CPV Rogue’s Wind would join the CPV Maple Hill Solar and the CPV Fairview Energy Center projects in Cambria County. The project would consist of 19 Vestas V-162 wind turbines.

CPV Rogue’s Wind is expected to come online in 2026. The project is part of the company’s 10 GW pipeline of renewable and dispatchable generation projects, including utility-scale power generation with carbon capture.

CPV Rogue’s Wind is the first project tied to the company’s recent partnership announcement with investment management firm Harrison Street. The partnership, in which Harrison Street acquired one-third of CPV Renewables, will support an accelerated build out of the 4 GW renewable development pipeline.

It represents the end of an era for the massive coal-fired plant, located near Farmington, New Mexico. The plant, which PNM had operated for decades, provided power for much of the state.

The shutdown of San Juan Unit 4 in September 2022 followed the retirement of Unit 1 in June of that year. The coal-fired plant had four units but was reduced to two in 2017, with the closure of Units 2 and 3. The plant first came online in 1973.

The plant’s retirement sent financial ripples through the surrounding communities. Hundreds of employees were impacted. PNM provided $11 million in severance packages to help about 200 displaced workers. About 240 mine workers received severance payments worth $9 million. Another $3 million went to job training.

PNM is the majority owner of San Juan Generation Station, but the city of Farmington has a 5% stake. The city had aimed to keep the plant open, partnering with Enchant Energy for a carbon capture and sequestration (CCS) project.

The San Juan Solar Project, which would have a capacity of 400 MW, is already on the power plant land and could start operating later this year. PNM approved a 20-year power purchase agreement (PPA) for the solar project.

“When more electricity generation capacity is needed and reserves begin to tighten, a well-designed competitive market sends the appropriate signals to generators to spend capital on both new and existing sources. We received that message loud and clear,” said Caleb Stephenson, Calpine EVP of Commercial Operations.

Over the last decade, Calpine has brought online 1,600 MW of new gas-fired generation within PJM territory. PJM is the largest grid operator in the U.S.

Last month, PJM announced the results of its latest power market auction. The auction produced a price of $269.92/MW-day for most of the PJM footprint, compared to $28.92/MW-day for the 2024/2025 auction. The more than 800% increase expects to have a massive ripple effect across PJM’s 13-state footprint.

Insufficient future transmission planning, the retirement of fossil-fired generation, long interconnection queues and the implementation of FERC market reforms are all contributing to the price hikes.

While Stephenson said the auction results send a build signal to Calpine and other power producers, he said “clarity regarding state-level air emissions regulations is needed for projects to move forward in Pennsylvania.”

After seeing positive market signals in Texas, Calpine began redevelopment efforts in the Lonestar State last year. The company is reportedly on track to add over 1,000 MW of generation to its Texas fleet over the next few years.

“We are increasing staffing and are looking forward to bringing more generation online in PJM as well,” added Stephenson.

TVA has now approved a total of $350 million in nuclear funding for the SMR project. The federal utility approved an initial $200 million at its February 2022 board meeting.

TVA is among the investors in GE Hitachi’s BWRX-300 SMR, a 300 MWe water-cooled, natural circulation reactor with passive safety systems that leverage the design and licensing basis of GEH’s ESBWR boiling water reactor.

The BWRX-300 leverages a unique combination of existing fuel that is currently used in operating reactors (and does not require HALEU), plant simplifications, proven components and a design based on already licensed reactor technology. 

TVA is currently preparing a construction permit application for a BWRX-300 at the Clinch River Site. The utility is also exploring additional sites in the TVA service area for potential SMR deployments.

“We believe advanced nuclear technologies will play a critical role in our region and nation’s drive toward a clean energy future,” said Jeff Lyash, TVA President and CEO. “Small modular reactors are an energy innovation technology that America must dominate – for our energy security, which is really our national security.”

The TVA Board also took action to accelerate the agency’s deployment of clean technologies, including 10,000 MW of solar by 2035. The Board approved TVA’s FY25 budget, which includes a rate increase to support sustained growth and ongoing construction of nearly 3,500 MW of additional generation.

Utilities everywhere are projecting increased demand, and TVA is no exception. According to TVA, the region’s population is growing three times faster than the national average. To address the need for more electricity, TVA is investing nearly $16 billion through FY27 to build new generation and infrastructure and enhance the reliability of existing assets.

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.

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.

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.

Of the 650 MW announced during the second quarter of this year, 600 MW were for data center projects. Earlier this year, Oklo signed a pre-agreement with data center colocation company Equinix to provide up to 500 MW of nuclear power. The company has signed an LOI with Wyoming Hyperscale to deliver 100 MW through its data centers.

Another notable agreement could result in Oklo providing 50 MW of power to oil & gas company Diamondback Energy in the Permian Basin in Texas.

The company is working to convert these LOIs into power purchase agreements toward the end of this year and beginning of next, the company said in recent filings to the SEC.

Oklo is developing next-generation nuclear power plants called “powerhouses.”

The company’s Aurora powerhouse design is a fast neutron reactor that would transport heat from the reactor core to a power conversion system and is designed to run on material from used nuclear fuel known as HALEU, or “high assay, low-enriched uranium.” The reactor builds on the Experimental Breeder Reactor-II and space reactor legacy.

The Aurora powerhouse is designed to scale to 15 MW and 50 MW offerings today. Oklo is also evaluating a 100 MW or larger offering that we’re developing.

“We are targeting 15 and 50 megawatt ranges to start because based on the feedback we’ve seen from our customers, that’s a really great size range to be in to meet their needs,” said Oklo Founder and CEO Jacob DeWitte on this week’s earnings call.

DeWitte said the company can scale up with data center projects, which generally don’t come online all at once.

“We can build up to match where our customers are going as they grow their order book and their demand in a phased way, while also building an extra reactor that is providing power on standby for them when they need it,” he said.

Oklo’s first Aurora powerhouse is targeted for deployment in 2027 at the Idaho National Laboratory (INL). Oklo obtained a site use permit from the U.S. Department of Energy (DOE) for the INL site in 2019. The company applied with the U.S. Nuclear Regulatory Commission (NRC) in March 2020 to build and operate the INL reactor. This was the first combined license application ever accepted by the NRC for an advanced non-light water reactor.

In January 2024, the company announced that DOE had reviewed and approved the Safety Design Strategy (SDS) for its Aurora Fuel Fabrication Facility at INL. The Aurora Fuel Fabrication Facility is being designed to demonstrate the reuse of recovered nuclear material to support the reactor demonstration.

Oklo has also formed a non-binding strategic partnership with Atomic Alchemy, which aims to combine Oklo’s expertise in building and operating fast reactors and fuel recycling with Atomic Alchemy’s expertise in isotope production.

The company plans to build its second and third plants in southern Ohio, on land owned by the Southern Ohio Diversification Initiative (SODI). Earlier this year, Oklo entered into land agreements with SODI, which built on the companies’ initial agreement from May 2023.

The Ohio and Idaho projects are for powerhouses at the 15 MW size. But more recently, there has been more interest in the company’s 50 MW offering, Oklo officials said.