional power system that are important to consider since the 2027 assessment, including announced thermal retirement changes of coal-to-gas conversion, expanded transmission capacity, and hydro changes from the Resilient Columbia Basin Agreement to the Lower Snake and Lower Columbia projects.

As we’ve reported, OPG is planning to build a total of four SMRs at the Darlington nuclear site and would use GE Hitachi’s BWRX-300 reactor technology. The four units once deployed would produce a total 1,200 MW of electricity.

In its latest filings, the provincial utility said it completed early-phase site preparation work for the first SMR and site clearing activities for the three planned additional SMRs in March 2024. Now, the project has commenced main site preparation activities.

OPG said the project completed the tunnel boring machine launch shaft retaining wall for the condenser cooling water system in June 2024. The company has now begun to drill for the reactor building shaft retaining wall. OPG is also planning for the procurement of long-lead items such as the fabrication of the reactor pressure vessel (RPV).

In October 2022, OPG submitted the License to Construct application to the Canadian Nuclear Safety Commission (CNSC) for the first SMR. In April 2024, Canadian regulators announced that the existing environmental assessment for the project is applicable to the BWRX-300 technology. The CNSC will hold a two-part second public hearing in October 2024 and January 2025 to consider OPG’s application.

Darlington refurbishment update

OPG also provided updates on the Darlington Refurbishment project, which began in 2016 to extend the lives of the station’s four units by at least 30 years. Refurbishment of Unit 2 was completed in June 2020, with Unit 3 completed in July 2023.

Work on Unit 1 began February 2022. In April 2024, OPG completed the lower feeder installation series and the lower body supports installation series for the Unit 1 refurbishment, signaling the end of reassembly. The loading of new fuel into the reactor was completed in May 2024.

The project is currently working to restore the reactor vault, which includes removing the bulkheads to reconnect Unit 1 back to the operating units. Vault restoration is on track for completion in August 2024. OPG said this would represent the completion of construction work and transition of the unit to start-up activities.

OPG said Unit 1 is expected to be returned to service by late 2024, ahead of its original schedule set for the second quarter of 2025.

Unit 4 refurbishment activities are currently in disassembly. The removal of the fuel channel assemblies is expected finished in the third quarter of 2024 with the removal of pressure tubes and calandria tubes. Refurbishment of Unit 4 is scheduled to be complete by the end of 2026.

OPG said the refurbishments of Units 1 and 4 incorporate the learnings from Units 2 and 3. The utility said it continues to assess the impact of the COVID-19 pandemic on the project’s total cost, which is tracking toward its $12.8 billion budget.

In May 2024, OPG applied to renew the operating license for the Darlington GS for a period of 30 years beyond November 2025. The two-part public hearing is scheduled to be held by the CNSC in March 2025 and June 2025.

Vineyard Wind said it has obtained federal approval to resume construction of the wind farm – work that was suspended following the partial collapse of a previously installed turbine blade on July 13.

A press release issued at 7 a.m. Tuesday morning said the Bureau of Safety and Environmental Enforcement had given the developers of the wind farm permission to resume the installation of towers and nacelles (which sit atop the tower and convert wind energy into electricity), but a suspension remains in effect for turbine blades and power generation.

Vineyard Wind is a 62-turbine project and only 24 had been completed at the time of the accident. Work is resuming on the remaining 38 turbines but blades cannot be installed nor power produced under the terms of the revised suspension order. Of the 24 completed turbines, 11 were generating electricity at the time of the incident and 13, including the one that broke, were undergoing testing.

In a joint press release, Vineyard Wind and GE Vernova, the manufacturer of the wind turbines, said a barge departed the New Bedford Marine Commerce Terminal Tuesday morning for the wind farm carrying turbine components, including several tower sections and one nacelle.

“The vessel will also carry a rack of three blades solely for the purpose of ensuring safe and balanced composition for the transport,” the press release said, adding that the blades will not be installed and will be returned to New Bedford later in the week.  

The press release said the Bureau of Safety and Environmental Enforcement revised its suspension order after examining records and a structural load analysis conducted by a third party. The federal agency had no mention of a revised suspension order on its website Tuesday morning.

Vineyard Wind and GE Vernova also said “a substantial amount” of what remained of the damaged blade was cut away on Sunday and Monday.

“During the operations, Vineyard Wind and GE Vernova mobilized maritime crews on multiple vessels nearby to secure as much debris as possible for immediate containment and removal as well as land-based crews managing debris recovery,” the press release said. ”Vineyard Wind and GE Vernova are currently assessing next steps to complete any additional cutting necessary at the earliest opportunity, secure and remove the debris on the turbine platform, remove the blade root, and address the debris on the seabed.”

The blade incident at Vineyard Wind, a joint venture of Avangrid and Vineyard Offshore, has been a major setback for the first industrial scale wind farm in the United States. Foam and fiberglass from the turbine has washed up on Nantucket and other beaches on the Cape and Martha’s Vineyard and raised questions about wind energy at a time when the industry is trying to ramp up production.

A preliminary investigation by GE Vernova has suggested the blade breakdown was caused by a “manufacturing deviation” – specifically insufficient bonding of the blade materials. The company has indicated no problems with the design of the Haliade-X blade, which is 853 feet tall.

It was unclear when Nantucket officials were notified about the resumption of construction of the wind farm. Updates posted on the town website indicated the Select Board was aware of the efforts beginning on Sunday to remove more of the damaged turbine blade.

During an executive session on Thursday, the Select Board met to discuss “strategy with respect to potential litigation in connection with Vineyard Wind,” according to the agenda.

This article first appeared on CommonWealth Beacon and is republished here under a Creative Commons license.

Callisto I is a 200 MW/400 MWh battery energy storage system located in central Houston, ten miles from the Houston Ship Channel at the site of a former HL&P H.O. Clarke fossil-fired power plant.

The site can accommodate an additional 400 MW/800 MWh of battery energy storage generation, Jupiter Power officials said.

Jupiter Power is a developer, owner and operator of standalone, grid-connected battery storage projects. Callisto I is Jupiter’s ninth project in ERCOT, bringing its total ERCOT fleet to 1,375 MWh. In December of 2023, Jupiter Power announced the closing of a $65.2 million financing with First Citizens Bank to finance the construction of Callisto I.  

Jupiter Power said Callisto I significantly increases Houston’s supply of reliable, zero emissions power as it faces record demand increases. This growth and recent extreme weather events in Texas has led to efforts by state lawmakers to incentivize adding more dispatchable power to the ERCOT grid. 

That’s according to the latest reporting from the U.S. Energy Information Administration (EIA). For perspective, the 40.4 GW of generating capacity added in 2023 was the most in a year since 2003.

EIA said 20.2 GW came online during the first half of 2024, 3.6 GW (or 21%) more than the capacity added during the first six months of 2023.

Solar continued to lead all U.S. generating capacity additions in the first half of 2024, representing 12 GW (or 59% of all additions). Texas and Florida made up 38% of U.S. solar additions. The largest new projects included the 690 MW solar and storage Gemini facility in Nevada and the 653 MW Lumina Solar Project in Texas.

Nearly 60% of the planned capacity (25 GW) for the second half of 2024 is from solar. If this planned capacity comes online, solar additions will total 37 GW in 2024, a record in any one year and almost double last year’s 18.8 GW.

Battery storage made up the second-most capacity added so far this year, according to EIA. Battery additions made up 21% of new additions and were concentrated in four states: California, Texas, Arizona and Nevada.

10.8 GW of battery storage is planned for the latter half of 2024. If it all comes online, the 2024 total (15 GW) would be a record. Plans for storage capacity in Texas and California currently account for 81% of new battery storage capacity in the second half.

Wind power made up 12% (2.5 GW) of U.S. capacity additions. Canyon Wind (309 MW) and Goodnight (266 MW), both located in Texas, were the largest wind projects that came online in the first half of 2024.

Nuclear power also increased in the U.S. during the first half of 2024, with Vogtle Unit 4 in Georgia coming online in April.

Retirements slow

Retirements of U.S. electric generating capacity has slowed so far in 2024. Operators retired 5.1 GW of generating capacity in the first half of the year, compared to 9.2 GW retired during the same period in 2023.

Natural gas units represented more than half (53%) of the capacity retired in in the first half of 2024, followed by coal (41%).

According to EIA, about 2.4 GW of capacity is scheduled to retire during the second half, including 700 MW of coal and 1.1 GW of natural gas.

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.