Formed in 2021, CC Power is a joint powers agency representing the interests of nine California community choice aggregators (CCAs) established to take advantage of economies of scale when it comes to power procurement.
Fixed US$/kW/month price for 15-year term
The Tumbleweed LDES project was selected as part of an RFO issued in October 2020 by a group of CCAs seeking to procure up to 500MW worth of long-duration energy storage (LDES) resources.
Following the formation of CC Power early in 2021, the joint powers agency continued the work on the RFO that was already underway, negotiating and securing an ESSA with REV for its Tumbleweed project in January 2022, as reported by Energy-Storage.news.
Over the following three months, the agreement was approved by the eight CCAs participating in this particular ESSA: CleanPowerSF, Peninsula Clean Energy, San Jose Clean Energy, Silicon Valley Clean Energy, RCEA, Sonoma Clean Power and Valley Clean Energy.
Under the terms of the initial agreement, each CCA was set to receive a portion of capacity from the 69MW/552MWh agreement for a fixed US$/kW-month price for a period of 15 years under a tolling agreement with full capacity rights.
The agreement between CC Power and REV Renewables was first amended towards the end of 2021, increasing the contracted capacity from 69MW/552MWh to 75MW/600MWh.

According to an agenda packet for the upcoming RCEA meeting, REV informed CC Power early this year that the Tumbleweed project was no longer economically viable at the original contract price, citing an increase in equipment costs and “uncertainty related to tariffs on Chinese imports depending on the 2024 presidential election outcome”.
As reported by Energy-Storage.News and detailed in a Fact Sheet issued by the White House on May 14 2024, the Biden Administration plans in 2026 to increase the tariffs paid on non-EV batteries imported into the US from China by 17.5%.
The administration plans to also increase the tariff on certain battery components and minerals imported from China used to make batteries, including natural graphite that makes up the anode in the majority of modern-day lithium-ion batteries.
The news has been met with a mixed reaction from the industry, with market intelligence firm Clean Energy Associates (CEA) predicting the potential tariff increases could increase costs for US BESS integrators by 11-16%.
15-21% price increase indexed to import tariff rate
In order for the project to remain viable, REV and CC Power have renegotiated the terms of the Tumbleweed ESSA. These amendments include a 15-21% contract price increase indexed to the import tariff rate on Chinese goods up to a cap, along with increased penalties for REV Renewables if it’s unable to deliver the contracted resource adequacy (RA).
REV will also allow CC Power to purchase RA from the partially built project for around 1.5 years before the contracted commercial operation date (COD) at below-market rates.
Sharing of IRA benefits would make Tumbleweed feasible
Under the terms of the amended agreement, CC Power will no longer receive a share of the tax benefits expected to be handed to REV as part of the Inflation Reduction Act (IRA).
According to the meeting packet, REV Renewables determined that due to unexpected project cost increases, coupled with the new tariff uncertainties, sharing of tax benefits with CC Power would make the project “financially infeasible”, even with the renegotiated contract price increase.
RCEA noted that the conceding of tax benefits would be minimally offset by the expected savings from procurement of RA in advance of the contracted COD, as described above.
Amendments in RCEA’s best interests despite additional cost
RCEA noted that, despite the additional costs associated with the amended ESSA, moving forward with the renegotiated contract was still the best option for addressing compliance needs in a timely manner.
Although RCEA expects the amended contract to cost an additional US$1.5 million, it noted that this figure could be closer to US$2.5 million in a worst-case scenario where batteries weren’t imported in time, a maximum tariff on Chinese imports is brought into effect, and other CCAs default on the deal.
The Board of Directors at CC Power was expected to vote on the amended contract at a meeting yesterday, which will then be followed by votes from participating CCAs to decide whether they want to continue to be a part of the ESSA.
One of the CCAs represented by CC Power, Redwood Coast Energy Authority (RCEA), is then set to discuss the ESSA amendments today, at a regular Board of Directors (BOD) meeting. Energy-Storage.news will follow up to report the outcome of those meetings in due course.
CC Power selected a second 8-hour duration lithium-ion BESS project for a contract in March 2022, a 50MW/400MWh asset in development by Onward Energy with an expected commissioning date in 2025, ahead of the Tumbleweed project.
600MWh California BESS goes into delayed commercial operation
In other California BESS news, the battery storage portion of Arevon Energy’s Vikings Energy Farm was brought online this month, according to upcoming BOD meeting materials from the project’s power offtaker San Diego Community Power (SDCP).
Under the terms of the original PPA between SDCP and Arevon, the Vikings project was expected to come online in June 2023. However, after widespread Covid-19 and supply-chain procurement issues, the two parties made several amendments to the project’s offtake agreement.
These changes included reducing the BESS size from 150MW/600MWh to 145.5MW/582MWh and pushing the contracted online date by 10 months to April 2024. Despite these changes, the BESS still missed its amended contracted online date by four months.
As reported in Energy-Storage.News in November 2023, Arevon financed the Vikings project using a combination of debt financing alongside a tax credit transfer under the IRA, thought to be among the first times a developer in the US has utilised credit transferability.

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The ministry released a statement a day prior to the application window’s opening. Energy minister Vladimir Malinov said the investments, worth up to BGN1,153,939,700 (US$657.4 million) “will guarantee the security and stability of the Bulgarian electricity system.”
Tender bids must be submitted electronically, with more information available on this portal.
Each bidder can apply for up to BGN148,643,080 in financial support, with up to 50% of the eligible costs to be covered. However, no application can receive more than BGN371,607.70, not including tax, per megawatt-hour of usable energy storage capacity.
Project costs incurred after the day the scheme was announced, 25 June 2024, will be recoverable. At the time of its announcement, the government invited public comment on the initiative, as reported by Energy-Storage.news.
EU’s post-pandemic recovery efforts supporting scheme
The scheme is funded by the European Union (EU) post-COVID Recovery and Resiliency Facility (RRF) and is part of Bulgaria’s National Recovery and Sustainability Plan (NRSP).
Back in 2021, as the EU’s European Commission (EC) was considering applications from the bloc’s 27 Member States for their share of up to €672.5 billion (US$749 billion) in funding through the RRF, the European trade association for energy storage, EASE, had warned the EC that leaving energy storage out of the scope of support would be a big mistake.
Since then, along with the funds for Bulgaria’s RESTORE scheme, the EU has approved state aid and incentive schemes to support energy storage in various other countries.
They include a €350 million scheme in Spain, grants worth €150 million in Slovenia and a €1.1 billion Hungarian government state aid plan to support large-scale energy storage as well as schemes in Romania and Greece.
‘Europe’s largest distributed energy storage tender’
Meanwhile, in Poland, state-owned power company Polska Grupa Energetyczna (PGE) said it would apply for funding from the nation’s KPO Recovery and Resilience Fund worth €60 billion as it began tendering for a large-scale battery energy storage system (BESS) of 263MW and at least 900MWh capacity in June.
Earlier this month, PGE, which is a retail utility as well as a public power generator, also launched what the company claimed is Europe’s largest tender for distributed energy storage facilities to date.
On 13 August, PGE said it is seeking to deploy 26 systems, with capacities ranging from 2MW to 10MW, for a total of 107MW/214MWh of electricity storage.
“The project of building distributed energy storage is a market response to the demand of local distribution systems for the possibility of storing surplus renewable energy and then using it when demand exceeds its supply. This will not only support the stable operation of the grid but will also contribute to the optimisation of prices on the energy market,” PGE management board president Dariusz Marzec said.
“Increasing the potential of the flexibility sources of the National Power System, including the number and capacity of energy storage installations, is the most effective support for the development of renewable energy sources.”
See more information on the PGE tender.
In a sponsored article for Energy-Storage.news last December, Silvestros Vlachopoulos and Jon Ferris from consultancy LCP Delta wrote about the prospects for energy storage market development across Eastern Europe, highlighting Poland as the country with the greatest immediate potential due to the start of capacity auctions.
While that has so far been the case in initial auction rounds, de-rating factors proposed by the government for forthcoming auctions could destabilise and otherwise negatively impact market growth, Energy-Storage.news heard in June from Michał Maćkowiak, managing director of the Poland arm of BESS developer Harmony Energy.

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It is worth noting that the project received approval from Indonesian authorities in 2021.
The AAPowerLink project is set to deploy between 17GW and 20GW of solar capacity and between 36.42GWh and 42GWh of energy storage to connect Australia’s Northern Territory with Singapore via 4,300km of subsea cable and supply power to the territory’s capital, Darwin, and the surrounding region.
The project aims to deliver up to 4GW of green electricity to Darwin’s green industrial customers over two stages of development. 900MW will be provided in stage one and approximately 3GW in stage two. 1.75GW will also be supplied to customers in Singapore.
Once complete, it will be capable of delivering up to 15% of Singapore’s total electricity needs via a 2GW high-voltage direct current (HVDC) subsea cable, Sun Cable said. Electricity supply is anticipated to commence in the early 2030s.
In Singapore, Sun Cable is working with the Singapore Energy Market Authority on the conditional approval application for the project’s subsea cable interconnector component. Sun Cable is also engaging with the Indonesian government on regulatory and permitting matters to prove that the subsea route includes knowledge and hydrographic data sharing.
To read the full version of this story, visit PV Tech.

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It is built around ten miles from the busy Houston Ship Channel at the city’s port, on the site of H.O. Clarke, a now-closed fossil fuel plant owned by Houston Lighting & Power (HL&P). The Greater Houston monopoly utility also no longer exists, having been dissolved and split into separate entities as the Texas energy market was deregulated.
As such, Callisto I is in an important strategic location for helping manage energy supply and demand imbalances in the metropolitan region and could, in the future, be expanded to add another 400MW/800MWh of battery storage, Jupiter Power said.
In December 2023, the company closed a US$65.2 million financing agreement with First Citizens Bank’s Energy Finance business towards the project’s construction.
That followed up collaboration between the two the previous summer, for two Jupiter Power ERCOT projects totalling 160MW/320MWh, in which First Citizens acted as Lead Arranger for a US$70.4 million loan financing.
At the time, Jupiter Power CEO Bowman said Callisto I “answers the call from the Texas Legislature to build more dispatchable power in ERCOT and near major load centres where consumers need it the most.”
It is the Blackrock-owned developer’s ninth ERCOT BESS project to date, and the first outside of West Texas. As with the other assets in Jupiter Power’s 1,375MWh ERCOT fleet, it will play into the ERCOT wholesale market to earn revenues for its role in helping balance the grid and manage demand.
ERCOT has around 5GW of battery storage connected to it, and that installed base continues to go up rapidly, with the US national Energy Information Administration (EIA) recently publishing data forecasting 6.4GW of new additions during 2024.
Senator Schwertner: ‘Essential that Texas has a diversified energy portfolio’
“Callisto I is the first energy storage project at this scale in the City of Houston and will help meet Houston’s growing power needs while also increasing resiliency from extreme weather events,” Bowman said this week.
It comes as Texas and much of the US Southwest face some of the hottest periods of the year, which means peaking electricity demand and market volatility.
In an interview for Energy-Storage.news Premium in late July, market intelligence firm Modo Energy’s ERCOT market lead Brandt Vermillion noted that “pretty extreme” weather last summer contributed to high energy storage revenues in the grid operator’s service area, which averaged around US$200,000/MW for 2023. Meanwhile, volatility in the market is likely to increase, with revenues becoming “more concentrated into a small number of days.”
“That means an increase in volatility where prices are either going through the roof or batteries aren’t making much money at all,” Vermillion said.
Jane Stricker, VP of Greater Houston Partnership, the city’s biggest chamber of commerce, and executive director of its Houston Energy Transition Initiative (HETI), noted that as Houston’s first large-scale transmission-connected BESS, Callisto I “will help address peak power demand and is another great example of our region’s leadership in scaling and deploying impactful solutions for an all the above energy future.”
State senator Charles Schwertner offered a similar sentiment, adding that “it is essential that Texas has a diversified generation portfolio.”
“Batteries play an important role within that portfolio to help address demands in times of need,” said Schwertner, who is also chairman of the Senate Committee of Business and Commerce.

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Ancillary services to maintain grid frequency
CAISO procures energy and ancillary service needs through auction-based day-ahead and real-time energy markets, with all ancillary services procured as part of the system operator’s day-ahead market.
Although REV’s 40MW Vista Energy Storage project provides CAISO with both energy and ancillary services, the recent investigation carried out by FERC’s Office of Enforcement comes from alleged incorrect information CAISO received from the IPP relating to the Vista project’s ability to provide ancillary services, specifically when it came to grid regulation.
Regulation is a type of ancillary service used by CAISO (as well as other grid operators) to maintain its grid frequency at around 60Hz. This is achieved by reducing or increasing the total amount of energy on the grid through the charge or discharge of battery storage projects which CAISO administers through regulation up and down awards.
If a developer wants a project to participate in the ancillary services market, it must hand over control of the project’s output to CAISO’s automated control algorithm. Developers receive a fee for their project being available during specific times to provide ancillary services.
Optional SoC forecasting for participating assets
When a developer submits a bid into the CAISO day-ahead market, it has the option of forecasting its expected state of charge (SoC) at the beginning of the next day, known as the initial state of charge. Market engines used by CAISO will then use this figure to determine whether a battery is given a regulation up or down award.
Under CAISO rules, batteries sized like the Vista project (with a maximum state of charge limit of 38MWh and 85% charging efficiency) may receive a regulation down award only if the initial state of charge is 4MWh or less.
Once given a regulation award, CAISO will charge or discharge the battery to ensure it is able to provide the regulation ancillary service for at least 30 minutes, known as the ancillary service state of charge constraint.
CAISO will pay the developers of the batteries for the charging/discharging to maintain specific charge levels.
REV Renewables ‘knew, or should have known’
The FERC settlement filing explains that REV predicted the initial state of charge of its Vista project would be 4MWh or less, even though the project had been given a 36MW or larger regulation up award for the final hour of the day.
The settlement filing stated that REV “knew, or should have known”, that as the project had been given a regulation up award, the ancillary service state of charge constraint would mean the project’s actual state of charge would be around 20MWh during the final hour of the day, and not 4MWh or less, like REV had forecasted.
REV predicted Vista’s initial state of charge to be 4MWh or less over 33 consecutive days, resulting in the project being granted a regulation down award for the first several hours each day across the period.
As the battery actually had around 20MWh of charge each day, there was a conflict between the operation of regulation down, which sought to charge the battery, and the ancillary service state of charge constraint, that sought to do the opposite and discharge the battery.
Under CAISO rules at the time, the system operator was required to pay REV for the charging of the battery, amounting to a total of US$1.45 million. REV also received US$185,000 for the actual regulation down awarding.
US$2.67 million settlement to the treasury and CAISO
FERC’s Office of Enforcement concluded that REV had violated certain CAISO rules in providing an inaccurate initial state of charge figure, concluding that the Vista project was not “reasonably expected to be available and capable of performing at the levels specified”.
As part of the settlement, REV agreed to pay a US$1 million civil penalty to the US Treasury and a larger US$1.67 million to CAISO. REV also agreed to complete compliance training and submit one annual compliance monitoring report to FERC’s Office of Enforcement.
Although the developer acknowledged the facts within the settlement agreement, REV stated it “neither admits nor denies the alleged violations” put forward by the Department of Enforcement.
NextEra CAISO market infringements
FERC’s Department of Enforcement also carried out a separate investigation into NextEra Energy subsidiaries, NextEra Energy Resources (NEER) and NextEra Energy Partners, and the manner in how they provided CAISO with ancillary services from portions of their Arlington Energy Center, Blythe Solar, Desert Sunlight and McCoy Solar hybrid projects between January 2022 and September 2023.
Crucially, the point of interconnection (POI) limit for each of these co-located facilities is below the combined solar and battery potential maximum output. When the combined output of these projects reached their POI limit, logic controllers programmed by NextEra would curtail the battery facilities, allowing the solar facilities to continue delivering energy to the CAISO grid.
Up until the end of 2021, this wouldn’t have been an issue. However, in December 2021, CAISO changed its regulations prohibiting co-located battery facilities from deviating from dispatch instructions when providing ancillary services, something which NextEra claims it wasn’t aware of.
According to the settlement agreement, there were 3,835 five-minute intervals during which the battery facilities at the mentioned NextEra projects deviated from dispatch instructions while holding ancillary services awards.
The Department of Enforcement claimed that NextEra earned approximately US$381,724 in revenue during the 18-month period from energy produced by the solar facilities when, under the procedural changes enacted in December 2021, they should have been curtailed.
Full cooperation from NextEra
The settlement agreement noted that NextEra fully cooperated with FERC during the investigation, and has since corrected its software to amend this issue.
As part of the settlement, NextEra agreed to pay a civil penalty of US$105,000 to the US treasury and US$381,724 to CAISO.
REV Renewables in lawsuit with system integrator
LS Power-owned REV Renewables claims that its Vista project was the largest in the US at the time of energization in 2018, and has continued to progress other battery storage projects across the country over the past few years.
This includes its 200MW Diablo Energy Storage facility located in Contra Costa County that was brought online in 2022, which happens to now be the center of a contract dispute with systems integrator Fluence – as reported in Energy-Storage.News at the end of last year.
REV is seeking a US$230 million refund from Fluence citing a catalogue of “defects, deficiencies and failures” at the Diablo project.

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Last week, planning permission was granted for a 47.5MW project near Mannington, Dorset, near England’s South coast.
EDF Renewables, the clean energy subsidiary of French state-owned energy company EDF, already manages a portfolio of 150MW of BESS projects in operation across the UK. The company states that it plans to deliver up to 2GW of transmission-connected BESS projects in the coming years, with 400MW of capacity already consented.
Simone Sullivan, head of storage at EDF Renewables UK said: “Our upcoming project pipeline will strengthen the UK’s capacity to integrate more renewables and will allow the grid to be more flexible and resilient by managing electricity supply and demand.
Battery storage is critical to enhancing our energy security and to achieving the new government’s 2030 targets. We have a strong momentum behind our projects, helping the UK to reap the benefits of cost-effective, clean renewable energy and a modern, flexible grid.”
According to the UK’s electricity system operator, National Grid ESO, between 20-30GW of additional BESS capacity is required to meet 2050 net zero goals outlined in ESO’s Future Energy Scenarios.
Recent analysis from Solar Media Market Research indicated installed BESS capacity in the UK will rise to 7.4GW/11.6GWh by the end of 2024, a substantial increase from the current operational capacity of 4.6GW/5.9GWh.
To read the full version of this article, visit Solar Power Portal.

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As confirmed on a LinkedIn post published by Geoff Eldridge, National Electricity Market (NEM) and energy transition observer at consultancy Global Power Energy, the BESS asset becomes the second bidirectional unit to be registered on the Market Management System.
The bidirectional unit can charge and discharge energy to support the grid and provide ancillary services, enhancing overall system flexibility.
Neoen’s project will cost in the region of AUS$337 million (US$227 million), with the Australian Renewable Energy Agency (ARENA) set to provide AUS$17 million in funding support. The organisation allocated the funding to implement an advanced inverter technology into the asset, to enable it to provide grid-balancing inertia.
By being registered, the asset will begin its testing phase as a bidirectional unit.
The wind farm at Goyder is part of Neoen’s hybrid renewable energy facility development. Called Goyder South Renewables Zone, it will eventually comprise 1200MW of wind power, 600MW of solar PV, and 900MW of battery energy storage. 
Neoen subject to takeover bid from Canadian asset manager Brookfield
It is worth noting that the French independent power producer is set to be acquired by Canadian asset manager Brookfield, in a deal worth €6.1 billion (US$6.7 billion).
The closing of the deal will see Brookfield take a 53.12% majority stake in Neoen at €39.85 (US$42.6) per share from investors Impala and Fonds Stratégique de Participations, an investment vehicle owned by seven French insurance companies, amongst others.
Neoen announced negotiations with Brookfield in late May for a majority sale to the asset owner, along with its institutional partners Brookfield Renewables and Singapore-headquartered investor Temasek.
Once the acquisition has closed, Neoen said that it expects Brookfield to initiate an all-cash mandatory tender offer for all of the remaining shares and outstanding convertible bonds in the company.

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US$2 billion in regional transmission upgrades
The legislation requires the retirement of all Illinois coal-fired power plants, with the exception of Dallman Unit 4 and Prairie State Generating Station, by 2030 and all methane (natural) gas-fired plants to be retired or switched to burning green hydrogen by 2045.
The 2022 PJM report found that Illinois’s fossil-fuel phase-out would result in the state needing to import a “substantial amount of remote replacement power” to address the estimated loss in dispatchable power between 2030-2045 across Illinois in both PJM and MISO regions.
Calculations from PJM estimated the increase in electricity imports to cost an approximate US$700 million in transmission upgrades by 2030 and an additional US$1.3 billion by 2045.
Potential for extended fossil fuel plant operation
Despite PJM acknowledging that “new generation resources at the same points where units are retiring, or in similarly favourable locations, could decrease the transmission cost estimates,” it did not evaluate the impact of new energy storage resources within Illinois.
Conversely, PJM concluded it might “need to request that certain units operate beyond their desired deactivation dates”, referring to the continued operation of the state’s polluting fossil fuel plants, which the legislation was brought in to stop.
The recent NRDC report built on the 2022 PJM study by performing a resource adequacy assessment on the addition of BESS facilities at fossil-fuel plants set to be retired by 2030 in MISO Zone 4 and PJM’s ComEd service territory – referred to as the “Illinois Zone”.
In order to determine whether reusing interconnection capabilities of retired fossil-fuel plants would be a feasible strategy, the analysis carried out in the NRDC report limited new storage capacity to not exceed that of the retiring plants.
Resource adequacy simulation for four scenarios
The recent report prepared for the NRDC simulated four resource adequacy scenarios for the Illinois Zone, with each of the cases building on the previous one. This was measured against an industry standard 0.1 loss of load expectation (LOLE) target – equating to electricity demand outstripping supply no more than one day across a 10-year period.
The four cases were as follows:

Base case: existing installed capacity in Illinois (as of March 2024).
Post-CEJA: Base Case minus fossil-fuel retirement capacity as mandated by CEJA by 2030 (estimated 11,588MW reduction).
CEJA plus queue: post-CEJA case plus expected additions from the Generator Interconnection Queue (GIQ) (estimated 7,727MW addition).
CEJA plus storage – CEJA plus queue plus required storage to meet LOLE target.

3GW of BESS to address shortfall
The analysis (displayed in the following graph below) found that although the Base Case exhibited a 4,971MW surplus, both Post-CEJA and CEJA plus queue scenarios presented shortfalls, at 5,065MW and 2,213MW, respectively.
In order to meet the 0.1 LOLE target in the CEJA plus storage scenario, the report concluded that 2,972MW worth of 4-hour duration batteries would be needed.

A graph displaying the results of the four scenarios prepared by Astrape Consulting for the NRDC. Source: Illinois Deactivations – Maintaining Reliability with Energy Storage report (page 4).
Astrape Consulting carried out a separate sensitivity study to determine the required capacity of 8-hour durations batteries to meet the LOLE target.
It concluded that a lower 2,243MW worth of batteries would be required, drawing attention to the importance of longer-duration storage systems, which the California Energy Commission (CEC) also highlighted in a recent study covered by Energy-Storage.news Premium.
Difference in study assumptions and metrics
Although the PJM and NRDC reports both utilised the same methodology for estimating GIQ additions, there was a very large discrepancy between the two figures – with the PJM report estimating 1,723MW of additional GIQ capacity, and the more recent report for the NRDC estimating a much larger 5,605MW.
Astrape Consulting addressed this difference within its recent report citing the use of more updated GIQ data. However, this discrepancy is still worth pointing out.
The NRDC report didn’t quantify the costs associated with the deployment of 3GW worth of BESS, which would likely be substantial, although it stated that this “could be an area of future development”.
It’s also worth noting that, unlike the PM study which looked all the way until 2045, the analysis carried out by Astrape Consulting only took place until 2030.
The full report with all of its findings can be found here.
Illinois ‘Coal to Solar Energy Storage’ grant programme
The Illinois Department of Commerce & Economic Opportunity has created several programmes since instating CEJA to assist in decarbonising its grid, including the “Coal to Solar Energy Storage” initiative which saw funding be issued to the developers of five energy storage projects located at the site of closing or soon to be closed coal-fired plants.
Fortune 500 company Vistra Energy was the recipient of three of these grants in 2022 that will see the developer receive US$40.7 million for each project over a ten-year period, covered in Energy-Storage.News.
The three projects, located at the site of the developer’s Edwards, Havana and Joppa generation stations, will each provide the MISO region within Illinois with 37MW of storage capacity, scheduled to come online next year.

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The Energy Dome CO2 Battery is a set of gas compression and turbine equipment housed, as the company’s name suggests, inside a dome-like structure.
It stores energy based on the adiabatic compression of carbon dioxide, which is liquified during charging and evaporated as it discharges. Heat given off during compression is stored and used to expand the gas, driving turbines to generate power.
The Alliant Energy project, for which construction is planned to begin in 2026 and reach completion by the end of 2027, is being developed by a coalition of companies that include two other Wisconsin utilities along with oil and gas major Shell’s Shell Global Solutions US arm, the US Electric Power Research Institute (EPRI) and two academic institutions.
In September 2023, the Columbia Energy Storage Project was among 15 long-duration storage projects selected to each receive a share of US$325 million in funding from the US Department of Energy (DOE). This was part of the department’s Office of Clean Energy Demonstrations’ (OCED’s) efforts to progress significant cost reductions in LDES technologies with potential to scale.  
‘Increasing energy security and strengthening the grid’
Energy Dome was founded by Italian inventor and entrepreneur Claudio Spadacini, who aimed to combine off-the-shelf technologies and processes from existing industries to create an LDES solution that can be easily scaled and cheaply manufactured and installed, as well as safe to use.
The company has one existing commercial demonstration plant in Sardinia, Italy. It is also building a 20MW/200MWh project on the southern Italian island, which it closed financing on in 2023.
Energy-Storage.news Premium subscribers can read our interview with Ben Potter, Energy Dome’s senior VP of strategy, corporate development and investor relations, from March this year.
Potter discussed the company’s various business models including its build, own and operate (BOO) development of projects and tolling agreements with offtakers, a year on from a more wide-ranging ESN Premium interview in 2023, in which he introduced the company and its technology, claiming that it can be cheaper than lithium-ion battery storage when scaled and replicated.
While the mention of CO2 as a medium might raise climate-conscious eyebrows, the CO2 Battery’s use of 2,000 metric tonnes of CO2 per 100MWh is a “low volume” of the gas, which can be easily dispersed, Potter said.
“Innovative systems like the Columbia Energy Storage Project are increasing energy security for our customers and strengthening our nation’s power grid,” Alliant Energy director of technical solutions and federal funding, Mike Bremel, said.
The utility is targeting a 50% reduction in greenhouse gas (GHG) emissions relative to 2005 levels by 2030, elimination of coal from its generation fleet by 2040 and achieving net-zero emissions from its utility operations by 2050 under its Clean Energy Vision plan.
“This is a pivotal moment in our transition toward more reliable, sustainable and cost-effective energy solutions,” Alliant Energy VP of strategy and customer solutions Raja Sundararajan said.

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“DESRI is pleased to continue our investment in the energy transition in New Mexico with our fourth utility-scale renewable energy facility in the state, and to build on our long-standing relationship with EPE,” said Hy Martin, chief development officer of DESRI.
“In addition, the project will support the local community with economic development opportunities for years to come.”
The New Mexico Public Regulatory Commission (NMPRC) approved the project’s offtake contracts last year, clearing the path for DESRI to begin construction. US engineering company SOLV Energy will provide engineering, procurement and construction (EPC) services at the project, and oversee operations and maintenance work once the project begins commercial operation, and US investors Galehead Development and Lacuna Sustainable Investments were involved in the initial development of the Carne project.
The project is DESRI’s latest in the state, following its 200MW San Juan solar-plus-storage project, for which it completed financing last June, and the 28MW Alta Luna solar project, which started commercial operations in 2017.
The deal is also the latest move towards EPE’s expansion of its clean energy portfolio. EPE aims to add 280MW of new solar and storage capacity next year, alongside a further 50MW of capacity in a ‘business community solar’ programme. The utility plans for carbon-free energy to account for 80% of its total energy mix by next year, and to be fully decarbonised by 2045.
These targets are in line with New Mexico’s Renewable Portfolio Standards (RPS), which obligates investor-owned utilities to meet 80% of their electricity demand with renewable energy by 2040, and be fully decarbonised five years after that.
“The Carne facility is dedicated 100% to serving our New Mexico customers and will be a critical resource in enabling EPE to meet the needs of customer demand and requirements of New Mexico’s RPS goals,” said James Schichtl, vice president of regulatory operations and resource strategy at EPE.
“The battery storage component of the new facility will be the largest serving EPE customers and provide much needed capacity and reliability for our New Mexico customers.”

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