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.

Zinc-based long duration energy storage (LDES) systems manufacturer Eos Energy is partnering with battery designer and power systems integrator FlexGen Power Systems to bring the first domestic BESS option to market.

Today the companies announced they’ve signed a joint development agreement (JDA) to develop and commercialize America’s first fully integrated, domestic storage solution by combining Eos’ Z3 zinc-bromine batteries with the FlexGen HybridOS Energy Management System (EMS) and a domestic inverter and transformer package. The end result will be a customizable solution for a variety of applications, from grid-scale to behind-the-meter energy storage systems.

Justin Vagnozzi, the senior vice president of global sales at Eos Energy, expects this partnership will increase Eos’ reach and deliver more value to customers of both companies by leveraging their combined pipeline of more than 50 gigawatt hours (GWh).

“This partnership not only strengthens our go-to-market strategy, but also positions us to deliver an American-made battery storage solution critical to securing America’s energy independence and national security,” Vagnozzi added.

North Carolina-based FlexGen utilizes its HybridOS EMS and Lifecycle service team to manage a rapidly growing fleet of energy storage assets for investor-owned utilities, municipal and cooperative utilities, and independent power producers.

Over time, Eos expects to source nearly 100% of the materials supply for the Eos Z3 battery from the United States. Domestic clean energy solutions are a hot commodity right now, as the U.S. scales critical manufacturing sectors, spurred by billions of dollars in Inflation Reduction Act investments. Companies are clamoring for domestic storage options in particular. When launched, this integrated solution is expected to deliver a competitive U.S. manufactured option to the market that utilizes the highest level of domestic content available.

A unique storage solution

Eos Energy, founded in Edison, New Jersey, offers an aqueous zinc battery designed to overcome the limitations of conventional lithium-ion, lead-acid, sodium-sulfur, and vanadium redox chemistries for stationary battery storage applications. The company contends its made-in-America solution is safe, scalable, efficient, and sustainable, providing utility, industrial, and commercial customers with 3 to 12-hour applications. The technology of the Z3 is specifically designed for long-duration grid-scale stationary battery storage that can assist in meeting the energy grids’ growing demand with increasing amounts of renewable energy penetration. Critically, Eos batteries are non-flammable and do not require active cooling to operate. The batteries can achieve 100% depth of discharge, do not degrade based on age, and are rated for 6,000 charge/discharge cycles before degradation.

Earlier this month, Eos Energy closed on a $303.5 million loan guarantee with the U.S. Department of Energy’s Loan Programs Office (LPO) to finance the construction of two state-of-the-art production lines producing the Eos Z3 in Turtle Creek, Pennsylvania. Two additional lines in Duquesne, Pennsylvania, may also be included as part of the loan guarantee. All four lines are expected to manufacture 8 GWh of storage capacity annually by 2027, or enough to provide electricity to over 300,000 average U.S. homes instantaneously or meet the annual electricity needs of approximately 130,000 homes if fully charged and discharged daily. The project is expected to create and maintain up to 1000 jobs.

According to the latest Energy Storage Monitor report, in the third quarter of 2024, the United States deployed a total of 3,806 MW and 9,931 megawatt-hours MW 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. 

Originally published in Renewable Energy World.

Vista Sands Solar LLC, a subsidiary of Doral Renewables, will construct the facility with a generating capacity of 1,315.6 MWac plus a 300 MW battery energy storage system (BESS) in the Village of Plover and the towns of Grant, Plover, and Buena Vista in Portage County, Wisconsin. Doral is targeting construction to begin in March 2025 and wrap up in December 2028.

The proposed project will encompass about 7,110 acres of the roughly 9,854-acre project study area, which is mostly farmland. The solar array is planned to take up just over 5,000 acres, and an additional nearly 1,600 acres of alternative spots for PV were provided by Doral in its application to the PSC initially submitted in January 2024. The BESS and associated operation and maintenance building will require 5.1 acres.

Since Doral is an independent power producer, the Wisconsin PSC did not review any costs associated with Vista Sands. The Commission would only do so if the facility is purchased by Wisconsin utilities.

Before Vista Sands dreams of connecting to the Midcontinent Independent System Operator (MISO), Doral will have to procure major components and build out parts of the site. Its wish list includes PV panels, power conversion units, inverters, approximately 318 miles of collector corridors for collector circuits and medium voltage lines, one substation, and a 345 kV overhead gen-tie transmission line of approximately 1,600 feet in length connecting the primary project substation to the point of interconnection. Vista Sands is seeking a Certificate of Public Convenience and Necessity (CPCN) and all other approvals required for construction.

“Today the PSC approved the biggest step toward curbing Wisconsin’s carbon emissions in the state’s history. Deployment of clean energy on this scale will do more to advance state energy policy than has any construction project in Wisconsin to date,” expressed Clean Wisconsin general counsel Katie Nekola. Wisconsin is targeting net-zero emissions by 2050.

Clean Wisconsin submitted testimony to the PSC about the benefits of the project, which include renewable energy for roughly 200,000 homes. A report from Quantum Energy released in October estimates that in its first year of operation, Vista Sands would avoid more than 1.6 million metric tons of carbon dioxide and 1,129 metric tons of particulate matter being released into the air, equivalent to the annual emissions from more than 353,000 vehicles. Quantum found clean power produced by Vista Sands would result in approximately 1,216 GWh less natural gas generation and 950 GWh less coal generation on the MISO regional grid while adding 2,296 GWh of clean electricity, meaning 94% of the electricity generated by Vista Sands would displace polluting fossil fuel generation. 

Portage County and surrounding communities will also receive a total of $6.5 million a year in payments from the project. Doral estimates Vista Sands Solar will usher in a total capital investment of nearly $2 billion and create approximately 500 jobs during construction and about 50 permanent jobs.

Farming the sun

Doral Renewables is no stranger to turning farmland into solar megaprojects. The company recently completed the first phase of the fittingly named Mammoth Solar in Indiana, another 1.3 GW behemoth that also promises to dramatically alter its former landscape. Mammoth should be selling electrons by 2026 and be completed late in that year or in early 2027, Doral president and CEO Nick Cohen told Renewable Energy World in a recent interview.

“We’re not really taking the farmland out of commission,” Cohen explained of projects like Mammoth and Vista Sands. “We’re farming the sun, which is what they’re doing anyhow, and most of what they’re farming out there is going to ethanol, so I don’t see how it’s different that now it’s just going straight to electricity.”

Conservationists and wildlife advocates have raised concerns about Vista Sands’ proximity to the Buena Vista Grassland State Wildlife Area, home of the state’s largest population of threatened prairie chickens. The final Environmental Impact Statement issued by the PSC also cited worries over those chickens, even if mitigation suggestions are followed. Doral says it will not construct any panels within 500 feet of the chickens’ grounds as identified by the Wisconsin DNR.

As it turns out, Doral is particularly familiar with handling livestock. The developer leans into dual-use practices, also known as agrivoltaics, and embraces a more traditional definition of farming- small, local, and steeped in heritage and family values. Its agrivoltaics project at Mammoth now includes more than 1,200 animals, including sheep, pigs, donkeys, and alpaca. That heartland-friendly attitude appears to have paid dividends with local farmers who agreed to lease land to Doral for both the Mammoth and Vista Sands projects. At the end of the leases, the solar panels will be removed and the land will remain the property of the families who have maintained it for generations, in many cases.

“We feel very connected to the community, and we know the names of all the farming families in this project and their stories,” insisted Doral project manager Ed Baptista. “We really put a lot of effort in getting to know people rather than just being some sort of out-of-town company that’s doing a project.”

“That’s important to us in all the projects that we do because we’re going to own and operate them for 30 to 35 years,” he added. “So we’re going to be neighbors.”

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.

Deemed the “Biden Energy Slush Fund” by The Wall Street Journal, the LPO has dabbled in everything from biofuels to hydrogen production, from onshoring electric vehicle wiring manufacturing to disseminating distributed energy resources.

Project IceBrick, LPO’s latest endeavor, is unique even by its standards.

Not just another brick in the wall

This week, LPO announced a conditional commitment to IceBrick Energy Assets I, LLC, a subsidiary of Nostromo Energy, for a loan guarantee of up to $305.54 million (including $303.69 million of principal and $1.85 million of capitalized interest) to finance Project IceBrick.

Project IceBrick is a virtual power plant (VPP) of up to 193 cold thermal energy storage (TES) installations at commercial buildings across California. The TES cells, a technology Nostromo has been touting since 2018 and the main component of the IceBrick systems, will be manufactured for this project and future U.S. installations entirely domestically by contractors in Texas, Iowa, and California.

The technology is hilariously simple. Basically, it utilizes ice to cool buildings rather than relying solely on air conditioning.

Project IceBrick would provide customers with efficiency as a service by freezing a water-based solution during prime solar generation hours when electricity is at its cheapest and cleanest. The IceBrick system would store and later use the ice to support cooling of the building during hours of peak power demand when electricity production is dirtiest and most expensive.

Nostromo says its nonflammable (duh) IceBrick cells are suitable for both new buildings and retrofits, and their compact and modular design makes them easy to configure into spaces of all sizes.

The company’s Cirrus software platform enables the IceBrick systems to operate as a VPP by orchestrating multiple energy assets to function in concert with one other or participating as individual assets. The resulting flexibility of this load shift technology provides resilient power capacity and serves as a load-stabilizing complement to intermittent clean energy assets, Nostromo contends. Project IceBrick also supports a higher rate of grid asset utilization, tempering electricity costs in a state facing some of the highest electricity bills in the nation.  

Nostromo asserts its IceBrick systems would allow California’s bulk power system to avoid up to 500 thousand tons of CO2 emissions over the project’s lifetime. Nostromo plans to share with its customers a portion of the expected cost savings attributable to this aggregate shift in building cooling load and intends to earn additional revenue by having the VPP participate in wholesale energy and capacity markets. At full scale, the project could provide the equivalent of approximately 170 MW (450 MWh) of behind-the-meter storage capacity for hotels, offices, data centers, and other commercial buildings.

Impact and next steps

DOE’s LPO believes the project can create more than 200 jobs, including at least 170 peak construction jobs. Over its five-year construction period, Nostromo Energy says it will create more than 870 annual job equivalents.

LPO’s investment supports the Biden-Harris Administration’s Justice40 Initiative, which sets a goal that 40% of the overall benefits of certain federal investments in clean energy and other areas flow to disadvantaged communities marginalized by underinvestment and overburdened by pollution. Some energy justice advocates fear Justice40 will be among the first items on the chopping block under the incoming Trump Administration, which could butcher provisions of the Inflation Reduction Act.

Project IceBrick is the third VPP project LPO has announced and the first to use cold TES. VPPs are aggregations of electrified, grid-connected devices, including grid-interactive efficient buildings, that reduce utilities’ reliance on natural gas peaker plants and reduce the strain on transmission and distribution infrastructure by intelligently time-shifting and shaving electricity demand.

If Nostromo Energy’s loan guarantee is finalized, it will be offered through the Innovation Energy category of LPO’s Title 17 Clean Energy Financing Program, which includes financing opportunities for projects that deploy new or significantly improved high-impact clean energy technologies. Interest in projects like IceBrick is also supported by the IRA’s Section 48 Investment Tax Credit, which allows businesses to deduct a significant percentage of the installation costs of TES and other clean technology installations from their federal taxes.  

DOE must still complete an environmental review and Nostromo must satisfy certain technical, legal, environmental, commercial, and financial conditions before the feds can decide whether to enter into definitive financing documents and fund the loan guarantee.

Originally published in Renewable Energy World.

The partners plan to develop industrial parks with gigawatts of data center capacity in the U.S., co-located with new clean energy plants to power them. The first phase of the first clean energy co-located project is expected to come online by 2026 and be fully complete in 2027, Google said. 

The partnership includes a planned $20 billion investment by Intersect Power in renewable power infrastructure by the end of the decade. Intersect Power has already begun financing the partnership’s first project.

The “power-first” approach to data center development is intended to increase the speed of infrastructure deployment, ease grid burden, and improve overall reliability and affordability for energy customers, Intersect Power said. The companies argue that by co-locating data center load with large amounts of high capacity factor clean electricity and added battery storage, data centers can achieve high percentages of renewable energy while reducing the transmission required to connect generation to load over longer distances.

“This partnership is an evolution of the way hyperscalers and power providers have previously worked together. We can and are developing innovative solutions to expand data center capacity while reducing the strain on the grid,” said Sheldon Kimber, CEO and Founder of Intersect Power.

Under the terms of the partnership, Intersect Power will build new clean energy assets, with Google providing offtake via newly constructed data center campuses as an anchor tenant in co-located industrial parks. Once built, the Google data center would come online alongside its own clean power, bringing new generation capacity to the grid to meet its own load.

Intersect Power also announced a more than $800 million funding round led by TPG Rise Climate and Google, with participation from Climate Adaptive Infrastructure and Greenbelt Capital Partners. Additionally, Google, TPG Rise Climate and other investors are making a capital investment in Intersect Power.

According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used. Demand for computing power from data centers, fueled by artificial intelligence and other new technologies, requires enormous amounts of power. Ohio is seeing unprecedented demand from data center customers, especially in the central part of the state.

 In the U.S., data center demand is expected to reach 35 GW by 2030, up from 17 GW in 2022, McKinsey & Company projects. Grid operators and utilities are projecting significant load growth driven by electrification, new manufacturing, and data center development. 

Utilities across the U.S. are grappling with how to equitably address growing data center demand through tariff structures. In late August, the Federal Energy Regulatory Commission (FERC) rejected a proposal from Basin Electric Power Cooperative that requested to create new wholesale power sales rate schedules for cryptocurrency centers and other large loads.

Some utilities are attempting to collaborate with technology providers, however. Amazon, Google, and Microsoft supported an effort by Duke to develop new tariffs designed to support the long-term sustainability goals of data center owners. The proposed Accelerating Clean Energy (ACE) tariffs would enable large customers to directly support carbon-free energy generation investments through financing structures and contributions that address project risk to lower costs of emerging technologies. ACE tariffs would facilitate onsite generation at customer facilities, participation in load flexibility programs, and investments in clean energy assets.

The idea of co-locating data centers with power generation is not new. Several power producers and data center developers are exploring it. Last month the Federal Energy Regulatory Commission (FERC) rejected a revised Interconnection Service Agreement (ISA) proposal that would have allowed expanded co-located load at an Amazon Web Services (AWS) data center connected to Talen Energy’s Susquehanna Nuclear plant in northeast Pennsylvania. The proposal has raised concerns about cost-sharing and grid reliability.

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.

Across the U.S. and worldwide, energy demand is soaring as data centers work to support the wide and growing use of artificial intelligence. These large facilities are filled with powerful computers, called servers, that run complex algorithms to help AI systems learn from vast amounts of data.

This process requires tremendous computing power, which consumes huge quantities of electricity. Often, a single data center will use amounts comparable to the power needs of a small town. This heavy demand is stressing local power grids and forcing utilities to scramble to provide enough energy to reliably power data centers and the communities around them.

My work at the intersection of computing and electric power engineering includes research on operating and controlling power systems and making the grid more resilient. Here are some ways in which the spread of AI data centers is challenging utilities and grid managers, and how the power industry is responding.

Upsetting a delicate balance

Electricity demand from data centers can vary dramatically throughout the day, depending on how much computing the facility is doing. For example, if a data center suddenly needs to perform a lot of AI computations, it can draw a huge amount of electricity from the grid in a period as short as several seconds. Such sudden spikes can cause problems for the power grid locally.

Electric grids are designed to balance electricity supply and demand. When demand suddenly increases, it can disrupt this balance, with effects on three critical aspects of the power grid:

• Voltage can be thought of as the push that makes electricity move, like the pressure in a water hose. If too many data centers start demanding electricity at the same time, it’s like turning on too many taps in a building at once and reducing its water pressure. Abrupt shifts in demand can cause voltage fluctuations, which may damage electrical equipment.
• Frequency is a measurement of how electric current oscillates back and forth per second as it travels from power sources to load demand through the network. The U.S. and most major countries transmit electricity as alternating current, or AC, which periodically reverses direction. Power grids operate at a stable frequency, usually 50 or 60 cycles per second, known as hertz; the U.S. grid operates at 60 Hz. If demand for electricity is too high, the frequency can drop, which can cause equipment to malfunction.
• Power balance is the constant real-time match between electricity supply and demand. To maintain a steady supply, power generation must match power consumption. If an AI data center suddenly demands a lot more electricity, it’s like pulling more water from a reservoir than the system can provide. This can lead to power outages or force the grid to rely on backup power sources, if available.

Peaks and valleys in power use

To see how operating decisions can play out in real time, let’s consider an AI data center in a city. It needs 20 megawatts of electricity during its peak operations – the equivalent of 10,000 homes turning on their air conditioners at the same time. That’s large but not outsize for a data center: Some of the biggest facilities can consume more than 100 megawatts.

Many industrial data centers in the U.S. draw this amount of power. Examples include Microsoft data centers in Virginia that support the company’s Azure cloud platform, which powers services such as OpenAI’s ChatGPT, and Google’s data center in The Dalles, Oregon, which supports various AI workloads, including Google Gemini.

The center’s load profile, a timeline of its electricity consumption through a 24-hour cycle, can include sudden spikes in demand. For instance, if the center schedules all of its AI training tasks for nighttime, when power is cheaper, the local grid may suddenly experience an increase in demand during these hours.

Here’s a simple hypothetical load profile for an AI data center, showing electricity consumption in megawatts:

• 6 a.m.-8 a.m.: 10 MW (low demand)
• 8 a.m.-12 p.m.: 12 MW (moderate demand)
• 12 p.m.-6 p.m.: 15 MW (higher demand due to business hours)
• 6 p.m.-12 a.m.: 20 MW (peak demand due to AI training tasks)
• 12 a.m.-6 a.m.: 12 MW (moderate demand due to maintenance tasks)

Ways to meet demand

There are several proven strategies for managing this kind of load and avoiding stress to the grid.

First, utilities can develop a pricing mechanism that gives AI data centers an incentive to schedule their most power-intensive tasks during off-peak hours, when overall electricity demand is lower. This approach, known as demand response, smooths out the load profile, avoiding sudden spikes in electricity usage.

Second, utilities can install large energy storage devices to bank electricity when demand is low, and then discharge it when demand spikes. This can help smooth the load on the grid.

Third, utilities can generate electricity from solar panels or wind turbines, combined with energy storage, so that they can provide power for periods when demand tends to rise. Some power companies are using this combination at a large scale to meet growing electricity demand.

Fourth, utilities can add new generating capacity near data centers. For example, Constellation plans to refurbish and restart the undamaged unit at the Three Mile Island nuclear plant near Middletown, Pennsylvania, to power Microsoft data centers in the mid-Atlantic region.

In Virginia, Dominion Energy is installing gas generators and plans to deploy small modular nuclear reactors, along with making investments in solar, wind and storage. And Google has signed an agreement with California-based Kairos Power to purchase electricity from small modular nuclear reactors.

Finally, grid managers can use advanced software to predict when AI data centers will need more electricity, and communicate with power grid resources to adjust accordingly. As companies work to modernize the national electric grid, adding new sensor data and computing power can maintain voltage, frequency and power balance.

Ultimately, computing experts predict that AI will become integrated into grid management, helping utilities anticipate issues such as which parts of the system need maintenance, or are at highest risk of failing during a natural disaster. AI can also learn load profile behavior over time and near AI data centers, which will be useful for proactively balancing energy and managing power resources.

The U.S. grid is far more complicated than it was a few decades ago, thanks to developments such as falling prices for solar power. Powering AI data centers is just one of many challenges that researchers are tackling to supply energy for an increasingly wired society.

Anurag Srivastava, Professor of Computer Science and Electrical Engineering, West Virginia University

This article is republished from The Conversation under a Creative Commons license. Read the original article.

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.