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.

Dominion made the request to the Virginia State Corporation Commission on Oct. 4 which includes six projects (337 MW) that would be owned or acquired by the utility and 13 power purchase agreements (435 MW) with independently owned projects.

Construction of the projects will support more than 1,600 jobs and generate more than $570 million in economic benefits across Virginia, Dominion said. Additional details about the utility-owned projects are below:

In addition to SCC approval, the utility-owned projects require local and state permits before construction may begin. If approved, construction is expected to be complete between 2024 and 2026.

The cost of the projects is estimated to add approximately $1.54 to the average residential customer’s monthly bill. Dominion Energy Virginia’s rates are currently 16% below the national average and 32% below the East Coast average, the utility added.

Episode 54 of the Factor This! podcast features Form Energy co-founder and CEO Mateo Jaramillo, a former Tesla executive pushing for deep decarbonization on the grid. Subscribe wherever you get your podcasts.

It sounded almost too good to be true.

Form Energy quietly launched in 2017 as a startup with big ambitions. The company aimed to manufacture and deploy an iron-air battery capable of delivering days of clean power on demand.

The firm was targeting a problem that didn't yet exist, but would become more pronounced as intermittent renewable energy resources displaced fossil fuel assets on the grid. Lithium-ion batteries could fill some of the gap as solar and wind output rose and fell, but only for minutes or a handful of hours. A multi-day, grid-scale energy storage solution would be critical for deep decarbonization, Form Energy's founders posited, even though previous efforts failed to fully capitalize on the opportunity.

Slick project renderings and the promise of a 100-hour storage solution allowed the company to raise nearly $1 billion, which included support from the likes of Bill Gates. Form Energy claimed its iron-air battery could be deployed at system costs that would be competitive with conventional power plants and at less than 1/10th the cost of lithium-ion.

Little was known, or shared, about how the battery might perform in the field. As is true for many emerging technologies, the company's marketing promises were met with some skepticism.

But six years after its launch, Form Energy says it is ready to prove its technology in primetime. The company has signed deals to deploy its battery with such risk-averse utilities as Xcel Energy, Southern Company, and Great River Energy, and recently broke ground on a commercial-scale battery plant in West Virginia.

Form Energy's CEO, Mateo Jaramillo, is quick to dismiss the string of milestones as successes. The former Tesla battery executive acknowledges that the company has yet to put steel in the ground. But the momentum behind a critical technology advancement can't be understated, either.

"I've been in batteries now for almost 20 years, and it is particularly gratifying to see a lot of real activity happening," Jaramillo said on the Factor This! podcast from Renewable Energy World. "I don't love the term hype, but there's a lot of talking. And until we actually produce that, then we can't say that we've gotten to where we want to be despite the long path that we have come down."

How it works

Form Energy didn't invent the iron-air battery chemistry, which dates back more than a half-century. The U.S. Department of Energy commissioned a study by Westinghouse in the 1970s to explore iron-air battery applications for transportation, but those didn't end up being ideal use cases.

At a high level, the basic principle of Form Energy’s battery operation is reversible rusting.  The battery contains an iron anode, resembling an automobile’s brake pad, and an air-breathing cathode. They are submersed in an electrolyte water bath with a permeable separation between them. When the iron is exposed to the oxygen and air, it triggers a chemical process called oxidation – otherwise known as rusting. That oxidation process releases electrons that are separated and sent to the grid – providing electricity when demand exceeds supply.  When there is excess power on the grid, the process is reversed and electrons flow in, releasing the oxygen and causing the iron to unrust, taking it back to a metallic state.

But Form Energy doesn't see itself only as a battery manufacturer. They implement systems, Jaramillo said, not chemistries.

"Nobody actually wants to buy a battery. What they want is electricity when they need it. That means, all they care about is the high side of the medium voltage," Jaramillo said. "If we're only focused on the electrochemical reaction and we get everything from the cell DC voltage wrong, all the way up to the medium voltage, it doesn't matter."

Timing is everything

Much of Form Energy's progress to date can be attributed to timing. Other well-intentioned and capable companies have taken on the multi-day storage challenge only to be too early for the market, Jaramillo said.

Even so, the market for its technology is still emerging. Form has spent years talking with policymakers and utilities about the merits of multi-day storage, which isn't adequately compensated by wholesale electricity markets.

Regulated utilities do, however, understand pricing for reliability, and have the ability to factor it into internal planning processes. One-hundred hours of energy storage also is familiar from pumped hydro, which represents the vast majority of nameplate rated storage on the grid.

"(Timing) was a fear that we had, of course, that it would be too early," Jaramillo said. "In conversations dating back in 2021, when it started to be very evident that that this could play a pretty prominent and impactful role, (utilities) want it right then.

"There's no in between. It was too early and then--now--not fast enough."

The real deal(s)

That sudden shift to go-go led to a deal with Xcel Energy for a demonstration-scale, 10 MW/1,000 MWh project be installed on 5 acres of land near the Sherburne County Generating Station in Becker, Minnesota. The project was recently approved by the Minnesota Public Utilities Commission.

Southern Company subsidiary Georgia Power, meanwhile, plans to deploy a 15 MW/1,500 MWh Form Energy system as early as 2026, pending regulatory approval. And Great River Energy, Minnesota’s second-largest electric utility, aims to partner with Form Energy on a 1.5 MW/150 MWh system.

Michael Webber, an energy researcher and professor at the University of Texas at Austin, and the chief technology officer at Energy Impact Partners, one of Form Energy's investors, said "utilities are clamoring for a solution" that addresses prolonged windless or cloudy days without relying on fossil fuels.

"This," he said, "just might be it."

A solar farm in Nebraska suffered significant hail damage during an extreme weather event that swept through the Great Plains last week.

The 4.375 MWac solar farm in Scottsbluff was damaged on June 23 by the same storm cell that injured eight people at a Wyoming coal mine.

Molly Brown, executive vice president of corporate strategy for GenPro Energy Solutions, which co-developed the project with Sol Systems, said insurance adjustors were onsite June 29 to assess the extent of the damage.

Based on a visual inspection, it appeared that only the solar modules were damaged in the storm, though further testing will be required. It’s unclear how long the project will be out of commission.

The Scottsbluff project features more than 14,000 JA Solar 380W modules, Brown said, and utilizes a single-axis tracker system with hail stow capabilities from Array Technologies. While it’s unclear if the asset’s hail stow program was activated during the weather event, damage to the face of the modules indicates it was not.

Brown believes it’s important to note that the extreme weather system caused significant damage to clean and fossil energy assets alike. While storms are indiscriminate, Brown said this is the first major damage GenPro has sustained since its first solar farm was installed in Lexington, Nebraska in 2017.

“We do get a lot of hailstorms in the Great Plains region, but typically the roofs get more damage than the solar panels.,” Brown told Renewable Energy World.

This is only GenPro’s second insurance claim on a solar array, and the first involved just five modules.

The Scottsbluff solar project is one of several developed by GenPro, Sol Systems, and Mesner Development for the Nebraska Public Power District. The project is in the midst of a 25-year power purchase agreement between Sol Systems and NPPD, and participates in the utility’s SunWise community solar program.

The PPA rate of $0.0519/kWh is the lowest rate NNPD has executed under its community solar program, according to a consortium that represents the three developers.

Renewable Energy World is in contact with NPPD, and has reached out to Sol Systems, regarding this story. Updates will be made as they come.

Stow early, stow often

Hail has become a prominent challenge for developers and asset owners, as modules move toward larger formats with thinner glass.

According to kWh Analytics, an asset insurance provider, moving panels into hail stow mode, where trackers are placed in a high degree tilt to reduce the impact energy of hailstones, is an effective mitigation technique that can reduce property insurance premiums up to 35%.

The firm modeled the revenue impact of a hail stow program to a 200 MW single-axis tracker site in Texas using PVLib and the National Solar Radiation Database.

GO DEEPER: Jason Kaminsky, CEO of the clean energy project insurance provider kWh Analytics, joined Episode 51 of the Factor This! podcast to share the data behind solar’s biggest risks, along with pathways to avoid potholes down the road. Subscribe wherever you get your podcasts.

The firm found that, assuming a $22/MWh PPA, moving into hail stow during extreme weather events throughout the year resulted in production loss of $12,000 or 0.1% of the asset’s $9.75 million estimated annual revenue. But the hail stow program resulted in a property insurance premium reduction of $2 million per year.

“The choice is clear: stow early and stow often when there is a chance of severe weather near your PV project,” the report’s authors wrote.

The report also noted that, based on RETC testing and modeling, PV modules with 3.2 mm tempered front glass over a polymer backsheet are approximately twice as resilient to impact as dual-glass modules with 2.0 mm heat-strengthened glass.

The U.S. solar industry is primed for significant growth in the coming years, emboldened by historic federal incentives and demand for renewable energy. But to what extent solar reaches its potential depends largely on how the industry navigates an evolving set of challenges.

Extreme weather, system underperformance, and labor shortages topped the fifth annual Solar Risk Assessment released by clean energy insurance provider kWh Analytics. The report used research from RETC, PVEL, BloombergNEF, Wood Mackenzie, ICF, Raptor Maps, Clean Power Research, National Renewable Energy Laboratory, Energy Sage, and Envision Digital.

“(2022) certainly provided some relief to those who have labored through the most recent turns of the solar-coaster, but we are not out of the woods yet,” kWh Analytics CEO Jason Kaminsky said.

Extreme weather

The declining availability of greenfield land for solar project development is leading developers to regions with harsher climates and, as a result, heightened extreme weather risks.

Hail has become a prominent challenge for developers and asset owners, as modules move toward larger formats with thinner glass.

According to kWh Analytics, moving panels into hail stow mode, where trackers are placed in a high degree tilt to reduce the impact energy of hailstones, is an effective mitigation technique that can reduce property insurance premiums up to 35%.

The firm modeled the revenue impact of a hail stow program to a 200 MW single-axis tracker site in Texas using PVLib and the National Solar Radiation Database.

The firm found that, assuming a $22/MWh PPA, moving into hail stow during extreme weather events throughout the year resulted in production loss of $12,000 or 0.1% of the asset’s $9.75 million estimated annual revenue. But the hail stow program resulted in a property insurance premium reduction of $2 million per year.

“The choice is clear: stow early and stow often when there is a chance of severe weather near your PV project,” the report’s authors wrote.

The report also noted that, based on RETC testing and modeling, PV modules with 3.2 mm tempered front glass over a polymer backsheet are approximately twice as resilient to impact as dual-glass modules with 2.0 mm heat-strengthened glass.

Additionally, PVEL analysis determined that glass//glass modules, which are steadily gaining market share with the popularity of bifacial modules, are more than twice as likely to break compared to glass//backsheet modules.

Financial Modeling

kWh Analytics found that asset owners are underestimating modeling uncertainty, causing projects to experience P99 outcomes, by definition a 1-in-100-year occurrence, every 20 years.

The firm said the main driver of this discrepancy is the lack of accounting for uncertainty in equipment performance when quantifying the likelihood of downside scenarios. Of the 25 independent engineer reports from recent utility-scale solar projects analyzed by kWh, none discussed incorporating uncertainty due to equipment performance.

Based on a data set of more than 200 utility-scale solar projects, kWh Analytics found the distribution of annual performance index relative to P50 estimates to be strongly left-skewed compared to the normal distribution typically assumed. The years of performance in the long left tail are from systems that experienced significant recurring inverter failures, ground faults, and manufacturer defects, they said.

Courtesy: kWh Analytics Solar Risk Assessment

Operational risk

Asset underperformance continues to plague the solar industry, presenting challenges for owners and investors alike.

Equipment-driven underperformance results in roughly $2.5 billion in losses annually for the solar industry, according to data that is extrapolated from the $82 million in total losses found in the 24.5GW of solar assets analyzed by Raptor Maps in 2022.

 Power loss due to anomalies has increased by 94% since 2019, according to Raptor Maps, a trend that could lead to “severe ramifications for the bankability of future projects” amid declining PPA rates. 

Large sites have seen the highest percentage increases affecting power production, with power loss increasing by 336% for 50-100MW sites, 243% for 200+ MW sites, and 168% for 100-200MW sites.

Smaller sites have a higher proportion of power loss than larger sites. 

“A standardized and centralized system that collates all relevant data in a digital twin – including inspections, power production, irradiance, and equipment maintenance history – is critical for the solar industry’s reliable growth,” the report authors wrote.

Courtesy: kWh Analytics Solar Risk Assessment

In addition to asset operational risks, the solar industry faces corporate operational headwinds, as well.

Nearly half of residential solar companies surveyed by EnergySage said a lack of trained labor is their biggest barrier to growth.

In the 2022 survey, installers reported that a lack of trained labor overtook customer acquisition as the biggest barrier to growing their businesses. Interestingly, despite recent supply chain constraints, only half as many installers (21%)pointed to the availability of equipment as a barrier to growth.