A major expansion of battery storage may be the most economical and environmentally beneficial way for Illinois to maintain grid reliability as it phases out fossil fuel generation, a new study finds.

The analysis was commissioned by the nonprofit Clean Grid Alliance and solar organizations as state lawmakers consider proposed incentives for private developers to build battery storage.

“The outlook is not great for bringing on major amounts of new capacity to replace the retiring capacity,” said Mark Pruitt, former head of the Illinois Power Agency and author of the study, which suggests batteries will be a more realistic path forward than a massive buildout of new generation and transmission infrastructure. 

The proposed legislation — SB 3959 and HB 5856 — would require the Illinois Power Agency to procure energy storage capacity for deployment by utilities ComEd and Ameren. Payments would be based on the difference between energy market prices and the costs of charging batteries off-peak, to ensure the storage would be profitable. The need for incentives would theoretically ratchet down over time. 

“As market prices for power go up, your incentive goes down,” Pruit said. “The idea is to provide an incentive that bridges the gap between the cost of battery technology and the value in the market. Over time, those will equalize and level out.” 

The bills, introduced in May at the end of the legislature’s spring session, would amend existing energy law to add energy storage incentives to state policy, along with existing incentives for nuclear and renewables. 

The study noted that Illinois will need at least 8,500 new megawatts of capacity and possibly as much as 15,000 new megawatts between 2030 and 2049, with increased demand driven in part by the growth of data centers. Twenty-five data centers being proposed in Illinois would use as much energy as the state’s five nuclear plants generate, according to nuclear plant owner Exelon’s CEO Calvin Butler Jr., quoted by Bloomberg. 

The North American Electric Reliability Corporation (NERC) found in its summer and winter 2024 assessments that within MISO and PJM regional grids, Wisconsin, Michigan, Minnesota, Illinois and Indiana are all at “elevated” risk of insufficient capacity. 

“NERC, PJM, MISO and the Illinois Commerce Commission have all identified the potential for capacity shortfalls,” said Pruitt. “You do have some options for alleviating that. You can build transmission and bring in capacity from outside the state. You can maintain your current domestic generating capacity [without retiring fossil fuel plants]. You could expand your domestic generating capacity. And an independent variable is your growth rate. All these have to work together, there’s no silver bullet. We know there are major challenges on each of those fronts.” 

Gloomy numbers 

The latest PJM capacity auction results showed capacity prices increasing from $28.92/MW-Day for the 2024/25 period to $269.92/MW-Day — a nearly 10-fold increase — for the following year. That “translates into an annual cost increase of about $350 for a typical single-family household served by ComEd,” Pruitt said. “The increase in costs indicates that more capacity supply is required to meet capacity demand in the future.” 

There are many new generation projects in the queue for interconnection by MISO and PJM, but many of them drop out before ever being deployed because of unviable economics, long delays, regulatory challenges and other issues. A recent study by Lawrence Berkeley National Laboratory noted that while interconnection requests for renewables have skyrocketed since the Inflation Reduction Act, only 15% of interconnected capacity was actually completed in PJM and MISO between 2000 and 2018, and experts say similar completion rates persist. 

“This finding indicates that deploying sufficient new capacity resources to offset [fossil fuel] retirements is not likely to occur in the near term,” said Pruitt. “Just because something is planned doesn’t mean it gets built.” 

Meanwhile the state is running out of funds for the purchase of renewable energy credits (RECs) that are crucial to driving wind and solar development. The 2024 long-term renewable resources procurement plan by the IPA shows the state’s fund for renewables reaching a deficit in 2028, so that spending on RECs from renewables will have to be scaled back by as much as 60%. 

Long-distance transmission lines could bring wind energy or other electricity from out of state. But planned transmission lines have faced hurdles. The Grain Belt Express transmission line, in the works for a decade, was in August denied needed approval from an Illinois appellate court. The transmission line, proposed by Invenergy, would have brought wind power from Kansas to load centers to the east. 

“That sets it back years,” Pruitt said. “Transmission is a very long-term solution. I’m sure people are working diligently on it, but it’s five to 10 years before you get something approved and built.” 

Value proposition, solar benefits 

Pruitt’s study found that if 8,500 MW of energy storage were deployed between 2030 and 2049, Illinois customers could see up to $3 billion in savings compared to if they had to foot the bill for increased capacity without new storage. The savings would come because of lower market prices in capacity auctions, as well as investment in new transmission and generation that would be avoided. 

Pruitt found that $11 billion to $28 billion in macro-level economic benefits could also result, with blackouts avoided, reduced fossil fuel emissions and jobs and economic stimulus created. 

Pruitt’s analysis indicates that the incentives proposed in the legislation would cost $6.4 billion to customers. But the storage would result in $9.4 billion in savings compared to the status quo, hence a $3 billion overall savings between 2030 and 2049. 

“Solar is great, but solar is an intermittent resource; battery storage when paired with solar allows it to be far more reliable,” said Andrew Linhares, Central Region senior manager for the Solar Energy Industry Association. “Battery storage is not as cheap as solar, but its reliability is its hallmark. Combining the resources gives you a cheap and reliable resource.” 

“Solar and storage is this powerful tool that can help reduce costs for consumers and create new jobs and economic activity,” he continued. “I don’t believe that same picture is there for building out new natural gas resources. Anything that helps storage, helps solar and vice versa. CEJA sees these two technologies as being joined at the hip for the future, they are being seen more and more as a single resource.”

This article first appeared on Energy News Network and is republished here under a Creative Commons license.

In Q2 2024, we expected to add about 6.9 GW of storage capacity but ultimately reached just 57% of that target. In the same window in 2023, only about half of the expected facilities came online.

Most of the new batteries- 97% of them, actually- ended up in ERCOT, WECC, and CAISO territories. The Western Electricity Coordinating Council (WECC) which includes the California Independent System Operator (CAISO), is projected to climb to 15.838 GW of battery storage capacity by the end of 2024 and surpass 20 GW in 2025, according to the North American Electricity Long-Term Forecast Supplement. ERCOT is expected to hit 7.2 GW in 2024 and surpass 10 GW in 2025.

According to the data, ERCOT had the most additions in Q2 with 1.4 GW, increasing its total capacity to 7.74 GW, or 32.6% of total US capacity. CAISO is the only grid operator with more, adding 1.388 GW in Q2 to reach 9.867 GW total storage capacity, accounting for 41.5% of total U.S. capacity, per S&P Global Commodity Insights.

S&P expects ISO New England to surpass 1 GW in 2025; New York ISO (NYISO) and the Midcontinent ISO (MISO) are expected to reach that milestone in 2026, followed by PJM Interconnection (PJM) and the SERC Reliability Corporation in 2027.

The top five largest projects added in Q2 were:

• Ørsted’s 300-MW Eleven Mile Solar Center in Arizona, the sixth-largest U.S. BESS
• Plus Power’s 250-MW Sierra Estrella Energy Storage in Arizona
• Calpine Affiliates’ 230-MW Nova Power Phase 1 in California
• Calpine Affiliates’ 230-MW Nova Power Phase 2 in California
• Longroad Energy Holdings’ 215-MW Sun Streams PVS in Arizona

According to S&P Global Commodity Insights, the largest facility is still Florida Power and Light’s 409-MW Manatee Energy Storage Center, which started operations in Q4 2021.

The companies with the most battery energy storage capacity in the U.S. are:

• NextEra Energy Resources with 3.369 GW
• ENGIE North America with 1.561 GW
• Axium Infrastructure with 1.125 GW
• Plus Power with 1.059 GW
• Vistra Energy with 1.023 GW

The states with the most battery energy storage are:

• California with 10.3 GW
• Texas with 7.74 GW
• Arizona with 1.893 MW
• Nevada with 1.125 GW
• Florida with 545 MW

Five states have between 100 and 500 MW, nine states have between 50 MW and 100 MW, and 20 states have less than 50 MW of storage capacity through Q2 2024. 11 states have no battery storage capacity, according to S&P Global Commodity Insights.

Reasons for growth

Lithium prices declined in 2024 and are more stable than a couple of years ago, leading to some certainty in financing battery projects. Platts, part of S&P Global Commodity Insights, assessed lithium carbonate CIF North Asia at $12,000/mt on August 13. That’s down $3,000/mt from the start of 2024 but follows two years of volatility that eventually saw the price collapse from a record of over $78,000/mt in November 2022 to $15,000/mt at the end of 2023.

Sodium-ion alternatives are also starting to gain a foothold, diversifying the battery market. Natron, the only commercial manufacturer of sodium-ion batteries in the United States, recently announced it will invest $1.4 billion to establish a sodium-ion battery giga-factory in Edgecombe County, North Carolina. Natron’s sodium-ion batteries were the first in the world to receive a UL 1973 listing, allowing them to be implemented in the data center, forklift, and electric vehicle (EV) fast-charging markets.

In addition, Commodity Insights notices battery energy storage is often the quickest way to add new capacity; constructing solar and wind generation takes longer and can be trickier considering permitting and labor costs. The decision to add energy storage is often dependent upon the needs of the region.

“The [ISO New England] battery forecast was increased partially to offset the capacity losses from solar and wind,” explains Annie Gutierrez, Commodity Insights senior research analyst. “In regions like ERCOT, data centers are driving increased demand compared to our last outlook which is increasing the need for firm capacity.”

Indeed, ERCOT is efficiently managing record-breaking demand days thanks to a more balanced renewable portfolio that includes more than 8 GW of new solar in the last year and a robust bevy of battery energy storage systems, including Jupiter Power’s new 400 MW BESS in Houston.

However, saturation in the Texas market is becoming an increasingly common topic of conversation among battery players. ERCOT’s connect and manage approach is efficient at getting Distributed Energy Resources online in a timely fashion, but Texas continues to curtail renewable energy sources due to transmission constraints.

Looking ahead to Q3

According to S&P Global Commodity Insights, more than 5 GW of energy storage is expected to come online in the third quarter of this year. If all of it is added (it won’t be, see above), it would represent a more than 20% increase in U.S. capacity quarter over quarter.

Many planned Q3 additions are also in the West and Texas. Less than 325 MW is expected to come online in the Southeast, Midwest, and Northeast.

The five largest Q3 projects to keep an eye on:

• Enel Green Power’s 305.5-MW GulfStar Power in Texas
• Jupiter Power’s 302.9-MW Old Aqueduct in Texas
• Clenera’s 300-MW Atrisco Energy Storage in New Mexico
• UBS Asset Management’s 209.3-MW Citadel BESS in Texas
• ENGIE’s 200.8-MW BRP Paleo BESS

This article was originally published on Renewable Energy World.

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.

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.

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.”

“Battery storage is a key element to building a green economy here in New York, and we have taken comprehensive efforts to ensure the proper safety standards are in place,” Governor Hochul said. “With updating fire codes, we’re ensuring that New York’s clean energy transition is done safely and responsibly.”

Governor Hochul convened the Working Group in 2023 to ensure the safety and security of energy storage systems, following fire incidents at facilities in Jefferson, Orange, and Suffolk Counties. The Working Group was tasked with independently examining energy storage facility fires and safety standards and creating a draft fire code Recommendations Report.

Proposed recommendations include:

• Requiring industry-funded independent peer reviews for all BESS installations exceeding energy capacity thresholds established for lithium-ion batteries;
• Requiring that qualified personnel or representatives with knowledge of the BESS installation are available for dispatch within 15 minutes and able to arrive on scene within four hours to provide support to local emergency responders in the event of a BESS fire.
• Extending safety signage requirements beyond the BESS unit itself to include perimeter fences or security barriers and include a map of the site, BESS enclosures, and associated equipment.
• Removing the fire code exemption for BESS projects owned or operated by electrical utilities to ensure that all projects comply with the fire code.
• Including a requirement that every BESS facility is equipped with an Emergency Response Plan (ERP) and site-specific training to be offered for local fire departments to familiarize them with the project, hazards associated with BESS, and procedures outlined in the ERP.
• Including a fire code requirement in all BESS installations for monitoring of fire detection systems by a central station service alarm system to ensure timely, proper notification to the local fire department in the event of a fire alarm.
• Introducing a new provision in the fire code mandating regular industry-funded special inspections for BESS installations to ensure thorough safety and compliance.

“Lithium-ion batteries and energy storage facilities play a large role in New York’s work toward achieving our clean energy goals,” said Secretary of State Walter T. Mosley. “Governor Hochul recognized the importance of putting the proper safety standards in place for this new, but critical, technology, and this draft language based on recommendations from the Governor’s Working Group will help ensure the safe operation of these facilities into the future.”

15 draft recommendations were proposed by the working group after examining existing FCNYS and other energy storage fire safety standards. The group previously released initial data finding no reported injuries nor harmful levels of toxins detected following fires at battery energy storage systems in Jefferson, Orange, and Suffolk Counties last summer.

The vote green lights Platte River’s recommended “optimal new carbon” portfolio which includes 300 MW of new solar and 460 MW of new wind by 2030. The utility would also add 200 MW of thermal generation in the form of aeroderivative gas turbines by 2028, according to filings presented to the board.

“While some community members question the need for new gas turbines, every portfolio we’ve modeled that meets the requirements of our three foundational pillars adds renewable resources and aeroderivative units,” says Jason Frisbie, general manager and CEO of Platte River.

While PRPA considered five different portfolios, the company said the optimal new carbon plan
“balances cost, reliability and carbon considerations.”

Platte River Power Authority is the utility serving Estes Park, Fort Collins, Longmont and Loveland – communities in Northern Colorado.

In 2020, PRPA had filed an IRP which included the goal of being carbon-free by 2030. However, the utility said supply chain and inflationary pressures caused by the COVID-19 pandemic prompted changes to the plan.

Platte River said the 2024 IRP captures these developments, while reaffirming the need for dispatchable capacity to support a highly renewable energy portfolio.

Platte River said it plans to follow a three-pronged approach to dispatchable capacity:

• Implementing both short and long-duration energy storage when commercially viable. PRPA plans to add 175 MW of battery storage by 2030. The utility acknowledged that long-duration energy storage would not be commercially available at scale until after 2030.
• Using the lowest carbon-emitting combustion turbine technology that is hydrogen capable. It’s worth noting that in all the utility portfolios, it assumes new thermal generation would use a fuel blend containing 50% hydrogen from 2035 on; and 100% hydrogen fuel from 2040 onwards.
• Building out a virtual power plant with the four owner communities. Platte River said though work is already underway to build a virtual power plant, modeling and data from consultants estimate it will take close to a decade to develop a fully functional resource.

In 20 years, the utility plans to add a total of 600 MW of solar and 885 MW of wind. PRPA would also add 275 MW of battery storage and 160 MW of long-duration energy storage during that time.

Platte River noted it could further refine its IRP during implementation, incorporating market conditions, technology evolution, availability and cost and timing of new resources.

The Signal Butte energy storage project would be a 250 MW, four-hour BESS located in the Elliot Road Technology Corridor in Mesa, AZ. The project would use lithium-ion technology and be operational by mid-2026. 

Signal Butte was selected from SRP’s 2023 All-Source Request for Proposals process. The project was jointly bid by Eolian, L.P., the original developer of the project; and Aypa Power.

The project would be owned and operated by Aypa Power, who purchased this late-stage battery energy storage project from Eolian, taking over the remaining development and construction required to bring this project into operation.

Once online, SRP will have full dispatch control of the storage system and will decide when to deploy its energy output. The project would typically be charged when energy costs are lowest and be discharged in the early-evening when demand is highest.  

SRP currently has nearly 1,300 MW of batteries and pumped hydro and 2,300 MW of carbon-free resources serving its customers. By the end of 2027, SRP expects nearly half of its generation mix to be carbon-free. 

The battery energy storage system (BESS) will have a 20-year guaranteed capacity of 25 megawatts (MW) and 100 megawatt-hours (MWh). A 25-year tolling agreement positions Ameresco as the asset owner and Snohomish PUD as the exclusive customer of the project. It allows Ameresco to provide Snohomish PUD the flexibility to utilize the battery energy storage system for charging and discharging activities under the agreement.

“This project represents a paradigm shift in the Pacific Northwest energy industry,” said Nicole Bulgarino, executive vice president at Ameresco. “By collaborating with Snohomish PUD, we are pioneering a unique model where the owner and the customer are distinct entities, showcasing the versatility and scalability of utility-scale storage solutions.”

Ameresco says the BESS will provide the PUD with enhanced electrical system reliability and flexibility while reducing exposure to energy price volatility.

“We’re excited to work with Ameresco on making this new battery energy storage project a reality,” stated John Haarlow, Snohomish PUD CEO/General Manager. “Energy storage is a critical component to helping us keep the grid reliable and affordable while also meeting our clean energy goals.”

Construction is expected to begin in late 2024 and the BESS could be operational in late 2025.

The largest non-standalone BESS project in the Northwest is located at Wheatridge Renewable Energy Facility (30 MW, 60 MWh) in Morrow County, Oregon. That site features first-of-its-kind wind, solar, and storage co-location.