Aypa Power intends to develop, own, and operate a 150 MW/600 MWh battery storage facility in Kuna, Idaho just outside the capital of Boise. Aypa’s secured financing package includes a $233 million green loan, including a construction and term loan, a tax equity bridge loan, and a letter of credit facility. Additionally, the project secured $90 million in tax equity, bringing the total financing to $323 million. The company secured a 20-year agreement with Idaho Power last year and hopes to bring it online in 2025.

Renewable Energy World asked Aypa Power to see if the Idaho battery storage project requires any additional state or local approval and is awaiting a response. It’s a natural question for any clean energy project proposed in Idaho given a recent trend of local opposition.

Kuna residents recently came out in force against the 2,385-acre Powers Butte Energy Center solar project developed by Savion, Idaho News 6 reports. The proposed solar farm would be located in a rural farming area, much to the annoyance of the opposition, who say the farm would be a blight on the surrounding area.

Kuna residents attended the second public hearing on the Powers Butte Energy Center project, but Ada County Commissioners did not make a decision on the project’s future. By the end of the month, the Ada County Commission moved to halt on the project, BoiseDev reports, citing public opposition and their own feelings in their decision. Commissioners said the project would come with environmental concerns and unfavorable views.

Ryan Davidson, an Ada County Commissioner, called the decision “tough” and said the board he serves on is “not anti-solar.” He said the commission previously approved a Savion solar project that was developed “out in the desert,” instead of near residents.

It’s not just solar that faces an uphill battle in Idaho: a controversial wind project is facing another obstacle after Sen. Jim Risch introduced legislation to delay the 1,000 MW Lava Ridge Wind project, which is located on federal land near the Minidoka National Historic Site. The project’s opponents claim that the wind farm will “visually compromise” the historic site honoring more than 13,000 Japanese-Americans who were incarcerated during World War II.

Opposition to the Lava Ridge Wind project led the Bureau of Land Management to suggest nearly halving the size of the project from 400 turbines to 241 as part of the “preferred alternative” plan. Idaho’s state legislature unanimously passed a resolution in March 2023 expressing opposition to the Lava Ridge Wind Energy Project.

Based on local reporting, Idaho residents haven’t appeared to have objected to any battery storage project, though Aypa’s would be the state’s first utility-scale facility.

Idaho Power, the investor-owned utility providing electricity to most of the state, sees energy storage serving a key role in the future. Last year, the utility laid out a plan to acquire 101 MW of energy storage to address potential capacity shortfalls driven by limited third-party transmission capacity, load growth, and declining peak performance from several resources, NewsData reports. Some of that load growth will come from a Meta data center that’s expected to be completed in 2025.

While opponents of wind and solar — referred to unaffectionately as “NIMBYs,” an acronym for Not in My Backyard — have successfully fought projects across the country, the majority of Americas don’t mind living near clean energy projects, according to polling data.

A Washington Post-University of Maryland poll found around 75% of Americans are comfortable living near solar projects. Wind projects faired slightly worse at 70%. The poll did not ask about energy storage projects.

Despite broad support for clean energy projects in the U.S., at least 15% of counties have “halted new utility-scale wind, solar, or both,” according to a USA Today report, by implementing “outright bans, moratoriums, construction impediments, and other conditions.”

AEP announced in February that the utility had agreed with Icahn’s investing group to appoint one of his lieutenants, Hunter Gary, to its board of directors along with an independent representative, tapped by the Icahn firm, Hank Linginfelter. Both appointments required approval from FERC under the Federal Power Act.

“We look forward to working with Julie Sloat and the Board of Directors to optimize the value and performance of AEP’s high quality regulated electric utility business for the benefit of all of AEP’s stakeholders,” Icahn, who owns 1% of AEP, said at the time.

Despite Icahn’s public confidence in Sloat, she was removed without cause as the utility’s CEO a few weeks after the board changes. She served as the company’s first female chief executive for just over a year.

The progressive consumer advocacy group Public Citizen had asked FERC to use its authority to block the Icahn board appointments, noting that “typical investors” with only 1% voting shares would not wield outsized control over such a large corporation.

“Mr. Icahn is not a typical investor. He is an activist investor—earning the colloquial moniker ‘corporate raider’— specializing in engaging in protracted, hostile shareholder fights to gain control of target corporations for the sole purpose of moving the company’s stock price to a pre-determined target that bestows considerable profit for Mr. Icahn,” Public Citizen said in a filing with FERC.

In his concurrence with the FERC authorization, Commissioner Mark Christie said the Icahn board appointments were “found to be consistent with the public interest” but also emphasized that public utilities are “not typical for-profit, shareholder-owned companies,” and added that it’s “essential for regulators to make sure that the interests of investors do not conflict with the public service obligations that a utility has.”

Christie signaled the potential for further examination of investor influence on public utilities by FERC.

“(FERC) must have a comprehensive understanding of the investors that ultimately own or control public utilities,” Christie wrote. “Investor influence on public utilities and public utility holding companies continues to grow, and in ways that may conflict with public utility service obligations.”

The North American Electric Reliability Corporation (NERC) issued an alert on June 4 to generation owners and transmission planners concerning resources — like solar, wind, and batteries — that use inverters to connect to the grid. These assets are increasingly the subject of reliability concerns because of their inability to withstand grid disturbances.

NERC found that 10 large-scale grid disturbances on the bulk power system since 2016 involved the “widespread and unexpected” reduction of nearly 15,000 MW of inverter-based resource output, including 10,000 MW in the past four years. Performing dynamic simulations of the bulk power system, in addition to improved interconnection and system studies, could solve the problem, they said.

“The significantly higher complexity and software-based nature of IBR modeling when compared to synchronous machine modeling necessitates an improvement in the fundamental principles of dynamic modeling to accurately capture the performance of IBR plants,” the NERC alert said.

Episode 67 of the Factor This! podcast features Ryan Quint, who oversees engineering and security integration for the North American Electric Reliability Corporation, which oversees the reliability of the bulk power system. Subscribe wherever you get your podcasts.

NERC aims to gather responses from generation owners and transmission planners to eight proposed recommendations.

“When we have a normal grid event like that and we lose power from dozens of solar PV facilities, hundreds, or maybe even a thousand, inverters all at the same moment in time, that’s a potential recipe for a catastrophically bad day,” Ryan Quint, formerly NERC’s director of engineering and security integration, said on the Factor This! podcast in 2023.

NERC has issued more than a dozen reports in recent years diagnosing the shortfalls of IBRs. Some incidents are what the grid watchdog identifies as “faint signals” of broader implications. Others have teetered on complete grid collapse. 

The root causes of these disturbances typically involve a resource tripping offline due to a normal grid event: a tree falls on a powerline, a squirrel climbs on a substation bus, and so on. And these grid events happen every day. Due to the volume of grid disturbances, NERC’s postmortems are taking on a sterner tone. 

In its 2023 Southeast Utah Disturbance, which detailed the loss of 921 MW of solar generation from nine large-scale solar projects due to a normally-cleared fault on a faraway transmission circuit, NERC, in no uncertain terms, called out inverter original equipment manufacturers and generator owners for failing to address persistent, and previously identified, reliability issues.

Generator owners “are often not addressing performance issues that latently exist within the existing fleet,” NERC wrote, adding that in “all of the causes of abnormal performance in this event have been previously documented by NERC in past reports; however, actions were not taken.”

The disturbances have not, to this point, caused blackouts on their own. But that’s due to IBRs playing a relatively still-small role in the power system. As renewable energy rapidly displaces fossil-fueled, synchronous sources, those “faint signals” may lead to systemic failures if the industry does not remain vigilant in addressing these underlying reliability risks.

Efforts are underway to enhance the NERC reliability standards specifically related to IBR risks. The Federal Energy Regulatory Commission issued Order 901, which directed NERC to develop new or modified reliability standards. NERC is developing a comprehensive work plan regarding standards development activities to meet this directive, and is also making changes to its registration criteria and process to bring smaller projects on the bulk power system under NERC jurisdiction per a separate FERC directive. 

Originally published in POWERGRID International.

This week’s episode features Washington Post climate reporter Maxine Joselow, who reported on a new ruling by the EPA to curb power plant emissions.

This week’s “Cleantecher of the Week” is Justina Whipkey, the mill supervisor at a JM Steel plant outside Pittsburgh that just tripled capacity to supply trackers to solar projects throughout the region.

1. In America’s Biggest Oil Field, the Ground Is Swelling and Buckling — Wall Street Journal

An analysis by The Journal found that land under the Permian basin in Texas and New Mexico has sunk as much as 11 inches since 2015 as a result of drilling. In other areas where wastewater from drilling is pumped into underground wells, the land has risen by as much as 5 inches.

For context, nearly 6 million barrels of oil are produced per day in the Permian – that’s more than triple the amount from a decade ago. That extraction requires massive amounts of water that becomes unusable, so it’s pumped back underground. Last year, companies injected 3.4 billion barrels of wastewater into disposal wells in the Permian. The increased pressure from injecting all that wastewater is not only causing the ground to rise, it’s making it harder to drill, and when that water is pumped deep underground, it can cause earthquakes, which have increased more than tenfold in the area since 2017.

2. Musk Plans More Layoffs as Two Senior Tesla Executives Depart — The Information

On Monday, The Information reported that, confusingly, Tesla layoffs include nearly the entire 500-member charging team. This comes after Tesla’s net income was down 55% in the first quarter of this year compared to the same period in 2023. In April, the company announced plans to lay off more than 10% of their workers.

It’s a bit of a headscratcher: Tesla’s work to develop charger technology and build a nationwide network has been foundational to the growth of EVs in the US. The company had seemingly “won the charging wars” when the industry coalesced around their NACS charger in an effort to increase options for EV drivers when they’re on the road.

One of the biggest barriers to EV adoption is range anxiety, so a slowdown in the growth of this network is likely bad for EV adoption across the board.

3. Sodium Batteries From Michigan Challenge Lithium’s Grip on Energy Transition — Bloomberg

Natron Energy, a California-based energy storage company opened its first full-scale sodium-ion battery plant in Holland, Michigan on Monday.

Their batteries are similar to the lithium-ion batteries used in most EVs, phones, and computers. But there are some key differences: sodium-ion batteries discharge faster and don’t need lithium or cobalt, which can be expensive and environmentally damaging to source. And, according to Natron, there’s no fire risk.

The downside is that they have less energy density, which is critical in order for electric vehicles to have a long range, but less important for their target application: backup power to support large electricity users like data centers.

Watch the full episode on YouTube

4. Biden completes permitting rule — Axios

The Biden administration on Tuesday finalized a rule to reform environmental review under the National Environmental Policy Act (NEPA).

The new rules would expand what qualifies for a  “categorical exclusion,” which is essentially a fast track for certain types of low-impact projects in specific areas. 

They would add deadlines and page limits to environmental reviews and increase emphasis on environmental justice by directing agencies to consider local impacts and engage local communities.

5. New rules will slash air, water and climate pollution from U.S. power plants — Washington Post

The U.S. Environmental Protection Agency (EPA) has announced final rules to crack down on emissions from coal-fired and new natural gas-fired power plants.

The highly-anticipated announcement outlined a suite of measures aimed at reducing air, water, and land pollution from the power sector. As the sector makes long-term investments in the transition to clean energy, EPA said the rules are designed to work with power companies’ planning processes. Regulators say they project the rules will result in the reduction of 1.38 billion metric tons of carbon pollution overall through 2047.

Notably, EPA’s final rule heavily relies on carbon capture and sequestration/storage (CCS) as the best system of emission reduction (BSER) for the longest-running existing coal-fired units and most heavily utilized new gas turbines. Unlike the original proposal from nearly a year ago, decarbonizing these plants through clean hydrogen co-firing is not a factor in the new rule.

As we’ve reported, rules for existing natural gas-fired plants aren’t expected to come out until after the November election.

Help make This Week in Cleantech the best it can be. Send feedback and story recommendations to rew@clarionevents.com. And don’t forget to leave a rating and review wherever you get your podcasts.

Join us every Friday for new episodes of This Week in Cleantech in the Factor This! podcast feed, and tune into new episodes of Factor This! every Monday.

This Week in Cleantech is hosted by Renewable Energy World senior content director John Engel and Tigercomm president Mike Casey. The show is produced by Brian Mendes with research support from Alex Petersen and Clare Quirin.

Two states — California and Texas — account for the vast majority of installed battery storage capacity in the U.S., which has grown from 1.6 GW in 2020 to more than 14 GW by the end of 2023. The trajectory is only expected to continue.

“There was nothing. Now, we’re chasing our…” said Sai Moorty, principal of market design and development at ERCOT, the Texas grid operator.

Moorty joined a panel of regional grid operators at POWERGEN International 2024 in New Orleans alongside CAISO market design sector manager Danny Johnson and Michael DeSosio, a consultant who previously served as the director of market design at NYISO.

Battery storage growth in ERCOT can be largely attributed to a streamlined permitting and interconnection process, as opposed to procurement mandates in states like California and New York.

And while batteries have captured much of ERCOT’s ancillary services market, sustained growth could be predicated on market adjustments, Moorty said. Price volatility in energy-only ERCOT creates uncertainty for developers, while the surge in predominately 1-hour batteries creates operational challenges for the grid operator.

Moorty said a capacity construct, which is under consideration, may be the key to incentivizing longer-duration battery storage development.

“We have good scarcity pricing, our price gaps are really high, but do they last long enough to justify the additional capital investment?” Moorty said. “Lacking (capacity payments), we’re going to have to wait.”

Other potential pitfalls concern state of charge requirements, which determine the amount of power that must be stored in a battery at a given time.

Moorty acknowledges that a state of charge rule issued by ERCOT last year may be viewed by some battery storage developers as discriminatory to the technology. He said the rule is the product of rapid growth and an imperative to adapt to an evolving grid.

“We just don’t have experience with batteries,” Moorty added. “In ERCOT, we’re playing catch up right now.”

California, the U.S. leader in battery storage deployment with 7.3 GW of nameplate installed capacity, is the country’s most formidable market, thanks to capacity payments, broad participation opportunities, and a sizeable procurement mandate.

There are still “significant” challenges facing grid operators, according to Johnson of CAISO. State of charge management tops the list, he said.

“It’s finding the right balance of flexibility for asset owners to utilize and bid-in their assets as they see fit, while also ensuring that, as a grid operator, those assets will be able to perform as dispatched and we can maintain reliability,” Johnson added.

Another, forward capacity planning for battery storage, still eludes grid operators.

The traditional process of adding up total capacity to meet peak load in the coldest or hottest times of the year doesn’t easily incorporate an asset like battery storage, which has to charge in order to serve the grid.

“The traditional stack analysis goes out the window with storage,” Johnson said. “You have to make sure that they have the ability to discharge the energy. When are you charging? How does that get factored into capacity planning?”

New York State’s 194 MW of installed battery capacity pales in comparison to the totals boasted by California and Texas. But near-term capacity constraints, paired with a 3,000 MW energy storage target, present attractive opportunities for developers.

DeSocio, who now leads the consultancy Luminary Energy, said an indexed energy storage credit construct under consideration in New York is a good start. The program would marry capacity payments with energy arbitrage, which at present isn’t economically attractive enough to incentivize storage deployment in the state.

DeSocio advised developers to avoid New York’s retail market, which treats batteries as native load, triggering demand charges.

“There is a whole lot of pressure to get new resources built,” DeSocio said. “The opportunity for storage is two-fold: maximize wholesale revenues (capacity and ancillary services) and offtakers.”

In the wake of Hurricane Ida, the newly-minted chief executive of Entergy New Orleans, surveyed the damage. But it was the quiet that struck her most.

Less than 90 days in the role, Rodriguez encountered a fatality, tornado, hurricane, and a public relations storm that swirled around the company’s new peaker power plant.

Rodriguez clearly realized that her charge of leading the utility into a more resilient and cleaner future would not come without costs.

“It’s expensive and requires a lot of communication,” Rodriguez said during the keynote address at POWERGEN International 2024 in New Orleans.

Rodriguez’s role requires her to think about the future. An order from the New Orleans City Council to submit a resiliency plan in response to Hurricane Ida further solidified the imperative.

Seeing into the future, though, can be daunting. Especially without a roadmap.

Brian David Johnson, an applied futurist and professor who headlined the POWERGEN keynote, pushed attendees to embrace the power of “dumb ideas” when planning for the future.

An idea is only “dumb” until someone realizes its genius, he said. The exercise also triggers imaginative collaboration that will be critical as the power industry evolves in the coming decades.

Johnson himself went through the process as an internal futurist at IBM, tasked with predicting consumer behaviors for chip investments that take 10-15 years to materialize.

“You’ll see your team, and yourself, do some crazy stuff,” Johnson said. “You have really important things to solve, and this is a way to actually go through and begin to solve them, and come up with some of those things that people have never thought of before.”

Large corporations, like Microsoft, are dependent on the power industry to evolve and embrace The Next Big Thing, in large part due to ambitious climate and clean energy goals.

Todd Noe, Microsoft’s director of nuclear technologies engineering, told the POWERGEN International keynote audience that nuclear energy stands to play a pivotal role in the company’s carbon-negative efforts. He added that small modular reactors (SMR), hydrogen, and long-duration energy storage technologies could also prove crucial.

“Our vision is we seek to have a decarbonized grid, not just for Microsoft, but our customers around the world,” Noe said. “We don’t see any one carbon-free technology that’s going to be the answer.”

A piece of that puzzle, particularly in the future, is carbon capture and storage.

Brad Crabtree, assistant secretary for the Department of Energy’s Office of Fossil Energy and Carbon Management, said scaling carbon capture retrofits for aging coal fleets will be “critical” to meeting international climate obligations.

“Demonstrating U.S. leadership here at home, scaling up the technology, reducing costs, and building industry confidence can have a global impact,” Crabtree said.

The Reciprocating Internal Combustion Engine (R.I.C.E.) technology at New Orleans Power Station is more responsive, offers additional flexibility and operates at higher efficiency than the traditional generation units. New Orleans Power Station features seven Wärtsilä 50SG engines that provide a total output of 129.5 MW to the New Orleans area.

WATCH: Highlights from the POWERGEN International 2024 Tech Tour at New Orleans Power Station

Ninemile 6 is a 2×1 CCGT site with two 180 MW GE 7FA gas turbines and one 241 MW Toshiba Steam turbine that remotely operates Washington Parish Energy Center, a Simple Cycle Gas Turbine (SCGT) site with two 195 MW GE 7FAs turbines. Ninemile 6 can complete remote rounds using SPOT – The agile mobile robot.

Attendees received an up-close view of SPOT and a demonstration of its remote use. Attendees will also tour the combined-cycle units and water lab.

PJM forecasts summer peak load growth within the RTO to average 1.7% per year over the next 10 years, more than double the .8% annual increase forecasted in last year’s 10-year outlook. Winter peak load is projected to grow 2% annually for the next decade, which also doubled.

Net energy load growth within the region is projected to average 2.4% annually over that period, according to PJM’s 2024 Load Report, an increase of 1% from the forecast issued in Jan. 2023. Total PJM energy is forecasted to be 1,033,267 GWh in 2034, a 10-year increase of 219,939 GWh.

PJM experienced a similar doubling of its 10-year load forecast from 2022 to 2023 when summer peak load growth jumped from projected growth of 0.4% per year to 0.8%. New data centers were to blame then, too.

According to Grid Strategies, U.S. peak demand growth could grow by more than 38 GW through 2028, driven by the development of data centers and industrial and manufacturing facilities.

The report, The Era of Flat Power Demand is Over, cited forecasts from grid planners, who have doubled the five-year load growth forecast over the past year. The nationwide forecast of electricity demand jumped from 2.6% to 4.7% growth over the next five years, according to FERC filings – and these forecasts are likely an underestimate, Grid Strategies said. Recent updates have tacked on several GW to that forecast, and next year’s will likely show an even steeper growth rate.

Perhaps unsurprisingly, Grid Strategies says our power grid is not yet ready for such significant growth. The U.S. installed 1,700 miles of new high-voltage transmission miles per year on average in the first half of the 2010’s but dropped to only 645 miles per year on average in the second half of the decade. Low transfer capability between regions is a key risk for reliability if load growth outpaces deployment of new generation in some regions, the report added.

Transmission investments will ultimately need to increase to keep up with demand, but investor-owned utility investment in transmission serving new load has actually decreased over the past three years, according to data from Edison Electric Institute. In 2021, expansion-related transmission capital expenditures were forecast at $9.2 billion but declined to $8.8 billion for 2023.

Originally published in Power Grid International.

A battery bubble may be forming. What happens if it pops? Episode 70 of the Factor This! podcast answers that question by taking an intimate look at the two top battery markets in the U.S. — California and Texas — and their diverging trajectories. Subscribe wherever you get your podcasts.

Battery storage is booming in the U.S., and for good reason.

So much intermittent renewable energy on the grid demands flexible resources to fill gaps. And, short of reverting to fossil fuels, batteries are the best answer to support the energy transition.

Investors have poured billions of dollars into battery storage development to cash in, largely based on speculative opportunities. But there's one problem: markets have been slow to evolve, leading to an uptick in consolidation and growing uncertainty about the path ahead.

Could a battery bubble be forming?

"Market by market," answered Cody Hill, who leads independent power producer REV Renewables' battery storage division. "Generally, no. There is so much load growth. There's so much that's happening."

"ERCOT? I mean, yes," Hill said, referencing Texas' market.

Watch the full episode on YouTube

More on Texas in a bit.

REV Renewables, which began its spinoff from LS Power in 2021, developed some of the first battery storage projects in California. The state boasts more than 6,600 MW of installed storage capacity to lead the nation, up from 770 MW just four years ago. The state is projected to need 52,000 MW of energy storage capacity by 2045 to meet electricity demand.

The battery boom in California can be attributed both to ambitious state procurement mandates as well as a market structure that allows batteries to support resource adequacy needs, like power generators, as opposed to being relegated to ancillary service programs with limited needs.

In 2013, the California Public Utilities Commission approved the nation's first energy storage mandate, requiring the state to procure 1,325 MW by 2020. Following blackouts in the summer of 2020, the CPUC ordered an additional 11.5 GW from clean energy sources, which was followed by an order for an additional 4 GW in 2023.

California's ban on new natural gas generation "opened the door" for the battery boom, since storage is one of the only resources that can fill that gap, cleanly, according to Renae Steichen, REV's director of regulatory affairs and the incoming chair of the California Energy Storage Alliance.

Other states are getting the itch. Maryland recently passed a mandate for 3 GW of energy storage capacity by 2033. Michigan will require 2,500 MW by 2030. New York intends to procure 6 GW by 2030 if approved by regulators. Illinois could be next.

But while new markets are opening up, none are quite like California. The Golden State's ambitious clean energy targets, paired with a deepening "duck curve" and favorable market structure, create a sound economic opportunity yet to develop anywhere else.

So let's talk about Texas, the second-largest battery storage market in the U.S. with around 9 GW installed as of 2022, according to the Energy Information Administration. Battery developers, backed by billions in private equity, have flocked to ERCOT, in part due to favorable permitting and interconnection rules that have made Texas a hotbed for clean energy growth.

But the market opportunity for battery storage is somewhat limited. The majority of battery systems in Texas range from 1-2 hours in energy capacity, and asset owners are battling over a finite amount of capacity set aside to support daily grid management needs, often referred to as ancillary services.

The battery storage analysts at Modo Energy report that around 70% of operational storage capacity in ERCOT was reserved for ancillary services in 2023. Early next year, the analysts expect the capacity of batteries reserved for ancillary services to exceed the capacity of capacity awarded to storage.

"We do expect to see saturation happen in battery-dominated ancillary services in the next few months," Modo Energy analysts wrote last month.

Ancillary services is a "shallow market," as Hill describes. Grid operators like CAISO, ERCOT, or PJM only need a few hundred megawatts to meet their needs. It's a good starting point for battery storage, but "it's not going to scale." Meanwhile, the arbitrage opportunity that makes California attractive is more muted, due to relatively low solar penetration that prevents cheap charging.

What Texas does have, to its detriment and the benefit of battery owners, are high-frequency price scarcity events as a result of extreme weather and skyrocketing load growth.

Hill believes that first-mover developers in ancillary services-dependent markets can be successful, but the outlook for Texas battery development is "not for the faint of heart."

"(There are such) low barriers to entry, and it's easy to get in there to build lots of stuff, and so many people raised so much money to go build so much stuff in the last few years," he said. "It's a very tough market."

Saturation in the Texas market is becoming an increasingly common topic of conversation among battery players. An uptick in M&A among the state's leading development shops further complicates the outlook.

Broad Reach Power offloaded its battery assets to ENGIE in August for a reported $1 billion, and Jupiter Power was gobbled up by BlackRock late last year.

Are market constraints and consolidation cause for concern of a battery bubble? Not everyone is convinced.

Jason Burwen, vice president of policy and strategy for the battery storage IPP GridStor, doesn't believe in the theory that a bubble is forming. But even if one does, and it pops, the industry will continue to grow.

Burwen believes the "boom-bust" dynamic is a hallmark of the Texas market, and isn't exclusive to storage. That shouldn't be the reason for developers to stay away, he said. He believes battery storage deployment will dwarf estimates in the coming years.

"It just might not be the first owners of those batteries who get to profit from it," Burwen acknowledged.

The company said the funds will help accelerate its manufacturing and deployment plans to meet the growing demand for green hydrogen. Electric Hydrogen has raised more than $600 million since its founding in 2020.

The funding round was led by Fortescue, Fifth Wall and Energy Impact Partners and included new investors bp Ventures, Oman Investment Authority, Temasek, Microsoft’s Climate Innovation Fund, the United Airlines Sustainable Flight Fund, New Legacy, Kajima Ventures and Fatima Holdings USA. Existing strategic investors Amazon’s Climate Pledge Fund, Equinor Ventures, Mitsubishi Heavy Industries, and Rio Tinto continued their participation, as did previous financial investors Breakthrough Energy Ventures, Capricorn Partners, Prelude Ventures, and S2G Ventures.

Watch Plug Power CEO Andy Marsh on the Factor This! podcast from Renewable Energy World discuss why he believes green hydrogen is “under attack” by policymakers in Washington

Electric Hydrogen is manufacturing and plans to deliver and commission 100 MW electrolyzer systems, each capable of producing nearly 50 tons of green hydrogen per day at low cost.

“We’re here to replace natural gas and coal with renewable green hydrogen,” Electric Hydrogen CEO Raffi Garabedian said. “Today’s hydrogen comes from natural gas and coal and accounts for around 2.5% of global carbon emissions. There has not been a viable solution to this problem because renewable green hydrogen has been too expensive to produce at scale.”

The company is currently installing manufacturing equipment in its 1.2 GW factory in Devens, Massachusetts. The factory will begin producing commercial electrolyzer systems in early 2024, with deliveries later in the year including the first customer-sited electrolyzer plant to be installed in Texas for New Fortress Energy.

Electric Hydrogen said it has more than 5 GW electrolyzer orders to date.