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.

The funding would support technologies that capture CO2 from industrial and power generation or directly from the atmosphere and transport it either for permanent geologic storage or conversion into valuable products such as fuels and chemicals.

The sixth opening of FECM’s Carbon Management funding opportunity announcement (FOA) will support the following areas of interest:

• Reactive carbon capture approaches for point source capture or atmospheric capture with integrated conversion to useful products. Reactive carbon capture is the integration of carbon capture with conversion to a product. This area of interest would focus on conceptual design studies followed by laboratory validation of reactive CO2 capture approaches from exhaust flue gas streams at electric generation and industrial facilities or from the atmosphere, with conversion of the CO2 into environmentally responsible and economically valuable products.
   
• Engineering-scale testing of transformational carbon capture technologies for natural gas combined cycle (NGCC) power plants. Testing under real flue gas conditions aims to achieve 95 percent or greater carbon capture efficiency and 95 percent CO2 purity, while demonstrating significant progress toward a 30 percent reduction in the cost of capture.
   
• Engineering-scale testing of transformational carbon capture technologies in portable systems at industrial plants. Development and testing of portable systems for transformational technologies would be conducted at a variety of sites, including oil refineries and petrochemical, cement and lime, pulp, steel and iron, and glass plants.
   
• Preliminary front-end engineering design (Pre-FEED) studies for carbon capture systems at existing (retrofit) domestic NGCC power plants. Pre-FEED studies of commercial-scale, advanced carbon capture systems at existing NGCC power plants or combined heat and power facilities that employ NGCC power generation.
   
• Pre-FEED studies for carbon capture systems at hydrogen production facilities using coal, mixed coal/biomass or natural gas feedstock. Studies to advance commercial-scale carbon capture systems that separate CO2 with at least 95 percent capture efficiency at new or existing hydrogen production facilities using coal, mixed coal/biomass/municipal solid waste/unrecyclable plastics, or natural gas feedstocks.
   
• Enhancing CO2 transport infrastructure (ECO2 transport): Pre-FEED studies for multimodal CO2 transfer facilities. Studies that support the development of viable and strategically adaptable multimodal transportation infrastructure capable of transferring CO2 across regional and national CO2 transportation networks.

The proposed plants are the EmberYork Energy Center in Austin County and the EmberGreen Energy Center in Wharton County, both located in the Houston area. Both simple-cycle facilities would operate as peaker plants and can ramp up to their full capacity in under 10 minutes, EmberClear said.

The facilities are located near several large interstate natural gas pipelines and over 60 billion cubic feet of storage capacity. The newly constructed Matterhorn pipeline, with a capacity of 2 BCF per day, already connects to both facilities.

EmberClear said it has engaged with Houston-based ConocoPhillips to secure a firm gas supply for both projects, with ConocoPhillips maintaining firm capacity on the Matterhorn Pipeline.

The company is also into advanced discussions with a leading gas turbine manufacturer but did not say which one.

EmberClear applied for the loans through the Texas Energy Fund (TEF), a state government low-interest loan program used to incentivize the development of more dispatchable generation and smaller backup power in the state.

The launch of the loan program was driven by a projected surge in power demand in the ERCOT market.

ERCOT’s power demand is projected to grow from 86 GW to potentially 150 GW by 2030, rapidly outpacing power supply and creating significant challenges for key metropolitan areas.

Both EmberYork and EmberGreen could begin construction by Q1/Q2 2026.

In their respective second-quarter earnings reports, NRG Energy and Vistra discussed potential opportunities for data center co-location.

NRG’s 21 generating sites are “ideally suited for new large loads and power plant development, offering co-location opportunities both behind and in front of the meter,” said NRG President and CEO Larry Coben on the company’s earnings call Thursday.

Coben said NRG’s facilities would be attractive to data center developers for their access to water for cooling, premium fiber channel access for low latency and existing grid access for rapid market entry. NRG’s fleet includes a mix of natural gas, renewables and coal.

“We were getting lots of people sort of throwing us bids for our sites,” Coben told investors.

He continued: “We know they think we’re just a bunch of power guys who don’t know anything about data centers. So, if that’s what they’re bidding us, we really need to look at this, because it means there’s a lot more value in there than the bids that we’re receiving.”

Regarding discussions with data center providers and any potential co-location deals, Coben said NRG was working on a strategy and would release more details later in 2024.

The concept of large loads co-locating with generation continues to draw interest. The most-watched proposal would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in Pennsylvania.

Multiple utilities protested the proposed Talen Interconnection Service Agreement (ISA), prompting FERC to call for a technical conference in the fall to discuss the larger issue of co-location.

For Vistra, the pending Talen case or upcoming FERC technical conference “has not slowed the conversation down” on potential data center co-location deals, said company President and CEO Jim Burke.

“We’re in due diligence for a number of sites,” Burke told investors on the company’s Q2 call. “This is a really big opportunity for our industry to meet customer needs.”

Vistra reiterated the company can provide data centers the speed to market advantage since there wouldn’t be the same level of buildout needed on the transmission side.

“I think there’s going to be plenty of data center load behind-the-meter or co-located, and also front of the meter,” Burke said.

On planning for load growth and building new gas plants

The industry’s rapid load growth is being driven by data centers, electrification and new manufacturing. This is compounded by the retirement of fossil-fired plants. As a result, both NRG and Vistra see emerging supply gaps and tightening markets.

Among the regions expected to experience a surge in demand, ERCOT’s current long-term load forecast shows peak demand increasing from 86 GW in 2024 to 137 GW in 2028. This load growth will require significant planning and construction of new generation and transmission.

While NRG and Vistra operate plants outside of Texas, most of their growth is taking place in the ERCOT market. Both companies are taking advantage of the Texas Energy Fund (TEF), a government low-interest loan program used to incentivize the development of more dispatchable generation and smaller backup power in the state.

NRG has filed TEF loan applications for three separate projects, totaling more than 1,500 MW of capacity. Thee company would begin construction on two of the three facilities as early as October of this year.

One of these projects is a new 689 MW natural gas combined-cycle unit with Mitsubishi Power M501JAC equipment, located at NRG’s Cedar Bayou plant in Baytown, Texas. The target completion date would be late-2027.

The 415 MW simple-cycle unit at TH Wharton would include Siemens Energy’s SGT6-5000F equipment and could come online by mid-2026.

Finally, the 443 MW simple-cycle unit at Greens Bayou would be powered by a GE 7HA.03 turbine and could be finished by mid-2028.

“We believe our projects are well-situated for a timely approval, given their shovel-ready nature and the completeness of the applications that we submitted,” said Coben.

Texas Lt. Gov. Dan Patrick recently said 81 applicants representing over 41 GW of dispatchable power had applied through the fund, as of May 31. Patrick said the state planned on expanding the program during the next legislative session.

Coben told investors NRG could apply for more loan funding in a potential second TEF round, but also noted the challenge of multi-year lead times for turbines and other equipment.

“If you don’t have a place in the turbine queue today, there’s no way you’re getting a new project online before 2030, at the earliest,” he said.

In May, Vistra announced plans to add up to 2,000 MW of natural gas-fired capacity in West, Central and North Texas.

860 MW of simple-cycle peaker plants would support West Texas, including the state’s growing oil and gas industry. The company is seeing multiple demand drivers, including data centers and the electrification of oil field operations, specifically the Permian Basin of West Texas

Vistra would also convert its coal-fired Coleto Creek plant near Goliad to natural gas after the plant retires in 2027. Repowering would enable up to 600 MW of gas-fired capacity.

Also included are 500 MW of augmentations at existing facilities, nearly half of which are already finished, Burke said on the Q2 earnings call.

In its quarterly report, Vistra leadership noted the industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment needed for the construction of renewables projects. As a result, Vistra has deferred some of planned capital spend for these projects, the company said in its 10-Q filing.

The company did announce two long-term power purchase agreements (PPAs) with Amazon and Microsoft for two new large-scale solar facilities.

Supply chain disruptions have also increased the lead times to procure certain materials necessary to maintain Vistra’s natural gas, nuclear and coal fleet, according to the filing.

“We have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages,” the company reported.

In its Q2 report, NRG said procuring mid to long-term generation through PPAs continues to be part of its strategy. The company has entered into renewable PPAs totaling nearly 1.9 GW with third-party developers, all of which were operational as of July 31.

The Cogentrix fleet includes 11 natural gas-fired power plants totaling 5.3 GW located throughout PJM, ERCOT and ISO-NE.

Cogentrix is headquartered in Charlotte, North Carolina and has multiple decades of experience acquiring, developing, constructing, operating and optimizing conventional and renewable power generation assets throughout the U.S. Following transaction close, the company will continue to be led by current CEO John Ragan and the existing Cogentrix management team.

On the 5+ GW buy, Quantum cited rapidly increasing electricity demand due to the growth of data centers and AI, the reshoring of manufacturing and electrification, as well as the retirements of fossil-fired generation.

The transaction is subject to customary regulatory approvals and is expected to close between the fourth quarter of 2024 and the first quarter of 2025.

Guggenheim served as Quantum’s financial advisor while King & Spalding and Vinson & Elkins provided legal advice to Quantum. Lazard served as Carlyle’s financial advisor and Latham & Watkins as legal advisor.