2024 was another banner year for a source of electricity that is better for people’s lungs, better for climate change and may be reaching your home when you turn on the lights or turn up the thermostat — large banks of batteries.

This ability to store large amounts of electricity in batteries was essentially nonexistent a decade ago, but the country had about 24 gigawatt-hours operating as of the end of November, up a whopping 71% over the same date in 2023.

This is welcome news to clean energy advocates including Dariella Rodriguez. She has seen what happens on days when demand for air conditioning or heating spikes and extra power plants fueled by natural gas, located in Port Morris and Mott Haven, fire up not far from where she works in Hunts Point in the South Bronx, New York.

Batteries can jolt into service, sending electricity onto overhead wires, instead of these dirty “peaker” plants. Rodriguez hasn’t seen that transition yet, but she hopes to.

“The people that are exposed to these plants are the most vulnerable people in environmental justice communities already,” said Rodriguez, a director at THE POINT Community Development Corporation there, noting that lower-income people and communities of color often live near peakers.

The nation’s 1,000 peaker plants can be very dirty, inefficient and expensive, according to an analysis by the U.S. Government Accountability Office, a watchdog group that works for the U.S. Congress. Some 63 million people are estimated to live within a three-mile radius of one.

Although peakers run only a small part of the time, they release more harmful nitrogen oxides and sulfur dioxide per unit of energy, the agency said. Those two pollutants cause asthma and other breathing problems.

Peakers also release more greenhouse gases than other power plants do per unit of electricity.
Batteries are “a really obvious solution” to reducing need for peakers, says Daniel Chu, senior energy planner for the New York City Environmental Justice Alliance.

Storing extra power in batteries also extends the hours of the day that you can use clean energy.
“It’s not always sunny, the wind’s not always blowing, but energy storage can help move that generation to when it’s most needed,” said Tim Fox, managing director at research firm ClearView Energy Partners.

That’s why at least half of battery storage facilities in the U.S. are co-located with, or in some other way support solar, an AP analysis of Energy Information Administration data shows. The amount of solar energy in the U.S. is growing and surpassed the 100-gigawatt mark this year.

Another way that the addition of these batteries is helpful to the American electrical grid and grids around the world is that forecasting is getting more difficult.

“With weather patterns changing, the old ways of essentially figuring out how much capacity you need on the grid for extreme events just doesn’t work,” said Oliver Garnett, director of energy services product at the technology company Fermata Energy.

Last, global electricity demand is slated to increase — by about one-third to three-quarters by 2050, according to the Energy Information Administration. Data centers for artificial intelligence, switching vehicles to electricity and population growth are all contributing.

“‘Do we have enough power plants?’ is the classic question every utility asks every year,” said Mike Jacobs, senior energy analyst at the science nonprofit Union of Concerned Scientists. “The beauty of the batteries is that if there’s energy in them, they can be used for unexpected needs.”

Otherwise, if utilities have to find more power generation, they may keep investing in plants that burn gas or coal and account for one-quarter of the nation’s greenhouse gas emissions, instead of retiring them.

Leading the charge for adding new batteries to the grid this year was California with more than 11 gigawatt-hours operating. One way to think about this is roughly the amount of electricity that a nuclear power plant would put out over 11 hours. Then the batteries would need to be recharged to do the same thing again. It’s a limited, but meaningful amount of power. In Texas, 6 gigawatt-hours were online.

Arizona saw nearly 2 gigawatt-hours humming and Nevada — the fourth-largest deployer of storage in the U.S. — had 1.1 gigawatt-hours operational.

Some regions are lagging

Yet many states aren’t using storage yet. As of November, 86% of large-scale battery storage in the U.S. was operating in just those four states.

Some states haven’t set targets telling utilities to go out and build or buy energy storage on their own. Only 18 states have 50 megawatt-hours or more operating.

Others don’t have as much clean electricity to pair with the batteries, or claim storage isn’t reliable in times of crisis. It can also be challenging to connect storage to the grid. Still, experts expect more momentum.

Especially in California and Texas, “That investment and that experiment is paying off very well,” said John Hensley, senior vice president of markets and policy analysis at American Clean Power.

“The word is getting out,” he said. “We’re increasingly seeing the technology move to other parts of the country.”

Today the LPO announced a conditional commitment for a low-interest loan guarantee of up to $15 billion for PG&E’s Project Polaris, which was submitted to the feds for consideration in June 2023. If finalized, the loan guarantee will support a portfolio of projects to expand hydropower generation and battery storage, upgrade transmission capacity through reconductoring and grid-enhancing technologies, and enable virtual power plants throughout PG&E’s service area. The utility, which serves about 16 million customers in Northern and Central California, says the loan will help it meet forecasted load growth, increase electric reliability, and reduce costs for its rate base.

Today’s announcement is the second Energy Infrastructure Reinvestment (EIR) project under LPO’s flexible loan facility and disbursement approach tailored for regulated, investment-grade utilities. The first was for the restoration and repowering of the Holtec Palisades nuclear plant, slated to become the first shut-down nuke plant to be recommissioned in the United States.

Electric utility borrowers for EIR projects must demonstrate that the financial benefits received from the DOE loan guarantee will be passed on to the customers of that utility or the communities it serves. LPO borrowers must develop and implement a comprehensive Community Benefits Plan (CBP), which ensures borrowers meaningfully engage with community and labor stakeholders to create good-paying, high-quality jobs and improve the well-being of the local community and workers. In its CBP, PG&E plans to expand its outreach programs to boost engagement and deliver community benefits in partnership with key stakeholders, including local governments, Native American Tribes, community-based organizations, and low-and-middle-income customers. PG&E has committed to locating many projects in disadvantaged communities, as identified by the Climate and Economic Justice Screening Tool.

LPO’s holiday spending spree

It’s no secret that the LPO is trying to get as much money as possible out the door before the Trump Administration takes office on January 20. In September, Trump pledged to rescind any unspent funds under the Inflation Reduction Act (IRA), the bipartisan infrastructure law that has pumped billions of dollars into the domestic supply chain and clean energy projects from coast to coast.

“To further defeat inflation, my plan will terminate the Green New Deal, which I call the Green New Scam,” Trump promised.

While it’s understandably easier for the President-elect to reign in unspent funding, he will have a tougher time navigating conditional loan guarantees and virtually no chance of recalling funds that have been distributed. According to the Wall Street Journal, the LPO is expected to extend the loan to PG&E via multiple cash installments spread out over several years, and the funding cannot be withdrawn by subsequent administrations. The LPO has closed on more than a dozen loans so far, totaling more than $13 billion.

The LPO has been especially this month, announcing a flurry of new loan activity. Yesterday, it announced $9.63 billion for BlueOval SK to finance the construction of three electric vehicle (EV) battery plants in Tennessee and Kentucky. Last week, DOE closed on a $1.25 billion guarantee with EVgo to expand public fast-charging infrastructure nationwide. The week before that was highlighted by a $303.5 million loan guarantee for Eos Energy Enterprises to support two Pennsylvania-based manufacturing facilities developing long-duration batteries. DOE also inked a conditional commitment of up to $7.54 billion with StarPlus Energy, a joint venture between automaker Stellantis and South Korean battery maker Samsung SDI, that will finance two lithium-ion battery cell and module factories in Indiana. According to an analysis by TechCrunch, automakers and battery manufacturers have attracted more than $112 billion via the IRA to build out domestic facilities.

How much more can DOE’s LPO spend?

The LPO has been granted the authority to distribute hundreds of billions of dollars to innovative clean energy and advanced manufacturing projects.

Through September 2024, the office reported financing nearly $44 billion worth to date. As of the EVgo announcement referenced above, that total was closer to $55 billion. Tacking on the billions for BlueOval SK’s battery plants and the PG&E guarantee brings LPO’s total near $90 billion. And there’s more to come.

Through November 2024, DOE’s LPO reports more than 200 active applications accounting for more than $324 billion in requested funding.

As of the start of this month, DOE estimated it had around $397 billion left to play around with, including more than $244 billion for Title 17 Energy Infrastructure Reinvestments, which PG&E just dipped into.

Cause for concern?

Electric utilities are rightfully concerned with the survivability of the LPO once Trump returns to the White House. Entire programs went dormant during his first presidency, and Trump will have the support of a Republican-majority House and Senate this time around.

Earlier this month, Duke Energy Carolinas and Duke Energy Progress paused their consideration of utilizing DOE loans, recognizing the money may not be there under Trump 2.0. According to a recent filing, Duke was about to hire a consultant to review EIR opportunities, but will now wait for the dust to settle.

“It is in the best interest of customers to pause any further efforts or expenditures until February, following the appointment of the new administration to gain clarity on the future of the EIR Program,” Duke Energy said.

PG&E is curious to see how it shakes out too.

“I think the number one thing that we’re interested in learning more about is the approach to the DOE loans,” detailed Shawn Adderly, director of PG&E’s Transmission Performance Center in a recent webinar on POWERGRID.

Adderly notes the application language is currently tied to renewable projects coming online, and he wonders whether the incoming Trump Administration will reframe consideration around something like predictability or grid security.

“We do need to upgrade our infrastructure,” Adderly admitted, referencing transformers operating past their expected lifespan and aging transmission lies. “I’m really hopeful, especially with the incoming administration campaigning on removing some of the bureaucracies, that they would encourage the permitting reforms to continue and to streamline the processes of regional planning and actions siting.”

“The biggest concern is just where the DOE loans land,” he reiterated.

Originally published in Renewable Energy World.

According to the latest Energy Storage Monitor report released today, in the third quarter of 2024, the United States deployed a total of 3,806 megawatts (MW) and 9,931 megawatt-hours (MWh) of energy storage, a new Q3 record and an 80% and 58% increase over the same span in 2023.

Most of that fresh capacity came courtesy of utility-connected batteries. The new American Clean Power Association (ACP) and Wood Mackenzie offering found that the grid-scale storage segment added 3,431 MW and 9,188 MWh in Q3, also a record for the quarter.

The cost of doing business

The rapid proliferation of energy storage onto the U.S. grid can be credited (at least partially) to the declining price of lithium-ion (Li-ion) batteries. Globally, battery prices just sustained their deepest year-over-year plunge since 2017 according to an analysis by research firm BloombergNEF (BNEF). Lithium-ion pack prices dropped 20% from 2023 to a record low of $115 per kilowatt-hour.

BNEF credits factors including cell manufacturing overcapacity, economies of scale, low metal and component prices, adoption of lower-cost lithium-iron-phosphate (LFP) batteries, and a slowdown in electric vehicle sales growth. Granted, Li-ion packs in the U.S. and Europe were 31% and 48% higher than those in China, which the analysis suggests is a reflection of the relative immaturity of the American and European markets, plus their higher production costs and lower comparative volumes.

Still, energy storage is getting connected to the grid at an ever-increasing clip, and competition in the global battery market is tightening (tariffs will help ensure that). And you can expect both trends to continue through 2025.

Record growth and more in Q4

ACP and Wood Mackenzie’s latest Energy Storage Monitor highlights rapid growth in Texas and California, where grid operators ERCOT and CAISO have been particularly eager to embrace storage as a solution to constraints and resiliency concerns.

In Q3 2024, Texas tripled installations compared to the previous quarter, adding nearly 1.7 gigawatts (GW). Only California brought gigawatt hours online, 6 GWh, thanks to the state’s focus on longer-duration storage.

Arizona, Colorado, Florida, and Vermont also added storage last quarter, hinting at a much larger appetite for grid-scale battery deployment nationwide.

The residential market set an all-time high in Q3, with 346 MW of residential storage installed, a 63% increase over Q2 2024. California, Arizona, and North Carolina had the most quarter-over-quarter growth, installing 56%, 73%, and 100% more residential storage in Q3 than in Q2 respectively. Community-scale and commercial and industrial (C&I) storage installations remained steady, with 29 MW installed, a 4% dip from year-ago numbers.

“We are seeing the energy storage industry fill a real need across the country to provide reliability in an affordable and efficient manner for communities,” noticed John Hensley, the senior vice president of markets and policy analysis for ACP. “The market signal continues to be clear that energy storage is a critical component of the grid moving forward.”

Texas’ recent battery boom is already paying off for customers in ERCOT territory, as new ACP analysis indicates the grid operator’s energy storage additions saved ratepayers $750 million this summer alone. Demand in ERCOT is higher than ever, but the problems that plagued Texas during the record-breaking summer of 2023 were abated this year by the state’s increasingly diverse mix of renewable energy generation and a whole lot of new storage.

ACP adds that increased energy storage deployment not only enhances reliability and affordability but also drives U.S. economic expansion, supporting growing industries like manufacturing and data centers.

“Energy storage is crucial for energy security and to help outpace rising demand,” chimed Noah Roberts, ACP’s VP of energy storage.

“Energy security” will no doubt be a combination of words we’ll hear often under Trump 2.0, regardless of what the administration chooses to do.

Potential growing pains

Grid-scale storage installations are projected to more than double by 2028, nearing a cumulative volume of 64 GW, and residential installations should eclipse 10 GW by then, per ACP and Wood Mackenzie.

“Overall, storage installations will grow 30% in 2024, signaling the industry’s strongest year yet. However, it will be difficult to keep this pace,” admits Wood Mackenzie senior research analyst Nina Rangel. “Between 2025 and 2028 we are projecting an annual average growth rate of 10%, as early-stage development constraints continue.”

Allison Weis, Wood Mackenzie’s global head of storage, noted that while consistent growth is expected, there are some uncertainties over the new presidential administration regarding potential changes to clean energy tax credits and increased tariffs that could come into play.

“While there might be potential opportunities in a new pricing environment for domestic manufacturers in terms of competition, any major shifts in tax incentives or increased tariffs could outweigh benefits and have an impact on new project development,” Weis warned.

That brings us back to the declining price of lithium-ion batteries. The market has benefitted from low raw material prices, which could rise in the next few years as geopolitical tensions, tariffs on critical minerals, and more stall new mining, refining, and manufacturing projects.

“One thing we’re watching is how new tariffs on finished battery products may lead to distortionary pricing dynamics and slow end-product demand,” said Yayoi Sekine, head of energy storage at BNEF.

As BloombergNEF notes, battery manufacturers have aggressively expanded production capacity over the past two years in anticipation of surging demand for batteries in the EV and stationary storage sectors. And they may have been a tad too ambitious.

Too much of a good thing?

Currently, overcapacity is a real concern. BNEF estimates the 3.1 terawatt-hours of fully commissioned global battery-cell manufacturing capacity is more than 2.5 times the annual demand for lithium-ion batteries in 2024. While demand across all sectors saw year-on-year growth, the EV market – the biggest demand driver for batteries – grew more slowly than in recent years.

“The price drop for battery cells this year was greater compared with that seen in battery metal prices, indicating that margins for battery manufacturers are being squeezed,” Sekine observes. “Smaller manufacturers face particular pressure to lower cell prices to fight for market share.”

“Regardless, higher adoption of LFP chemistries, continued market competition, improvements in technology, material processing, and manufacturing will exert downward pressure on battery prices,” BNEF’s head of energy storage predicts.

BNEF expects Li-ion pack prices to decrease by $3/kWh in 2025 based on its near-term outlook. Over the next decade, the research firm believes continued investment in R&D, manufacturing process improvements, and capacity expansion across the supply chain will help improve battery technology and further drive prices downward.

In addition, next-generation technologies like silicon and lithium metal anodes, solid-state electrolytes, new cathode material, and new cell-manufacturing processes will play an important role in enabling further price reductions. Plenty of lithium-ion alternatives are being actively piloted for their viability, technologies ranging from Natron’s sodium-ion battery to EnerVenue’s metal-hydrogen vessel; from gravity storage to IceBricks, it seems like there’s a storage solution for any situation.

Lithium-ion batteries are still the most economical solution for most situations, even without considering their trend downward pricing trend, but it takes a village, as they say- and ours should be doing all it can to ensure storage stays an economical solution for the foreseeable future.

Originally published in Renewable Energy World.

A brand new offering from grid-scale storage developer Energy Vault promises ultra-high energy density and 10+ hours of power, and it has already caught the attention of an emerging data center developer.

Today Energy Vault announced a strategic partnership with RackScale Data Centers (RSDC) that intends to accelerate the delivery of 2 GW of power to data center sites developed by RSDC via the deployment of Energy Vault’s proprietary B-Nest hyperscale battery energy storage system, targeting construction in 2026.

What is the B-Nest?

The B-Nest is a proprietary, fixed-frame, multi-story structure designed to house batteries for onsite energy storage, a boon for space-constrained project sites with a large interconnect capacity. Capable of storing up to 1.6 gigawatt hours (GWh) of energy per acre, Energy Vault contends its B-Nest represents a more than 8X increase in installed site energy density over traditional ground-mounted Battery Energy Storage system (BESS) installations. The ultra-high energy density of the B-Nest will provide each data center with full primary power for 10+ hours. When paired with an interruptible utility power contract, the system can ensure full power deliverability to each data center during demand response events.

The proprietary technology behind B-Nest stems from the IP developed for Energy Vault’s gravity-based energy storage systems and will incorporate structures similar to those used in G-VAULT designs. B-Nest solutions will be operated by Energy Vault’s proprietary VaultOS Energy Management System (EMS) to control, manage, and optimize the BESS operations.

“The B-Nest will be a major leap forward for the data center sector, and we are incredibly excited to bring it to market in partnership with RSDC,” said Marco Terruzzin, chief product officer at Energy Vault. “By incorporating the multi-story fixed frame structure concept inherent in our G-VAULT technology, we are delivering safe, cost-effective, insurable, and rapidly deployable solutions for the data center industry. With the B-Nest we look forward to providing data center developers the power they so urgently need.”

The partnership between Energy Vault and RSDC includes the planned deployment of 2GW/20GWh of B-Nest infrastructure that the companies say will drive a rapid portfolio build-out, taking advantage of the ability to capture supplementary revenue through participation in demand response programs with local utilities, in turn stabilizing the grid.

As utilities work to expand their generation fleets to meet surging power demand, estimated in a recent report to be approaching 6% growth over the next five years, data center interconnection wait times can now stretch up to five years or more. Goldman Sachs Research estimates that data center power demand will grow a staggering 160% by 2030, driven in large part by Artificial Intelligence (AI).

“It is absolutely essential that renewable energy generation and storage become key points of focus to power the AI data center boom,” surveys Marco Terruzzin, chief commercial and product officer at Energy Vault, who seeks to establish a model for the industry via its partnership with RSDC. “The safety characteristics, energy density, and economics of the B-Nest solution are ideally suited to meet the needs of the data center market, and we look forward to working with RSDC on the deployment of critical power infrastructure to support their ambitious growth plans.”

Last month, Energy Vault announced plans to deploy a 57 MW/114 MWh BESS in Scurry County, Texas, signing a 10-year offtake agreement with Gridmatic, an AI-enabled power marketer. Construction of the Cross Trails BESS is expected to start in the first quarter of next year, with commercial operation expected by summer 2025. The BESS will be built with Energy Vault’s proprietary X-Vault integration platform using the company’s UL9540 certified B-VAULT product, and VaultOS Energy Management System to control, manage, and optimize operations.

Earlier this year, Energy Vault celebrated the successful testing and commissioning of its Rudong EVx gravity energy storage system in China. In January, the Rudong EVx was selected as part of a list of projects with the classification of “new energy storage pilot demonstration projects” by China’s National Energy Administration. Projects selected receive increased management oversight by provincial-level energy authorities, allowing coordination for construction, data reporting, compliance, and safety measures, among other areas.

Originally published in Renewable Energy World.

At its November 14 meeting, the council approved the Final Order on the Application for Site Certificate (ASC) for the Sunstone Solar Project, formerly known as Echo Solar, shortly thereafter issuing a site certificate for the construction, operation, and retirement of the facility in Morrow County, Oregon.

If built to its intended capacity, Sunstone Solar will be one of the largest renewable energy projects in the United States. It is planned to have up to 1.2 gigawatts (GW) of generating capacity via nearly 4 million solar panels and up to 7,200 megawatt hours (MWh) of paired battery energy storage. The site is expected to provide clean, renewable power for up to 800,000 homes.

Construction on the project will include building an interconnection substation, up to six collector substations, up to four operations and maintenance (O&M) facilities, and up to 9.5 miles of 230-kilovolt (kV) overhead transmission lines, in addition to other structural work including roads, fencing, and gates.

Farming the sun

Sunstone will take a large chunk of usable farmland out of production. It is authorized to occupy up to approximately 9,442 acres (14.75 sq. miles) of private land zoned for Exclusive Farm Use within an approximately 10,960-acre (17-sq. mile) site, which is about 15 miles northeast of Lexington, OR.

The Oregonian notes the area has been cultivated in dryland winter wheat, and more than half of the site is considered “high-value” farmland. The state cracked down on solar siting in such places five years ago, but large-scale projects have found ways around restrictions by proving a site’s potential economic benefits to the local economy and mitigating the total loss of farmland.

Another project developer, owner, and operator, Doral Renewables, is plenty familiar with the arithmetic necessary to get projects approved while still maintaining critical agriculture. Doral just finished the first 400 MW phase of the colossal Mammoth Solar in Indiana, which will have 1.3 GW of clean capacity by the time it’s finished. Doral president and CEO Nick Cohen approaches the farmland conundrum with a clever line of thinking.

“We’re farming the sun, which is what they’re doing anyhow,” he notes, pointing out that a lot of farmers near Mammoth are using their crops for ethanol production- just another (dirtier) fuel. “I don’t see how it’s different that now it’s just going straight to electricity,” Cohen surmises.

Doral is making active efforts to return to traditional farming on small farms, leaning into an agrivoltaics pilot and maintaining close relationships with farmers in Mammoth’s footprint. It is unclear if Pine Gate plans to employ similar tactics at Sunstone Solar.

“There was a time in America when small farms grew food,” Cohen said in a recent chat with Renewable Energy World. “They produced food as a business. And that’s one of the things that our projects do, is we bring the heritage farming back to the small farms.”

Construction on Sunstone Solar is expected to begin in 2026, although the Pine Gate subsidiary has until November 18, 2027, to comply with applicable pre-construction site certificate conditions and start putting steel in the ground. It has up to three years to complete construction once work has begun.

The project will put a sizable dent in Oregon’s state climate goals, which require its two largest electric utilities, Portland General Electric and Pacific Power, to reduce greenhouse gas emissions by 80% by 2030 and be emission-free by 2040. PGE currently operates the region’s largest battery energy storage system, two 200 MW/800MWh BESS commissioned in 2023, which will be dwarfed by the Sunstone BESS once operational.

This fall, Pine Gate Renewables closed on a $288 million preferred equity investment with funds affiliated with Blackstone Credit and Insurance (Blackstone) supporting six solar projects in two states totaling 780 MW of capacity. All six of the projects are backed by corporate offtake agreements. Their locations have not been publicly announced.

Originally published in Renewable Energy World.

In August, Georgia Power Company submitted its 2023 Integrated Resource Plan Update (2023 IRP Update) to the Georgia Public Service Commission, which included the application to build half a gigawatt of battery energy storage systems (BESS). A lot of important information has been entirely redacted from public disclosure- deemed “trade secrets”- but here’s what we do know about the impending projects:

Robins BESS: A 128 MW, 4-hour duration BESS in Warner Robins, Georgia on an existing Air Force base site. The engineering, procurement, and construction company (EPC) is Burns and McDonnell. It will utilize lithium iron phosphate Tesla Megapack 2 XL batteries, which will be charged via electricity from the grid. It’s expected to be online in 2026.

Moody BESS: A 49.5 MW, 4-hour duration BESS in Valdosta, Georgia on an existing Air Force base site. The EPC is Crowder. It will utilize lithium iron phosphate Tesla Megapack 2 XL batteries, which will be paired with an existing solar project at the base. It’s expected to be online in 2026.

Hammond BESS: A 57.5 MW, 4-hour duration in Rome, Georgia on the site of Plant Hammond, an existing coal-fired power station that has been decommissioned. The EPC is Crowder. It will utilize lithium iron phosphate Tesla Megapack 2 XL batteries, which will be positioned alongside “existing infrastructure.” It’s expected to be online in 2026.

McGrau Ford Phase II: A 265 MW, 4-hour duration in Ball Ground, Georgia on a site in Cherokee County that already has a 265 MW BESS being built. Burns and McDonnell is the EPC. It also utilizes lithium iron phosphate Tesla Megapack 2 XL batteries, which will be charged by the grid. Phase two of this project is expected to be online in 2026.

An agreement between Georgia Power and the PSC’s Public Interest Advocacy Staff will require the utility to submit quarterly reports while the BESS are under construction, updating spending and the construction schedule.

What’s in store for Georgia Power?

In April, Georgia Power received permission from the Public Service Commission to forgo the typical bidding process and get right to constructing energy storage to support limiting the use of fossil fuels to mitigate peaks. In that filing, Georgia Power signaled its intention to solicit bids for more storage- another 500 MW- in the near future.

In February 2024, Georgia Power installed its first grid-connected BESS, the Mossy Branch Energy Facility, a 65 MW BESS on 2.5 acres of rural countryside in Talbot County, north of Columbus. The company marked commercial operations of the facility last month. It was approved by the PSC as part of Georgia Power’s 2019 IRP.

“We know our customers depend on us to make the investments in our state’s power grid needed to deliver reliable energy to their homes and businesses around the clock,” said Kim Greene, chairman, president, and CEO of Georgia Power at the Mossy Branch site in November. “Battery energy storage is an example of a new technology that will make our grid more reliable and resilient every day, and especially during extreme weather events. The Mossy Branch facility is an incredibly valuable addition to our grid and commercial operation of this site is a significant milestone in our continued work with the Georgia PSC to evolve and enhance Georgia’s power grid.”

Wärtsilä provided the engineering, procurement, and construction services for the Mossy Branch facility. The project utilizes the GEMS Digital Energy Platform, Wärtsilä’s energy management system.

As mentioned above, Georgia Power is currently developing the first phase of the 265 MW McGrau Ford BESS project in Cherokee County. This project was approved in the 2022 IRP, and Georgia Power expects the first phase to enter service by the end of 2026.z

Originally published in Renewable Energy World.

This week the DOE Office of Electricity (OE) announced the launch of the Energy Storage Innovations Prize Round 2, which builds on the success of the first Energy Storage Innovations Prize.

This one-phase competition calls for energy storage innovations focused on non-conventional use cases, like remote and/or underserved communities or extreme climates, and innovative (less mature) energy storage technology solutions, across all duration scales, to advance the market landscape.

DOE is committed to investing in innovations that deliver benefits to the American public and lead to the commercialization of technologies and products that foster sustainable, resilient, and equitable access to energy. Round 2 will also inform DOE’s strategy on transformative energy storage technologies to accelerate grid modernization for all consumers. 

“The Energy Storage Innovations Prize platform provides a unique opportunity to learn about different solution approaches to meet energy storage needs,” explained Caitlin Callaghan, director of storage materials and systems within the OE. “We’re excited to expand the solution set to address less conventional use cases through a second round of the prize, and we continue to connect a community of innovators addressing energy storage challenges.”  

DOE is offering a $300,000 prize, inviting individuals, academia, non-federal government entities, small businesses, start-ups, entrepreneurs, and other inventors in the U.S. working on nascent or emerging energy storage innovations that address less conventional use cases to submit their energy storage solutions. Up to five Storage Innovations Champions will receive a $50,000 cash prize each and up to five additional Storage Innovations Finalists will receive a $10,000 cash prize each.  

The Energy Storage Innovations Prize Round 2 closes on April 20, 2025. Learn more about this competition, including key dates and submission details on HeroX, the official prize platform.  

Since the American-Made Challenges prize program launched in 2018, DOE has awarded more than $400 million in cash prizes and incentives to competitors in more than 70 prizes spanning solar, water, geothermal, buildings, hydrogen, energy storage, transportation, technology transitions, manufacturing, and more. 

Originally published in Renewable Energy World.

Renewable energy developer, owner, and operator Arevon Energy has started commercial operations at its $529 million Vikings Solar-plus-Storage Project in Imperial County, California, believed to be the first utility-scale solar peaker plant in the United States. Its very existence contradicts the notion that renewable energy is inherently unreliable, instead providing carbon-free electricity at specific times of critical need to support the grid and empower ratepayers.

The specs

Vikings will utilize a 157 megawatt (MW) solar array paired with 150 MW/600 MWh of battery energy storage to shift low-cost daytime solar energy to higher-cost peak demand periods, lowering the cost of electricity for nearly one million customers of San Diego Community Power, the project’s offtaker. The companies have also executed a commercial agreement for Arevon’s 200 MW Avocet Energy Storage Project located in the City of Carson, California, which is expected to start construction in early 2025.

Vikings’ battery storage system can rapidly adjust capacity in seconds to address changes in demand. The project features key components from domestic manufacturers, leveraging incentives provided by the Inflation Reduction Act to maximize value. They include Megapack battery energy storage systems manufactured by Tesla in Lathrop, CA, First Solar thin-film photovoltaic solar panels, and Nextracker smart solar trackers. San Diego-headquartered SOLV Energy led the engineering, procurement, and construction (EPC).

“Vikings’ advanced design sets the standard for safe and reliable solar-plus-storage configurations,” said Kevin Smith, Arevon’s chief executive officer at last week’s ribbon cutting. “Its completion marks a significant milestone for Arevon.”

Typically, hybrid projects serve load when the sun is up and store the excess generation in their battery. That energy is then discharged in the evening during peak demand.

“The unique 1:1 solar to storage configuration of Vikings allows the project to shift the entirety of its generation from ‘solar hours’ to the peak demand period,” explains Jacob Montgomery, director of development at Arevon. “As an industry, we have already made steps in energy shifting a portion of solar generation by coupling solar with storage. The Vikings project takes it one step further by shifting the full output of the facility. This is another step in the right direction to provide clean renewable energy around the clock.”

Vikings, located near Holtsville, CA, was named after the local high school’s mascot and provided scholarships for several Holtsville H.S. students to use for college tuition costs. The project employed more than 170 personnel during its construction and will disburse more than $17 million to local governments over its lifespan, providing revenue for schools, first responders, and other community needs.

Vikings was previously recognized with the IJGlobal’s Renewables Deal of the Year – Energy Storage Award, lauded as one of the first utility-scale solar-plus-storage ITC and PTC transfer agreements since the U.S. Treasury announced the guidance for tax transferability in June of 2023. The project was financed with a $228M construction facility and a $72M ITC transfer bridge loan facility. In the past 12 months, Arevon has completed project financings of more than $3 billion.

Arevon’s endeavors

Arevon Energy, headquartered in Scottsdale, Arizona, owns and operates more than 4,000 MW of utility-scale solar, energy storage, and solar-plus-storage projects as well as distributed generation assets in 17 states. The company is constructing more than 2,000 MW of new solar and storage capacity and has a development portfolio of more than 6 gigawatts.

In July, Arevon started operations at its 200 MW/800 MWh Condor Energy Storage Project in San Bernardino County, California, its third utility-scale storage site in the state. Arevon also recently secured offtake agreements for its Cormorant Energy Storage Project and its Avocet Energy Storage Project and closed financing on its Eland 2 Solar-plus-Storage Project, its Condor Energy Storage Project, and the Vikings project.

Arevon’s chief operating officer Justin Johnson, who oversees EPC operations, says developing relationships with offtakers is similar to doing so with equipment suppliers, construction firms, and O&M service providers.

“We do a deal with them, we build a project, and we deliver what we promised when we promised. They’re comfortable with us, they trust us and you can do repeat business with them,” he explains. “It’s the same thing with the communities too. You build a project in the community, you’re a good member of the community, you support charity, you pay your property taxes… And then they see that it’s not so bad living next to a solar plant.”

Originally published in Renewable Energy World.

The town hall is closed on Fridays, don’t forget.

PMLD is one of 40 municipal utilities in the Commonwealth of Massachusetts. Tiny ones like Paxton can’t always afford to invest in substantial clean energy technology like battery energy storage systems (BESS), but does that mean the people who live there should be left behind in the clean energy transition while increasing grid demands strain their resilience?

Not if Lightshift Energy and the Massachusetts Municipal Wholesale Electric Company (MMWEC) have something to say about it.

A first-of-its-kind partnership

MMWEC is the designated joint action agency for munis in Massachusetts, serving 20 municipal utility members and all 40 municipal utilities as project participants. Back in 2022, following a competitive solicitation process, MMWEC selected Lightshift as its exclusive partner in a first-of-its-kind plan to deploy the state’s first jointly implemented fleet of grid-scale battery energy storage systems.

Lightshift is now constructing up to 50 megawatts (MW) across MMWEC territories, making an impact one community at a time. By the time they’re finished, the developer estimates a total cost savings of more than $200 million for MMWEC’s customers.

“I am beaming with pride over these projects,” gushes Rory Jones, cofounder of Lightshift and a Massachusetts native. “It’s been a few years in the making, and we’re just starting to really see the benefits come to life.”

Cutting ribbons and saving cash

Earlier this month, PMLD and Lightshift hosted a ribbon-cutting ceremony for the battery energy storage project in Paxton. The 3 MW / 9 MWh system uses lithium-ion phosphate batteries from TrinaStorage to reduce grid load during peak events, saving the municipal utility up to $10 million in energy costs while decreasing the Commonwealth’s reliance on fossil fuels.

“For smaller utilities such as Paxton Municipal Light Department, early adoption of new technologies can be cost prohibitive,” says Tara Rondeau, general manager at PMLD. “Thanks to MMWEC’s efforts in establishing a partnership with Lightshift, PMLD is able to utilize battery storage. This will help offset rising capacity and transmission costs for our ratepayers while focusing on cleaner solutions.”

The BESS in Paxton is the fourth in a long series under development. Two were recently commissioned in Groton, Massachusetts, and another in Holden. A fifth project is under construction in Wakefield.

“This is a great example of achieving a lot of efficiency and scale through a centralized procurement entity,” explains Lightshift’s Jones, who recognizes the utility (no pun intended) of applying economies of scale to these projects.

Ratepayers see the benefits too, from their bills to the air they breathe. Jones estimates Paxton’s 2,000 PMLD customers will save $10 million over the 20-year life of the project. That’s a solid chunk of change in a small community, which by nature of its new BESS is also staving off 30,000 tons of CO2.

Municipal utilities in Massachusetts aren’t able to participate in the Commonwealth’s Clean Peak Energy Standard, so the mechanism by which ratepayers save money is a little different, explains Jones.

“It’s shaving peak,” he details. “It’s reducing peak during times when the grid is most stressed, and they’re compensated for that by alleviating that need.”

Lightshift estimates the 5 MW BESS in Holden will save its rate base $30M and provide a net reduction of 50,000 tons of CO2.

Considering the dollars and the (common) sense, Lightshift’s cofounder says these energy storage projects weren’t too difficult to sell to their communities.

“They were welcomed, particularly when accompanied by a narrative that has that type of economic impact,” he offers with a smile. “it’s not typically a controversial technology. It’s fairly non-partisan in nature. And you know that the environmental impact is unequivocally there, but we lead with the economics.”

Rinse, lather, repeat

Although each battery energy storage project comes with unique concerns, the beautiful thing about the arrangement between MMWEC and Lightshift is that it’s easily replicable.

Lightshift’s Jones says his team worked with MMWEC to construct a sort of template for these projects, including legal agreements, power purchase agreements and/or energy storage services agreements, site control licenses, and interconnection agreements.

“Those are all boiler-plated, templated, and agreed to in advance,” Jones shares. “Then you replicate them over and over again, and you reduce all of the administrative and transaction costs associated with that. Those can be really burdensome on a smaller project.”

Jones asserts municipal utilities dramatically improve their buying power under arrangements like this. Instead of procuring the needs of a 2 or 3 MW project, a company can enter large-scale procurement and get the best prices on the market for batteries.

“You’ve worked with an EPC partner, the construction partner, that can build in sequence, serially, and create a lot of efficiencies there,” Jones adds. “So the cost of going in and developing a five-megawatt project on its own is very different from doing a portfolio like this. And there hasn’t been any of that yet in the space. There’s really a trailblazing application here that we’re trying to see replicated in other markets as well.”

Originally published in Renewable Energy World.

In a meeting Monday, the City of Green Bay Plan Commission authorized a Conditional Use Permit (CUP) to allow Tern Energy Storage LLC to establish a BESS on 8.1 acres of land tucked into the southeast corner of 20 acres zoned for General Industrial (GI) use at 2020 North Quincy Street, just north of Interstate Highway 43.

GI is Green Bay’s least-restrictive zoning district, but substations substations and distribution facilities
require a CUP to be established.

The proposed 200-megawatt (MW), 800-megawatt-hour (MWh) BESS will consist of approximately 450 battery enclosures (10’ X 30’ in size), approximately 112 transformers, and a collection substation. The BESS will support grid reliability by charging its lithium-ion batteries with energy from the electric transmission grid, storing that energy on-site, and delivering it back to the grid when needed. The project will be designed and operated in accordance with the National Fire Protection Association (NFPA) 855 Standard on the Installation of Energy Storage Systems, considered the gold standard for battery energy storage fire safety. It may also include an onsite operation and maintenance (O&M) facility, according to documents filed with the City of Green Bay.

The project will be owned and operated by Tern Energy Storage, a wholly owned subsidiary of infrastructure investment firm Copenhagen Infrastructure Partners (CIP), and will be developed by Tenaska, Inc. CIP currently has about $20 billion of assets under management and is involved in the development of 550 MW of BESS projects in Wisconsin, including the proposed Tern Energy Storage project. Tenaska, a private company based in Omaha, Nebraska, has been responsible for developing, managing, and operating more than 22,000 MWs of generation over its 35 years. It has been a partner with CIP in all of CIP’s Wisconsin BESS projects.

A Tenaska representative told the Green Bay Plan Commission that Tern Energy Storage represents a $300 million investment in the city. The project is expected to produce about 75 construction jobs once work begins in the fourth quarter of 2025. Tenaska expects operations to start in 2026 or 2027.

What else is in store?

More battery energy storage should be popping up across Wisconsin soon.

Presuming it overcomes increased costs and delays in construction, the Koshkonong Solar Energy Center will include a 300 MW solar facility and a 165 MW BESS in Dane County. We Energies, Wisconsin Public Service, and Madison Gas and Electric recently agreed to purchase the project from Chicago-based developer Invenergy. Considering supply chain disruptions, interest rates, and federal regulations combating unfair trade practices and forced labor, the once $649 million project is now expected to cost more than $900M to build.

We Energies also recently filed plans with the Public Service Commission of Wisconsin to build a bevy of new clean generation that would add more than 500 megawatts (MW) of solar power and 180 MW of wind power to the grid, including 100 MW of new battery storage.

Last September, Black Mountain Energy Storage received approval from the City of Milwaukee to construct a 300 MW/1,200 MWh battery storage project, slated to be Wisconsin’s largest known standalone battery project.

Originally published in Renewable Energy World.