ESS Tech, listed on the New York Stock Exchange as “GWH”, announced it has secured a $50 million investment from the Export-Import Bank of The United States (EXIM).

The funds are expected to support the expansion of ESS production capacity at its Wilsonville, Oregon plant. The company develops long-duration energy storage iron flow batteries. The investment is expected to help ESS triple its manufacturing capacity at the Wilsonville plant.

“Our technology uses earth-abundant iron, salt and water to deliver environmentally safe solutions capable of providing up to 12 hours of flexible energy capacity for commercial and utility-scale energy storage applications,” said ESS Tech.

EXIM made the investment via its Make More in America Initiative, which makes available medium- and long-term loans, loan guarantees, and insurance to finance export-oriented domestic manufacturing projects.

ESS Tech is delivering iron flow energy storage systems to customers in Europe, Australia and Africa. The company manufactures 100% of its products in the United States, with a predominantly domestic supply chain that spans 29 states.

“Our partnership with EXIM underscores the critical role that American-made clean energy technology will play in the global clean energy transition,” said ESS chief executive officer Eric Dresselhuys. “ESS’s iron flow technology is already deployed in Australia and Europe and with this agreement, we are well positioned to meet the growing needs of our current and future global customers.” 

ESS battery systems are designed to operate for 25 years, while conventional batteries last about 7 to 10 years. The battery modules, electrolyte, plumbing, and other components may well last for decades longer with proper maintenance, said the company. The battery, for example, is expected to experience zero degradation over 20,000 cycles. The long duration energy storage (LDES) system can store and dispatch electricity for 12 hours or more.

According to the Department of Energy’s ‘Pathways to Commercial Liftoff: Long Duration Energy Storage’ report, the U.S. grid needs 225 to 460 GW of LDES capacity for power market application for a net zero economy by 2060. The global LDES market is estimated to be $50 billion per year and forecast to grow significantly with a cumulative investment of up to $3 trillion by 2040, according to the LDES Council and McKinsey & Co.

From pv magazine Global

Summer weather and a heat dome have brought increased irradiance to both US coasts, with the strongest impact in the North East, while New Mexico and regions through the midwest experienced below-average irradiance due to increased cloud cover and atmospheric disturbances, according to analysis using the Solcast API.

Much of the continental United States saw irradiance moderately above average, 5-10% above historical June averages, with the increase most notable along the East Coast. The “heat dome” that dominated much of June was accompanied by upper-atmosphere subsidence which suppressed cloud formation, allowing more sunlight to reach the ground. In contrast, the Gulf of Mexico experienced increased precipitation and cloudiness. However, prevailing winds kept most of these clouds offshore, except for the tip of Florida. The area around the Great Lakes saw up to 10% below average irradiance due to the additional heat enhancing evaporation and cloud formation.

Despite the heatwave, New Mexico saw irradiance 5-10% below typical levels. This deviation was caused by a tropical disturbance in the Gulf of Mexico, which was observed on June 19. This disturbance brought moisture and atmospheric instability, triggering thunderstorms over New Mexico a few days later.

These thunderstorms caused flash floods and large hail in the region. While these events are not widespread enough to fully extinguish the wildfires across the state, it has impacted solar panel performance. Hail can damage and destroy solar panels, but many utility-scale solar farms in this latitude employ single-axis tracking systems that can stow panels in a vertical position to reduce damage risk. Smoke from wildfires also impacts irradiance by soiling panels and reducing light transmission through the atmosphere.

This year, the Summer Solstice happened on June 20. As the sun reaches its highest point in the sky in the Northern Hemisphere, irradiance also typically peaks around this time of year across North America. However, in Central America, this is somewhat offset by the
increased cloudiness of the tropical wet season.

Solcast produces these figures by tracking clouds and aerosols at 1-2km resolution globally, using satellite data and proprietary AI/ML algorithms. This data is used to drive irradiance models, enabling Solcast to calculate irradiance at high resolution, with typical bias of less than 2%, and also cloud-tracking forecasts. This data is used by more than 300 companies managing over 150GW of solar assets globally.

From pv magazine Global

The Chinese Module Marker (CMM), the OPIS benchmark assessment for TOPCon modules from China was assessed at $0.100/W, down $0.005/W week-to-week. Mono PERC module prices were assessed at $0.090/W, down $0.005/W from the previous week. The new record lows for both prices according to OPIS data comes as market activity remains subdued on low demand.

Module makers have reduced prices in a bid to secure new orders and maintain cash flow with tradable indications for TOPCon modules heard at $0.10/W Free-on-Board (FOB) China.

Solar modules exported to Europe continue to contend with elevated freight rates on matters in the Red Sea. OPIS heard freight rates of about $0.0164-0.0175/W (about high $6,000s-$7,000/FEU) for shipments from Shanghai to Rotterdam. While this has affected shipments, it presents an opportunity for module sellers to reduce their inventories in Europe.

A market observer said that prices during Intersolar did not move and remained around $0.10/W FOB China (+/-0.3cts) and that despite the high installations season just starting, the installation demand for Europe this year did not seem very strong, at least in the utility-scale space.

Latin America continues to look weak with the price competition in this market described as “intense” by a module seller. Prices in the Brazilian market are generally lower than in other markets as buyers are price-sensitive. TOPCon prices to Brazil had fallen to the range of $0.08-0.09/W FOB China with prices at the low end offered by Tier2-3 module sellers, the module seller added.

A buyer noted that current U.S. Delivered Duty Paid (DDP) TOPCon prices have risen to the low-to-mid $0.30/W range. This pricing includes the 201 bifacial tariffs but excludes the new antidumping/countervailing duties. With the exemption set to lapse mid-week, another market source told OPIS that “any new deals would be subject to the 14.25% Section 201 tariffs and will likely push pricing into the mid $0.30s/W in 2024”.

Domestic Chinese demand remained weak amid mounting inventory pressure. Further price cuts in the coming weeks were expected as module sellers clear inventories to generate cash flow. The majority of market participants OPIS surveyed expected TOPCon prices to drop below CNY0.8/W or $0.099/W on a FOB China equivalent, which is the current cost of production for integrated producers.

The operating rates of integrated module sellers remained between 60-80%, according to the Silicon Industry of China Nonferrous Metals Industry Association. Estimates of June module production capacity stood at 50 GW, down from 52 GW previously expected and down 5 GW from May, the association said.

China exported 83.3 GW of modules in the period January-April marking a year-on-year increase of 20%, according to latest data from China’s Ministry of Industry and Information Technology. The total value of the module shipments for the period January-April reached $12.7 billion.

Looking ahead in the FOB China market, broader bearish conditions prevent any upticks in module prices in the short term although continued production cuts into July could give some respite to supply pressures.

OPIS, a Dow Jones company, provides energy prices, news, data, and analysis on gasoline, diesel, jet fuel, LPG/NGL, coal, metals, and chemicals, as well as renewable fuels and environmental commodities. It acquired pricing data assets from Singapore Solar Exchange in 2022 and now publishes the OPIS APAC Solar Weekly Report.

Generac Power Systems, a provider of home backup generators, battery energy storage, and other power products, announced it has acquired PowerPlay Battery Energy Storage Systems, an engineering, procurement, and construction (EPC) firm.

PowerPlay specializes in turnkey battery energy storage systems for commercial and industrial customers, with systems sized up to 7 MWh. It is a division of Sungrid, an energy storage EPC and operations and maintenance company.

Generac said the acquisition will help the company offer a more complete ecosystem of products and solutions to C&I customers.

The PowerPlay business will continue its operations in Cambridge, Canada, and serve as a dedicated research and development facility for Generac’s C&I battery energy storage system solutions. SunGrid Solutions will continue its energy storage EPC operations across the United States and Canada, specializing in solutions ranging from 10 MWh to 1 GWh.

“Various factors contribute to the need for energy storage, including the uptake of distributed solar, increased electrification of C&I facilities, rising utility rates, and possibility that the central grid can experience fluctuations due to weather, blackouts, or lack of infrastructure,” said Generac. “[Battery energy storage] systems up to 7 MWh are commonly deployed in C&I enterprises, including retail stores, restaurants, office buildings, manufacturing facilities, and healthcare facilities.”

Energy storage deployment continues to rise nationwide. Across all segments, Wood Mackenzie expects 12.9 GW / 35.8 GWh of storage to be installed in 2024. In its quarterly report, the firm raised its five-year forecast for grid-scale installations by 5% and residential sector installations by 8%. The five-year commercial, community, and industrial forecast was cut by 34% after the California Public Utilities Commission (CPUC) made an unfavorable ruling on community solar. However, Wood Mackenzie sees a strong value proposition for C&I storage for years to come.

“The CCI segment continues to see the highest barriers to growth in the near-term, but its strong value proposition and emerging value streams will make it an exciting growth segment in the later years of our ten-year forecast,” said Wood Mackenzie.

From pv magazine Global

IEA PVPS Task 12 (PV Sustainability Activities) has released an updated Fact Sheet, shedding light on the environmental impacts of photovoltaic (PV) electricity. This Fact Sheet, titled “Environmental Life Cycle Assessment of Electricity from PV Systems“, offers crucial insights into PV sustainability and highlights key advancements as well as current data in PV technology.

Life Cycle Assessment: A Comprehensive Overview

Life Cycle Assessment (LCA) is a detailed method used to quantify and assess the material and energy flows, as well as emissions, throughout the life cycle stages of PV systems. These stages include manufacturing, transport, installation, use, and end-of-life. The manufacturing phase encompasses resource extraction, raw material production, and the creation of wafers, cells, panels, inverters, and mounting structures. Transport covers the distribution logistics, while installation involves setting up roof-mounted systems and cabling. The use phase evaluates the system’s performance over a typical 30-year operational period, including maintenance. Finally, the end-of-life stage addresses dismantling, recycling, and waste management processes.

The updated Fact Sheet primarily focuses on a typical residential PV system in Europe. This system is defined by a roof-mounted PV setup, an annual production rate of 976 kWh/kW, and an in-plane irradiation of 1,331 kWh/m². It includes PV panels, cabling, mounting structure, inverter, and installation, with a linear degradation rate of 0.7% per year and a service life of 30 years for panels and 15 years for inverters.

Evaluating PV Module Technologies

IEA PVPS Task 12 assesses four PV module technologies, each with distinct efficiencies: Cadmium-Telluride (CdTe) at 18.4%, Copper-Indium-Gallium-Selenide (CIS/CIGS) at 17.0%, Multi-crystalline Silicon (multi-Si, BSF) at 18.0%, and Mono-crystalline Silicon (mono-Si, PERC/TOPCon) at 20.9%. These efficiencies are critical in determining the environmental impacts and performance of each technology.

Key Findings from the Fact Sheet

Non-renewable energy payback time (NREPBT) is the period required for a renewable energy system to generate an amount of energy equivalent to the non-renewable energy used in its production. The study reveals an NREPBT of approximately one year for the evaluated PV systems, indicating a swift return on energy investment.

PV systems dramatically reduce greenhouse gas emissions compared to fossil fuel generators. The carbon footprint for producing 1 kWh of solar electricity ranges from 25.2 to 43.6 g CO2 equivalent, far lower than the up to 1 kg CO2 per kWh emitted by fossil fuels. The study also examines additional environmental impacts, including resource use of fossil fuels (0.35 to 0.52 MJ per kWh), resource use of minerals and metals (4.6 to 5.3 mg Sb equivalent per kWh), particulate matter (1.0 to 4.0 incidences per kWh), and acidification (0.18 to 0.36 mmol H+ equivalent per kWh).

When comparing current data with previous years, the study highlights significant reductions in greenhouse gas emissions by up to 17% in some technologies, thanks to improvements in manufacturing and an increase in module efficiency.

Conclusion

The detailed life cycle assessment methodology employed in this study provides valuable insights into the entire life cycle of PV systems, from manufacturing to end-of-life management. This holistic approach ensures that all environmental impacts are considered, enabling more informed decision-making for both policymakers and industry stakeholders.

Please download the Fact Sheet here.

IEA PVPS Task 12 aims to quantify the environmental profile of PV systems relative to other energy technologies and address critical environmental, health, safety, and sustainability issues to support market growth.

For further information please contact the IEA PVPS Task 12 Managers: Garvin Heath and Etienne Drahi.

World4Solar held a launch event at its warehouse in Miami, Florida to introduce HelioWing, a pre-constructed solar canopy structure.

The HelioWing is available in two base models, HelioWing 5 with 7.38 kWp and the HelioWing 7 with 9.84 kWp. The HelioWing 7 roof is made of 24 Aptos 400 W bifacial solar panels. The company uses Sol-Ark 12kW hybrid 2-phase inverters for its canopy.

The canopy design can be customized with features like storage capacity or a carport with a built-in EV charger. The modular energy systems come preassembled and preconfigured. The unit comes equipped with motion sensor LED light strips.

HelioWing 7 measures 22.7 feet by 22.4 feet by 13.10 feet and has a 500 square foot gap-free solar roof.

World4Solar noted that the canopy should take about six hours to install, when set up by a certified installer on a prepared foundation. The HelioWing can be used grid-tied or off-grid. To operate off-grid, or to store electricity for later use, battery packs are available ranging from 8.3 to 24.9 kWh.

Two available Level 2 chargers per unit work with all electric vehicles and add 25 miles average of range per hour of charging.

HelioWing is waterproof rated and has an average 20-year life span. The system comes with a 10-year warranty. The main structure is listed at MSRP $37,180, while the modules are priced at $5,044 and the inverters $6,825. A Tesla level 2 EV charger is priced at $1,625 while the battery system can range from about $7,500 to over $18,000 depending on products selected. The company also offers what it calls a “hurricane-hardened” canopy.

The New York Solar Energy Industries Association (NYSEIA) has issued a report to Governor Kathy Hochul, requesting a raised target for the state’s distributed solar targets.

NYSEIA specifically requested an increased target for the buildout of distributed solar projects, which are typically installed on rooftops, carports or other built-environment locations for homes and businesses.

Under New York’s current climate strategy, the state targets 10 GW of distributed solar by 2030. NYSEIA has called for this to be doubled five years later, reaching 20 GW by 2035.

NYSEIA projects achieving this goal would lead to $50 billion in gross electric bill savings; $3 to $4 billion in revenue for rural landowners, municipalities and school districts; and support an additional 15,000 jobs in the solar industry.

New York is a leader in distributed solar buildout. About 90% of the state’s solar capacity is distributed, a much higher percentage than solar heavy states like California and Texas that have invested heavily in large, centralized utility-scale projects.

New York added more than 800 MW of distributed solar capacity last year alone and is on track to surpass 6 GW by the end of 2024, one year ahead of schedule.

“Scaling up distributed solar deployment will deliver cost-effective progress toward New York’s overall climate goals while delivering immense benefits to New York’s environment, economy, and working families,” said Noah Ginsburg, executive director, NYSEIA.

In 2019, New York enacted the Climate Leadership and Community Protection Act (CLCPA), directing New York to be powered with 70% renewable energy by 2030, 100% renewable energy by 2040, and a carbon neutral economy by 2050. 

Since then, a wave of high-profile utility-scale renewable project cancellations has jeopardized the feasibility of achieving 70% renewable energy by 2030, said NYSEIA.

“As New York struggles to meet its ambitious renewable energy mandates, legislative leaders and regulators must take decisive action,” said Ginsburg.

In 2023, Governor Hochul enacted a 10-point action plan to get utility-scale renewable projects back on track. However, NYSEIA said while utility-scale projects are important, they are not enough to meet New York’s mandates. To double solar cumulative solar deployment in six short years, distributed rooftop solar can be deployed rapidly to fill the gap.

There is hope yet for New York to achieve its climate goals. Solar deployment has grown at an average 31% annual growth from 2013-2022. To reach the new 20 GW by 2035 goal, the state will need to sustain 7-10% annual growth in deployment. NYSEIA said this was driven in part by the state’s leading community solar program.

NYSEIA advocates for the following policy changes to achieve the goal:

• Interconnection reform and flexible interconnection to lower clean energy costs and accelerate deployment 
• Streamlined permitting for rooftop and community solar
• Virtual power plant programs and dynamic rate design to compensate distributed solar and energy storage for exporting power when and where it’s needed
• Continued investment in New York’s nation-leading community solar programs to provide even more direct bill savings to low-income New Yorkers

“Distributed solar has performed so well in New York because it fits the nature of our state,” said Senator Pete Harckham, chair of the environmental conservation committee. “We have a unique mix of urban, suburban, and rural communities that can support a diverse portfolio of renewable energy projects, and it’s time we lean into our character as a state.”

Find the full roadmap here.

From pv magazine Global

A new white paper from research and consulting firm Exawatt examines and contrasts key module parameters across various technologies to assess the potential value these technologies may offer for residential and commercial applications. The white paper, authored by Molly Morgan and Alex Barrows of Exawatt, draws on analyses from the company’s Solar Technology and Cost Service.

The paper reveals that, in the modelling performed, back contact (xBC), heterojunction (HJT), and tunnel oxide passivated contact (TOPCon) technologies may exhibit meaningful improvements in lifetime energy generation compared to mono passivated emitter rear contact (PERC) technologies. Through detailed modelling exercises, the document evaluates how xBC, HJT, and TOPCon contribute to increased clean energy generation and potential financial savings depending on specific system parameters.

In both residential and commercial system modelling scenarios, the authors found that xBC stands out as the top performer, showing an average increase of 16.0% over mono PERC, while HJT and TOPCon offer generation gains of 11.4% and 8.2%, respectively.

Furthermore, the white paper delves into the profitability of residential and commercial installations through assessments of payback time and levelized cost of electricity (LCOE). Despite their premium pricing, xBC, HJT, and TOPCon technologies demonstrate enhanced profitability in both modelling scenarios in comparison to the previously mainstream mono PERC. Among these technologies, xBC emerges as the frontrunner, boasting an average 9.7% shorter payback time and 10.7% lower LCOE across all modelled locations.

While small cost reductions may still be achieved in the current PV industry, the white paper outlines that these are relatively minor in comparison to the potential efficiency gains offered by advanced technologies. High module efficiency is key to driving down system cost-per-watt, payback time, and LCOE, since it can drive down the per-watt costs of many key non-module costs such as labor and mounting.

The white paper underscores the importance for distributors, installers, and system owners to grasp the value proposition of high-performance technologies for informed decision-making on which technology has the greatest value for a specific application.

The authors conclude that as the industry continues to prioritize performance improvements over cost reductions, embracing high-performance PV technologies can pave the way for enhanced efficiency, cost savings, and sustainable energy solutions.

The City of Detroit announced it has selected three sites for its Solar Neighborhoods initiative, which seeks to develop solar facilities on mostly vacant neighborhoods throughout the city. 

Detroit city-owned buildings use a collective 33 MW of electricity. The city seeks to meet all this demand with new solar projects distributed throughout the metro area. 

Phase one of the project will add 21 MW of capacity across the Gratiot Findlay, Van Dyke/Lynch, and State Fair neighborhoods. Lightstar Renewables was selected to develop 10 MW of the portfolio. Site maps can be found here. 

Under the agreement, the solar facilities will be operated for 25 to 35 years. When the arrays reach the end of their useful life, the contract calls for developers to remove the equipment and return the property to a green field.

A coalition of local nonprofits, environmental groups, energy experts and solar developers are participating in the program. The groups engaged in a several-months-long community engagement program to explain its benefits and reach residents. 

Projects are planned in mostly vacant neighborhoods. Residents located in the footprint of the proposed solar facilities are offered compensation equal to double the market value of their property (or $90,000 minimum) along with moving expenses and relocation services. Renters will receive 18 months’ worth of rent and relocation services. The initiative includes energy efficiency upgrades for surrounding homes, with a minimum value of $15,000 on average per home. 

Each acre contributed will be provided with up to $25,000 in community benefits for energy-efficient upgrades, prioritizing affected homeowners and renters within the solar array footprint. Neighbors can elect to install energy bill saving measures like new windows, roof repairs, energy efficiency, home insulation, smart thermostats, battery back-up, and residential solar panels. 

For the next steps, the Office of Sustainability, The Department of Neighborhoods, the program’s Neighborhood Solar Partners and the solar developers to work with the community and get their insight into how the sites will look and operate. There will be a negotiated and approved agreement between the developer and residents, which will include what the design, vegetation and maintenance will be for each solar neighborhood before any construction work begins. 

List of Neighborhood Solar Partners: 

Green Door Initiative  

EcoWorks  

D2 Solar  

MI Interfaith Power and Light  

Peace Tree  

Sustainable Community Farms  

Walker-Miller Energy  

Rescue MI Nature  

Manistique Community Treehouse Center  

Ryter Cooperatives  

First Family Solar  

Anti-Gravity, LLC  

SDEV  

Energy Alliance 

From pv magazine 6/24

Tariff and trade tensions, tempered by favorable industrial policies courtesy of the US Inflation Reduction Act (IRA), have prompted multiple solar and storage manufacturers to announce plans to set up facilities in the United States, some for the first time.

To date, most firms eyeing US ventures are in China, reflecting the global dominance of Chinese PV and storage companies. Companies based in India are in the mix, too, followed by European producers and a roster of businesses from across Southeast Asia and South Korea.

With all this interest comes the realization that many business practices that are considered normal in the United States, differ – sometimes in big ways – from other parts of the world. Take employee parking, for example. Companies based in parts of the world where private vehicle ownership is not the norm may look at the acres of car park space at US manufacturing sites and see wasted potential.

On the other hand, some non-US employers are surprised when they hear worker dormitories are not standard at manufacturing sites. Or that the open labor market, not a government ministry, is the primary source for workers. Some find it a foreign concept that most Americans are willing to commute a significant distance to a job they secured on their own.

Other cultural differences include the layers of decision-makers who need to sign off on manufacturing plants, the subtle differences between product and equipment standards, and the emergence in some parts of the United States of opposition to any investments by Chinese companies.

Location and equipment

Site selection provides another challenge. Many available buildings were originally built for warehouse or distribution purposes. Such operations typically use little energy, at least when compared with solar and battery production lines. Electrical service upgrades often become necessary, with upgrades sometimes required all the way to the substation. In other cases, new substations need to be built from scratch.

That means the prospective manufacturer must work with local utilities to secure upgrades. Sometimes this can be done relatively quickly, with the utility able to locate transformers within a year.

However, equipment acquisition often proves more difficult. In the case of transformers and related substation equipment, wait times of several years are becoming more common. That means a non-US manufacturer needs to be something of a utility expert, able to understand and work not only across multiple business types (investor-owned, cooperative, municipal, and so on), but also with regulated or unregulated regimes which vary by state.

Even when it comes to commonplace equipment such as a facility’s air conditioner, lead times of two to three years are increasingly reported for 40-ton units and larger. Fewer than a dozen suppliers exist that manufacture equipment of this size for the US market and each typically produces only a handful of units each week, to meet global demand.

Matter of standards

Even for European companies, different quality, certification, and manufacturing standards need to be addressed. That’s because companies working in the European Union typically are more familiar with the bloc’s CE mark for health, safety, and environmental protection. Products that have received the CE mark are not automatically UL (Underwriters Laboratories)-listed for sale in the United States. In part, this is because some product types with the CE mark do not have to be third-party certified and are not necessarily compliant with US standards.

Rarely does a one-to-one equivalency exist so qualification testing often needs to be performed for European products and equipment to be used in the United States.

A further layer of complexity often exists here. The certification must satisfy not a federal or state official but, in many cases, an official as local as a fire marshal. These local code administrators are instrumental in deciding whether every aspect of a facility complies with a host of safety standards. Only after a fire marshal signs off can a manufacturing plant be occupied and begin production.

Multiple logistical issues can also surprise non-US firms. For example, an industrial site in the middle of the country might look like an ideal solution and then be rejected because it is too far from a deepwater port, which adds to transportation expenses and delays. Or an industrial site close to a deepwater port on one of the coasts may have an unacceptably large risk of suffering natural disasters such as hurricanes and floods. A site in the fast-growing and sunbaked Southwest of the United States may lack access to long-term, reliable water supplies.

Managing differences

Any company looking to base itself in the United States should develop a set of qualifying categories that rank the importance of a range of inputs, from available real estate to utility service upgrades to workforce availability, as they pertain to specific projects.

One outcome of such an exercise is that it’s rare for two seemingly similar businesses to favor the same site, let alone the same state. While many factory projects look the same from the outside, their specific needs can be quite different. One emerging factor is the policy – written and unwritten – in some states that discourages Chinese-owned factories. There are still states that welcome Chinese ownership, however.

At the federal level, there is the No Official Giveaways of Taxpayers’ Income to Oppressive Nations (NO GOTION) Act. This is a bill in the House of Representatives that would prohibit companies affiliated with certain regimes around the world from benefiting from IRA tax credits. It is likely that companies that have begun manufacturing prior to the bill’s passage will be affected differently.

Renewed interest in, and support of, domestic US solar manufacturing is opening attractive opportunities for foreign-based companies to set up production lines. Cultural differences exist, however, and need to be proactively addressed to help ensure a project’s profitability.

About the author: Mark Hagedorn is the vice president of manufacturing services for Clean Energy Associates.

The Renewable Energy Test Center (RETC) released its 2024 PV Module Index report, evaluating the reliability, quality, and performance of solar panels.

Solar modules are put through a variety of accelerated stress tests to evaluate these parameters. Through comparative test results, project stakeholders can select products best suited for a particular environment, location, or portfolio.

To identify the best of the best, RETC reviewed and ranked the overall data distributions across three disciplines: quality, performance, and reliability. Find the overall top performers at the end of this report.

Reliability

Backsheet ultraviolet durability

Top performers: JA Solar, Longi Solar, SolarSpace

Backsheet ultraviolet durability (BUDT) incorporates a durability testing sequence to probe glass-on-backsheet PV module designs for vulnerabilities to UV exposure and prevent backsheet-related failures. This BUDT sequence starts with 1,000 hours of damp heat exposure to weaken polymeric bonds.

Highlighted top performers experience no backsheet cracking in the test.

Damp heat test

Top performers: Astronergy, ES Foundry, Longi Solar, Runergy, and Trina Solar

The RETC thresher test includes a damp heat test that exposes modules for 2,000 hours, double the amount required for product certification. The test evaluates a module’s ability to withstand prolonged exposure to humid, high-temperature environments. Taking place inside an environmental chamber, the test exposes modules to a controlled temperature of 85 C (185 F) and a relative humidity of 85% for a set amount of time.

RETC highlighted performers that experienced less than 2% degradation after this exposure.

Hail durability

Top performers: JA Solar, Longi Solar

RETC’s hail durability test takes UL and IEC standards testing a step further, exposing solar modules to higher kinetic impact to reflect the risk posed by hail over a 25 or 30-year operating life. In addition to ballistic impact testing, RETC runs thermal cycle and hot-spot tests to reveal potential long-term module degradation.

The top performers in this category withstood an effective kinetic energy of 20 Joules or more. These modules effectively demonstrated resistance to a 45 mm (1.8 in.) iceball traveling at a terminal velocity of 30.7 m/s (68.7 mph).

Potential induced degradation (PID) 

Top performers: Astronergy, ES Foundry, GEP VN, Gstar, JA Solar, Longi Solar, Qcells, REC Solar, Runergy, SEG Solar, Silfab Solar, SolarSpace, Talesun, Trina Solar, VSUN Solar, and Yingli Solar

Potential induced degradation (PID) resistance tests rack-mounted modules in an environmental chamber, which controls temperature and humidity and exposes them to a voltage bias of several hundred volts with respect to the mounting structure for 192 hours (PID192 exposure). PID testing characterizes a module’s ability to withstand degradation due to voltage and current leakage resulting from ion mobility between the semiconductor and other elements in module packaging.

RETC required that PV module models withstand PID192 exposure with less than 2% degradation in maximum power. At the other end of the spectrum, it considered maximum power degradation greater than or equal to 5% a red-flag result.

Static and dynamic mechanical load test

Top performers: Aptos Solar, Astronergy, ES Foundry, Gstar, JA Solar, Longi Solar, Runergy, Silfab Solar, SolarSpace, Trina Solar, and Yingli Solar

This test exposes modules to 1,000 cycles of +1,000 pascal and –1,000 pascal loads at a frequency of three to seven cycles per minute. Measurements were taken after this stress test rate electrical performance.

This year, RETC required that PV module models withstand SDML exposure with less than 2.5% degradation in maximum power. It considered maximum power degradation greater than or equal to 5% to be a red-flag result. In this testing category, it notes that 68% of samples qualified as high achievers whereas 7% returned red-flag results.

Thermal cycling

Top performers: Aptos Solar, Astronergy, ES Foundry, Gstar, JA Solar, Longi Solar, Qcells, Runergy, SolarSpace, Trina Solar, and Yingli Solar

The thermal cycle test calls for cycling modules in an environmental chamber between two temperature extremes—85 C (185 F) on the high end and –40 C (–40F)  on the low end. The RETC test runs 600 cycles, three times as much as the 200 required for certification.

About 67% of modules in this test achieved high performer status of less than 2% power loss, while 9% of tested brands had power losses of 5% or more.

Ultraviolet induced degradation (UVID)

Top performers: Trina Solar and VSUN Solar

UVID tests characterize a PV module’s ability to withstand ultraviolet induced degradation. This optional testing sequence exposes test samples to 220 kWh/m2 of UV exposure (UV220), nearly 15 times the UV exposure required for product certification.

Top performers withstand UV220 exposure with less than 2% degradation in maximum power. Red flag modules that degraded more than 5% represented 40% of brands tested.

“Alarmingly, we observed double-digit power loss in some mass-produced, commercially available PV modules, indicating that these products could degrade 10%–16% in the first three years of in-field operation,” said RETC.

Performance

Module efficiency

Top performers: Astronergy, Mission Solar, Qcells, REC Solar, and Silfab Solar

Module conversion efficiency is determined by dividing a product’s nameplate maximum power rating under standard test conditions by its total aperture area.

RETC has recognized manufacturers of PV module models with conversion efficiencies greater than 21% as test category high achievers. About 56% of tested modules were listed as high performers.

Incidence angle modifier

Top performers: Dehui Solar, ES Foundry, JA Solar, JinkoSolar, Longi Solar, Meyer Burger, Qcells, Runergy, Silfab Solar, and SolarSpace

Incidence angle modifier (IAM) is a performance characteristic that accounts for changes in PV module output based on changing sun angles relative to the plane of the array. To characterize IAM, RETC conducts electrical characterization tests at different incidence angles, ranging from 0° to 90°.

Manufacturers of PV module models with an IAM greater than 88% at a 70° angle of incidence were listed as test category high achievers.

LeTID resistance

Top performers: Astronergy, Gstar, JinkoSolar, Longi Solar, Runergy, SEG Solar, Silfab Solar, SolarSpace, Talesun, Trina Solar, VSUN Solar, Waaree, Yingli Solar

Relatively new cell technologies may experience long-term degradation associated with light exposure and elevated temperatures. This phenomenon, called light- and elevated temperature-induced degradation (LeTID), is tested with a protocol of light soaking, followed by 75 C (167 F) temperature exposure for two 162-hour cycles to identify significant degradation (>5%). Subsequently, test samples are subject to 500 hours of 75 C temperature exposure followed by two additional 162-hour cycles.

Highlighted top performers demonstrated products that had less than 0.5% power loss after 486 hours of exposure.

LID resistance

Top performers: Astronergy, GEP VN, Gstar, JA Solar, JinkoSolar, Longi Solar, Meyer Burger, Qcells, Runergy, SEG Solar, Silfab Solar, SolarSpace, Talesun, Trina Solar, VSUN Solar, Waaree, and Yingli Solar

Light-induced degradation (LID), or power losses from sunlight exposure, affects some PV cell types but not others. PV modules exposed to LID losses rapidly lose performance over the first few hours or days of operation before stabilizing. RETC notes LID resistance is highly correlated with cell type.

RETC required that PV module models withstand the LID sequence with less than or equal to 0.5% degradation in maximum power.

Module efficiency

Top performers: Auxin Solar, JA Solar, Longi Solar, Meyer Burger, Mission Solar, Qcells, REC Solar, Silfab Solar, Trina Solar, Yingli Solar

Module efficiency, or the percentage of incident solar energy converted to electrical energy, is a well-known and key metric for solar performance. It is highly correlated with cell technology and module design.

The top 14 highest scoring modules scored efficiencies of 20% or more. An n-type TOPCon cell scored the highest at 25.8% efficiency, followed by a monocrystalline silicon module with heterojunction technology, recording a 22.4% efficiency.

PAN file

Leading residential solar industry financers and the Solar Energy Industry Association (SEIA) are partnering with the newly launched Recheck, a platform designed to create a registry of residential solar salespeople and vet their conduct.

Residential solar has long struggled with aggressive sales tactics that has led to negative customer experiences. Many installers outsource their sales efforts to a third party, which can create a disconnect between sales promises and installation realities.

The platform was launched by a consortium of the main players in U.S. residential solar finance, including Dividend Finance, Freedom Forever, GoodLeap, Mosaic, Palmetto,  Sungage Financial, Sunlight Financial, and Sunrun.

“A healthy solar industry is vital to consumers and the U.S. energy transition. Recheck is proud of its founding partners and is committed to building the tools to ensure long-term trust with consumers,” said Tim Trefren, Recheck co-founder and CEO.

Recheck creates an online registry of approved solar salespeople, issuing a Recheck ID that allows contractors, financiers, and technology platforms to confirm that their sales partners meet certification, licensing, and training requirements.

The platform marks a first-of-its-kind opportunity for solar finance, contractor, and technology partners to track sales conduct across the industry.

Recheck will also facilitate industry-wide data exchange across the platform. The data will businesses vet sales partners, prevent poor practices by unregistered salespeople, and identify individuals with a history of consumer protection violations that move from company to company.

“Solar remains America’s most popular form of energy and will be installed on 10 million homes by 2030. It’s our job to make sure the solar and storage industry is accountable to the millions of families that are putting their trust in us to power their lives,” said SEIA president and chief executive officer Abigail Ross Hopper.

Recheck founding partners will be part of an ongoing advisory board and have committed to driving the adoption of Recheck IDs within their platforms in 2024 and beyond.

Along with supporting the launch of Recheck, SEIA is developing industry wide standards for residential solar, with accreditation from the American National Standards Institute. SEIA is proactively tackling issues that build confidence among customers, regulators, investors, rating agencies, and other stakeholders. These standards will contribute assurance that solar and storage systems have been ethically, sustainably, and responsibly sourced, manufactured, transported, installed, operated, and recycled.

In Europe, there are still large stocks of modules produced in 2023, or earlier with distributors and installers themselves. If these have the smaller dimensions commonly used for rooftop systems in Germany, they are selling poorly due to low power output classes. Building owners usually want to see a high wattage and the latest technology installed in their systems, which makes it much more difficult to sell existing inventory.

Despite the supposed reduction in module production, and European import volumes, it appears that more Asian panels are still reaching the European market than are currently in demand. This, in turn, is causing inventories to grow, even in high-performance classes, exerting additional pressure on module prices, especially on old modules which were produced and purchased at significantly higher prices.

The ability to devalue old stock varies greatly from company to company, resulting in vastly different prices for modules with passivated emitter rear contact (PERC) cell technology. The overall price differences between model categories is shrinking.

Shelf warmers

It is very difficult to get rid of these older modules in markets outside Europe without accepting a massive loss in value. Africa and Southeast Asia are also likely to be oversaturated with modules and Chinese-made products cannot easily be sold to the US market. One strategy that is becoming increasingly established is to enable concessions in the soft factors of the trade business. There can be some room to move in payment and delivery terms. Instead of offering the modules at a lower price, a credit line is granted – often without requiring collateral – and delivery can be offered for free. That said, it is doubtful that this tactic will work over the long term. Many smaller companies are on the brink of insolvency and the possibility of defaults cannot be ruled out. The pressure to sell should, therefore, not override common sense and tempt providers to take incalculable risks.

Some suppliers are also attempting to take refuge in online marketplaces where they hope to sell quickly to international customers without incurring sales and marketing costs. However, the competitive pressure there is also high and the goods can often only be sold at dumping prices.

Online business models come with further risk. They seldom provide solid opportunities to get to know the potential business partner in advance – sellers just take what they can get. Misunderstandings can arise in business transactions, especially across national borders and the platform operator is not always available to provide support and advice. The effort involved in an online transaction can quickly become greater than buying or selling within an established business relationship. Everything can go smoothly but that does not necessarily mean that it will.

Notes: Only tax-free prices for PV modules are shown, with stated prices reflecting average customs-cleared prices on the European spot market. Source: pvXchange.com

Project sales

One possibility for making good use of surplus old solar modules is to install them in larger open-space projects or rooftop systems. Smaller formats may not be a bad choice in areas with higher wind or snow loads. Although the material and installation costs increase slightly, easier handling during installation makes up for this disadvantage. There is another undeniable advantage here – that the modules are already in stock. This guaranteed availability means there can be no ­delivery problems and therefore no delays in the construction process. Add in a few unsold inverters and cable reels and the components are in place for a working PV system.

Once a system has been installed and connected to the grid, nobody will care whether the solar modules belong to the very latest generation or not. The resulting asset can then be marketed better than the 400 W PERC modules in the current market situation. This can also be done via an online brokerage portal, for companies not yet properly set up for project sales.

About the author: Martin Schachinger has a degree in electrical engineering and has been active in PV and other renewables for almost 30 years. In 2004, he founded online trading platform pvXchange.com, enabling wholesalers, installers, and service companies to buy solar panels, standard components, and inverters that are no longer manufactured but which may be urgently needed to repair defective PV plants.

Glass is a unique material used for its chemical stability and visual transparency. It is commonly used in solar panels as a protective outer layer.

In its annual PV Module Index, the Renewable Energy Test Center (RETC) examined emerging issues in solar glass manufacturing and field performance. It found reports of a concerning rise in solar panel glass spontaneously breaking in the field, sometimes even before commissioning.

Teresa Barnes, Ph.D., manages the Photovoltaic Reliability and System Performance Group at the National Renewable Energy Laboratory (NREL). Barnes and her colleagues at NREL reported the issue.

“Spontaneous glass breakage is an example of a failure mode that we didn’t used to see. When I first started working on solar module reliability seven or eight years ago, we mostly heard about glass breakage when there were sloppy operations and maintenance practices,” said Barnes.

Now, this is no longer the case, and the NREL reliability team is regularly receiving reports of glass breakage in silicon modules unrelated to direct damage from maintenance or storm impacts. The team found that over time, the average quality of solar glass appears to be decreasing.

“It used to be the case that modules would pass the IEC 61215 static load test with a big safety factor,” said Barnes. “Today, modules are either barely passing the base static load test or they are not passing with higher safety factors. Some new module designs are simply not passing the minimum static load test.”

The NREL team has begun to hypothesize that glass damage in solar panels is undergoing a similar process to a car windshield in need of replacement. When a windshield takes impact damage, often it only shows up as a small star-shaped mark that seems insignificant. But when extreme weather conditions with very high or low temperatures cycle through, the severity of the damage is fully realized, and suddenly a large crack is visible across the whole surface.

“We think a similar dynamic could be a root cause of spontaneous solar glass breakage,” said Barnes.

This rise in breakage is likely due to the trend solar glass getting thinner over time, said NREL. Mike Pilliod from Central Tension, who spoke at NREL’s 2024 PV Module Reliability Workshop said any manufacturer can temper glass that is 3 mm. But under 3 mm, glass tempering is a difficult process. He said that as glass gets thinner, it takes fewer defects to create strength-limiting flaws in the glass. These flaws are actively being studied by NREL to understand some of the potential pitfalls of using thin glass in solar manufacturing.

Barnes warned that it may be a combination of effects that are making glass breakage a larger threat that before. Modules are getting larger, frames are getting thinner, and mounting rails are getting closer together. All these factors lead to “large, floppy modules” that are putting more pressure on the glass surface, which is also getting thinner in many modules.

The NREL team said at this year’s PV Module Reliability Workshop, manufacturers began speaking about introducing thicker frames and wider mounting positions.

“As people better understand how the module system interacts, they can work to optimize how loads are balanced out,” said Barnes. “The pendulum in that balancing act may already be swinging back toward the integrity of the frame and the mounting rail.”

While some module providers are focused on frames and mounting, others have introduced tempered glass modules that are marketed as hail-hardened and resilient to extreme weather.

RETC asked Barnes about the recent catastrophic losses in Texas, where hailstorms caused hundreds of millions of dollars in damage to operational solar assets.

GCube Insurance, an underwriter for renewable energy, said despite being only 1.4% of total number of insurance claims filed, about 54% of incurred costs of total solar losses can be attributed to hail. This is based on data collected by Gcube over the past five years. Average costs totaled $58 million per claim.

“Ten years ago, people would run you out of the meeting on a rail if you mentioned climate-specific module designs. The consensus was that this would simply be too expensive,” said Barnes. “Now climate specific modules and climate-specific testing are starting to look viable because we are seeing more of an emphasis on total system costs. It is entirely possible that we could see hail-hardened modules, especially in a market like the United States, where it could be worth paying more up front for hail resilience.”

From pv magazine Global

The Global Polysilicon Marker (GPM), the OPIS benchmark for polysilicon outside China, was assessed at $22.567/kg this week, unchanged from the previous week on the back of buy-sell indications heard. The price has held steady for four consecutive weeks.

According to a source knowledgeable about the polysilicon market outside of China, the trading status of global polysilicon in the spot markets is currently largely stagnant, with buyers awaiting the preliminary ruling from the U.S. anti-dumping and countervailing duties investigations expected in July.

A major global polysilicon buyer reported receiving spot prices from certain sellers lower than long-term agreement prices for the same specifications. However, due to uncertainty in US trade policy, they have refrained from placing an order.

This information was corroborated by a global polysilicon supplier, who expressed concern: “We are worried about inventory accumulation.”

Nevertheless, there are still optimistic voices lingering in the market, with sources reporting ongoing positive sales experiences. One of the sources explained that the solar supply chain features three distinct supply-demand relationships: between polysilicon and wafers, wafers and cells, and cells and modules.

“It’s argued that applying the current pessimism from the module market to the global polysilicon market is unjustified,” the source added. “Only the relationship between polysilicon and wafers directly influences the pricing of global polysilicon, which has been proven to be stable without notable fluctuations.”

China Mono Grade, OPIS’ assessment for polysilicon prices in the country, remained steady at CNY33 ($4.54)/kg this week, marking the fourth consecutive week of stability.

The market participants generally believe that current polysilicon prices do not need further reduction, as it would not significantly stimulate sales. Wafer companies are constrained by their operating rates and cash flow, limiting their ability to accelerate polysilicon procurement. “We are currently facing a loss of approximately 0.20 yuan for every piece of wafer produced,” a major wafer producer disclosed.

Multiple sources have confirmed that while nearly all Chinese polysilicon manufacturers are undergoing equipment maintenance, production cuts, or shutdowns, one major manufacturer is operating at full capacity with a 100% operating rate.

As a result, this company is incurring a monthly loss of CNY600-700 million in the polysilicon manufacturing segment, a source commented, noting that due to the factory’s large production capacity, operating at full capacity will keep overall polysilicon inventory levels high, casting uncertainty over the prospects for polysilicon prices.

Sources indicate that in addition to operating at full capacity, the company’s new production capacity is also ramping up as scheduled. This strategy underscores the company’s robust cash flow and its intent to leverage scaled capacity and cost advantages to squeeze the survival space of smaller companies in the ongoing price war.

According to an industry watcher, the current situation of selling polysilicon at a significant cash loss is unsustainable. By the end of the year, prices are expected to stabilize slightly above the average cash cost in the market, the source noted, who further anticipates that at that point, some excess production capacity, particularly high-cost or outdated facilities, will likely be phased out effectively.

OPIS, a Dow Jones company, provides energy prices, news, data, and analysis on gasoline, diesel, jet fuel, LPG/NGL, coal, metals, and chemicals, as well as renewable fuels and environmental commodities. It acquired pricing data assets from Singapore Solar Exchange in 2022 and now publishes the OPIS APAC Solar Weekly Report.

Planted Solar, a solar startup out of Oakland, California, received $20 million in Series A funding from the Bill Gates Breakthrough Energy Ventures and Khosla Ventures, as well as Department of Energy Funds to scale its terrain-following solar installation design.

The company installs its arrays like a sheet, densely packed together, rather than using typical row spacing. Instead of developing the land to be flat and uniform, the company’s solar mounts follow the terrain, tolerating up to a 27% slope. This helps reduce land development costs and allows for more energy-per-acre.

This may prove important, as the U.S. Bureau of Land Management forecasts the country will need 22 million acres for solar project deployment.

“In comparison to south-facing fixed tilt and tracker designs, a Planted array provides a comparable kWh/kWp yield when using a higher inverter loading ratio (ILR) and is substantially lower in cost of structural balance of system and installation, reduces the amount of civil work and civil risk, and requires a lot less land,” said Planted Solar.

The company said its design allows for a megawatt of solar to be installed on only two acres, less than the five acres typically required for a megawatt of solar capacity. Its simple terrain-following mount leads to a 50% reduction in balance of system costs and fewer installation hours.

“This adds up to a system with a lower build cost, higher DC system size, and similar annual kWh production,” said the company.

The terrain-following mounts are compatible with all conventional module formats and sizes, said the company.

After completing the design phase, the company uses installation robots to deploy the solar panels, which it said reduces installation time and costs. Planted Solar said its design mitigates impacts like erosion on the developed land, which is explained in a whitepaper.

“Planted’s low-impact approach to fixed-tilt solar PV foundation and table installation is novel in its automation, low impact/low disturbance, and tolerance to using existing ground conditions without grading. Furthermore, the low-area cross section of the Planted foundation legs should reduce local scour when compared to traditional pile. Installing using Planted’s methodologies will reduce disturbance and resultant hydrological and hydraulic impact to a site versus traditional installations of solar arrays,” said Planted Solar.

Planted Solar chief executive officer Eric Brown said it is rapidly “moving from pilots to portfolios.” The company announced it was selected for an 11 MW portfolio of projects in the Chicago area with Cultivate Power.

“Planted Solar gives our team a strategic tool to be stewards of the land and develop better projects with our community partners,” said Brian Matthay, co-founder and managing director of Cultivate Power. “Cultivate is focused on collaborating with landowners and communities so we can integrate solar seamlessly with the local environment and agricultural operations.”

Wood Mackenzie and American Clean Power released its quarterly Energy Storage Monitor report, finding that the U.S. storage market posted strong growth in the grid-scale and residential storage sector, while the commercial and industrial sector retracted significantly in Q1 2024. 

The grid-scale market installed 993 MW / 2,952 MWh of storage, with California, Texas, and Nevada responsible for 90% of the total. This was a record quarter for grid-scale storage, growing 84% year-over-year over Q1 2023. The enormous backlog of grid-scale storage with interconnection applications has grown 10% year-over-year, with 426 GW of storage in the queue nationwide. 

Costs declined considerably year-over-year, with grid scale storage averaging $1,776 per kWh in Q1 2023 and falling 39% to $1,080 per kWh in 2024. The grid-scale segment is projected to see a 45% increase year-over-year in 2024 with 11.1 GW/31.6 GWh installed, bringing total cumulative volume in the next five years to 62.6 GW/219 GWh.

About 250 MW / 515 MWh of residential storage was installed, posting a slight increase of 8% over Q4 2023. Interestingly the residential solar segment grew 48% on a MW capacity basis year-over-year for Q1. 

California tripled its number of residential storage installs year-over-year for Q1. Batteries were attached to 41% of installed solar arrays in California, suggesting there is still a lot of room for growth, said Wood Mackenzie. High interest rates continue to drag down the residential solar and storage market, increasing the amount of third-party owned systems like leases and power purchase agreements (PPA). 

Wood Mackenzie forecasts that 13 GW of distributed storage will be deployed over the next five years. The residential segment will constitute 79% of distributed power capacity installations, said the report. It said that more residential storage will come online as costs decrease and the value of exporting rooftop solar mid-day decreases as well. 

Despite growth in other sectors, the commercial, community and industrial market had its worst quarterly deployment total in years. The California market has remained stagnant as most systems installed are under Net Energy Metering 2.0, and New York and Massachusetts have had down quarters. 

“The CCI segment continues to see the highest barriers to growth in the near-term, but its strong value proposition and emerging value streams will make it an exciting growth segment in the later years of our ten-year forecast,” said Wood Mackenzie. 

Across all segments, Wood Mackenzie expects 12.9 GW / 35.8 GWh of storage to be installed in 2024. In its quarterly report, the firm raised its five-year forecast for grid-scale installations by 5% and residential sector installations by 8%. The five-year commercial, community, and industrial forecast was cut by 34% after the California Public Utilities Commission (CPUC) made an unfavorable ruling on community solar.

Looking ahead, Wood Mackenzie expects 75 GW / 251 GWh to be installed through 2028.

“The rapid growth of the energy storage industry comes at a critical time, providing a solution to growing energy demand and increasingly variable weather conditions that are placing added stress on the grid.” said John Hensley, vice president of markets and policy analysis at American Clean Power, “A strong start to 2024 sets expectations high for the remainder of the year.”

Read more energy storage news coverage on the new pv magazine energy storage platform.

This article was amended to correct MWh to KWh in reference to declining costs.

From pv magazine 6/24

The Invesco Solar exchange-traded fund (ETF) underperformed compared to other stock indexes in April 2024. The solar ETF was down 11% and the S&P 500 and DJIA decreased 4%. That fall followed a 3% gain for the Invesco Solar ETF in March 2024.

The top three performing April 2024 solar-related stocks in the United States were Atlantica Sustainable Infrastructure plc, up 5%; First Solar, Inc. up 3%; and Clearway Energy, Inc., up 1%. The three worst were Maxeon Solar Technologies, falling 39%; Daqo New Energy Corp., down 32%; and SunPower Corp., down 29%.

Residential solar stocks dropped 18% in April 2024, having dropped 2% in March 2024. This extended the 2024 fall for residential solar stocks to 44%. The companies in this measure are Enphase Energy Inc., SolarEdge Technologies., Sunnova Energy International Inc., and Sunrun Inc.

The situation was similar for utility scale solar equipment stocks, down 15% in April 2024 and 22% year to date. The companies in this measure are Array Technologies Inc., Shoals Technologies Group Inc., NEXTracker Inc., FTC Solar Inc., and First Solar Inc.

Independent power producers (IPP) fared better than utility scale or solar stocks. IPPs were down 8% for April 2024 and 22% year to date. This was despite poor performances from Emeren Group Ltd. (-22%) and Altus Power, Inc. (-24%).

The U.S. solar industry is experiencing a gray market for discounted Enphase products, fueled by large installers and rising competition from other microinverter brands. Chinese manufacturers are pricing and financing utility scale battery storage, challenging international firms.

For utility scale projects, rising module prices and uncertainty about retroactive duties are causing delays. Some firms have reassessed plans. Distributors are hesitant to take on new stock, leading to slower inventory clearance, contributing to market disruption. Within the IPP sector there has been an uptick in merger and acquisition activity, however.

From pv magazine 6/24

AD/CVD tariffs for US-imported solar components from Vietnam, Malaysia, Thailand, and Cambodia have been paused since 2022. Should they resume, tariffs of between 50% and 250% of the cost of shipped goods would apply to components from China that are found to have been dumped in the affected Southeast Asian nations for import to the United States.

The tariff moratorium is set to expire in June 2024 and a new AD/CVD investigation has been launched. A petition signed by the American Alliance for Solar Manufacturing Trade Committee coalition was filed in late April 2024 and, on May 15, 2024, the US International Trade Commission and the Department of Customs announced an investigation would be launched into suppliers from the four Southeast Asian nations.

Petition filers

Companies that signed the petition include First Solar, Qcells, Meyer Burger, REC Silicon, and others that have invested in US solar manufacturing capacity. The petitioners said the US solar “manufacturing renaissance” was threatened by heavily subsidized Chinese cells and modules.

“China’s unfair and illegal trade practices have inundated the market with dumped solar panels, undercutting the US ability to compete,” said the group. Solar module prices have fallen by more than half over the last 12 months to a record low, according to online solar trading platform pvXchange.

If US solar developers sourced 55% of solar goods domestically, 900,000 US jobs would be supported by 2035, said the petitioners. They added that “onshoring” the solar supply chain would cut solar manufacturing emissions by 30%.

Difficult position

With almost 80% of US solar modules imported from Vietnam, Malaysia, Thailand, and Cambodia, trade measures could threaten supply.

The US Energy Information Administration said the threat of AD/CVD tariffs in 2022 had prompted delays or the cancellation of around 20% of utility-scale solar generation capacity.

Investment bank Roth Capital has been told a “non-trivial amount of [solar] projects that have not secured modules, especially for 2025,” could be affected by AD/CVD measures. Projects that have already secured modules through 2025 should be unaffected.

AD/CVD action could drive US module prices for utility-scale projects to $0.40/W to $0.50/W of panel generation capacity, Clean Energy Associates (CEA) told a Roth Capital webinar. Late 2023 saw such module prices fall to a record low $0.13/W and CEA estimated Southeast Asian imports would remain at around $0.20/W without new AD/CVD action.

CEA anticipates new AD/CVD measures could cause a bottleneck of duty-free PV cells and flip an oversupplied solar market into shortages. The company estimated the 18 GW of annual crystalline silicon cell production capacity outside AD/CVD-investigated nations in early 2024 – plus 17 GW of US-based thin film capacity – would be less than projected US demand in 2024.

“This means that there will likely be duties applied to some of the modules serving the US market – or the cells imported to make these modules – starting later this year,” said CEA. “This is likely to greatly reduce import levels, as occurred in the second quarter of 2022 when the anti-circumvention case was filed. If these duties are passed along to buyers, they will introduce uncertainty to the financial models that projects depend on. This will potentially cause projects to be delayed, canceled, and/or sold.”

Crunch time

With the US International Trade Commission investigation launched, a preliminary determination of material injury, or the threat of material injury to domestic manufacturers must be determined within 45 days of the filing, from May 15, 2024. A final determination would likely be made by spring 2025.

Canadian Solar, a leading solar panel supplier with operations in Southeast Asia, responded to the investigation by calling into question South Korean owned company Qcells’ status as a US manufacturer. It said that the company is a “US importer of subject merchandise” and “primarily a foreign producer.”

Qcells, which primarily manufactures in Malaysia, is also the largest crystalline silicon module producer in the United States, manufacturing around 5.1 GW of modules there annually. The company said in early 2023, that it plans to invest more than $2.5 billion in 3.3 GW of solar ingot, wafer, cell, and module factories in the US state of Georgia.

Since the passage of the US Inflation Reduction Act in 2022, which contained rich incentives for clean energy manufacturing, multinational solar manufacturers have begun to move operations into the United States. In 2023, Trina Solar, Canadian Solar, and Longi all announced 5 GW solar module manufacturing facilities, potentially adding a combined 15 GW of US-based solar production capacity. To put that investment into context, each of those factories would represent $200 million to $600 million in capital expenditure. Many gigawatt-scale US factory announcements have been made by global suppliers since then, with many new fabs and expansions announced over the past two years.

Capacity mismatch

Much of the announced capacity in the United States concerns the final step of the solar module supply chain: module assembly. If the United States wants to establish an independent solar supply chain, it will need to incentivize the production of polysilicon, solar ingots, wafers, and solar cells, in order to feed this module demand.

CEA said there is currently a mismatch in US production capacity, with much of the focus on module assembly. The company expects around 30 GW of annual module manufacturing capacity in the United States by 2027 but only 3 GW of ingot and wafer lines and 17 GW of polysilicon facilities.

A pair of bills that would establish rules for a community solar market are working their way through the Michigan legislature. If passed, Senate bills 152 and 153 of 2023 would enable customers to subscribe to off-site solar facilities, paying a monthly rate for electricity generated by the project in exchange for offsets on their utility bills.

The legislation would require all customer classes to have access to community solar subscriptions, and it would contain a carve-out that ensures at least 30% of the electricity produced is serving low-income households or low-income service organizations.

The bill would also provide for the transferability and portability of subscriptions, including a subscriber’s retention of a subscription to a community solar facility if the subscriber moves within the same electric provider’s service territory.

Senator Ed McBroom, a Republican serving Waucedah Township, said the legislation would allow Michigan residents to “escape the ever-increasing rates” from electricity providers.

“As we’ve shackled our residents to fossil fuels and a limited system that requires them to go through providers, the rates have just gone up and up and up and up and up,” said Senator Jeff Irwin (D–Ann Arbor).

Michigan’s electric utilities have opposed the bill.

“Unfortunately, this legislation completely misses the mark while putting Michigan’s clean energy transformation at risk and raising costs for everyone,” said Tracy Wimmer, a spokesperson for utility Consumers Energy.

Consumers Energy has its own internal “community” solar program that is utility owned and managed. The proposed solar legislation would destroy its monopoly control of the market.

The need for non-utility-run community solar projects has more implications than fighting a monopoly and securing rates. It will also enable Michigan to access federal funds as part of the $7 billion Solar For All program, which requires community solar projects to be owned independently from utilities for program eligibility.

(Read: “Calculating potential impact of EPA’s $7 billion Solar for All program”) 

“Without a community solar enabling policy here in Michigan that allows independently owned projects, we will be leaving a key policy lever off the table on our ability to take full advantage of the Solar for All funding and provide the energy cost-saving benefits to residents that true community solar provides,” said Tim Minotas, deputy legislative director, Sierra Club Michigan. 

Track the bills’ progress for Senate Bill 152 and 153.

Titan Solar Power, a residential solar installer founded in 2013 in Arizona, sent an email to its employees informing them it has failed to sell the company to prospective buyers and will close its doors permanently.

Titan was among the largest residential solar installers in the nation, with tens of thousands of installations across 16 states. It grew quickly through its Solar Dealer program, a network of partnerships with sales organizations that sold Titan services, while Titan focused on installations. The partnership was based on a pricing model where Titan charged a fee for completing the project, and dealers retained the remaining balance as sales commission.

“Despite these achievements, the company faced criticism over its business practices, workmanship, and customer service, leading to numerous negative reviews and legal disputes,” said Ara Agopian, chief executive officer, Solar Insure.

Solar Insure, a leading residential solar insurance provider, said the reliance of third-party dealers for sales created a layer of separation from Titan and its customers, leading to communication gaps and inconsistent service experiences. The insurance provider maintains a list of solar bankruptcies and business closures here.

Titan said it had been negotiating with a potential buyer for six months, and the deal fell through on June 11, causing management to make the decision to close operations. Solar Insure said the Federal Reserve’s rate hikes to combat inflation inadvertently impacted the solar sector by making borrowing more expensive. This led to decreased consumer demand for solar energy systems, as higher borrowing costs diminished the appeal of solar as a cost-saving investment.

The higher interest rate environment has led to increased cost of capital for installers, increased risk in solar lending packages and strained operating cash flows. This difficult financial environment was made worse by policy changes in key markets like California, which cut solar export compensation rates in its move to Net Energy Metering (NEM) 3.0.

Solar Insure said that while Titan’s dealer network business model was lucrative, it proved to be a double-edged sword. The sales organization dealers’ primary motivation was to maximize their commissions, which sometimes led to aggressive sales tactics and overselling of systems without adequate consideration for the customers’ specific needs, it said.

“This disconnect between sales promises and installation realities further strained Titan’s resources and customer relations. As economic conditions tightened and borrowing costs increased, the financial pressure on both Titan and its dealers intensified, exacerbating cash flow issues and operational inefficiencies,” said Agopian.

Customers of Titan Solar are now left in a situation where their 25-year workmanship warranty is now void. Solar Insure offers a program called Solar Detect, designed to assist homeowners abandoned by a bankrupt solar contractor with long-term maintenance service contracts.

Find more pv magazine USA reporting on the series of residential solar bankruptcies and business closures.

Maxeon Solar Technologies conducted a competitive assessment of its Interdigitated Back Contact (IBC) solar panels, finding confirmation of their resilience against damaging hotspots.

The company has developed its IBC solar panels for 40 years. It tested its Maxeon 7 line of panels against a series of competing technologies including half-cell ribbon-based back contact, half-cell heterojunction (HJT), and half-cell front contact tunnel oxide passivated contact (TOPCon) panels. Panels were tested in full sun and then transitioned to partial shading, a condition that forces cells to begin converting power from surrounding cells into heat.

Maxeon found that based on the characteristics of IBC cells, including diode functionality, uniform heating, and lower breakdown voltage, IBC panels like Maxeon 7 exhibit more favorable performance under partial shade compared to other module technologies like PERC and HJT.

IBC panels were found to mitigate the long-term degradation risk of panel materials by better minimizing that heat build-up in shaded cells—staying an average of 67 °C (153 °F) cooler than the ribbon-based back contact, HJT and TOPCon technologies tested.

The Maxeon whitepaper explains hotspot risks:

A solar panel maximizes its energy generation potential when each cell within an electrical string maintains the same current. When a cell can’t match the current of its neighbors, usually due to the presence of shading or cell cracks, it begins consuming power from surrounding cells and converting it to heat—also known as operating in a state of reverse bias. As cell temperatures rise, hotspots can form in the vicinity of the obstruction. Hotspots are very concentrated areas of heat energy that can reach extreme temperatures—temperatures high enough to degrade panel materials by burning the encapsulant and back sheet, as well as damage cells and glass.

Maxeon’s research and development team also tested the resilience of panels to heat build-up after deactivating the panels’ bypass diode, the primary defense mechanism of standard solar panels against hotspots. It found that the IBC panels continued to limit heat build-up even after deactivating the bypass diode.

“Solar panel manufacturers should continue to pursue improved product design—technology risk shouldn’t be the customer’s burden to bear,” said Matt Dawson, chief technology officer, Maxeon. “We believe many of today’s manufacturers are sacrificing product reliability in the pursuit of higher power and efficiency. High performance solar panels truly maximize lifetime customer value when they can match that performance with low degradation and long-term reliability.”

Find the IBC hotspot resilience whitepaper here.

The Federal Energy Regulatory Commission released its Energy Infrastructure Update, issuing data through April 2024 for projects interconnected to utility electric grids.

Solar installed a cumulative 7,899 MW in January through April 2024, representing 80.5% of capacity additions. Wind followed with 1,825 MW, while natural gas added 67 MW of capacity through the first four months of the year.

In April, solar added 1,374 MW to the grid, representing 63.7% of all capacity added. Wind followed with 737 MW added, while 16 MW of natural gas was interconnected with the grid.

Despite its domination of new project queues and activations, renewable energy has a long ramp of growth ahead of it if the United States is to achieve its goals of decarbonizing the energy sector. FERC reports that natural gas has the largest share of the energy mix with 564.5 GW (44%). This is followed by coal (16%), wind (12%), solar (9%) Nuclear (8%), and hydropower (8%). Oil, biomass, geothermal and waste heat combine for about 4% of the energy mix.

Looking ahead, for a short-term outlook of new capacity additions from May 2024 through April 2027, FERC expects solar to add the most capacity by a wide margin. FERC defines capacity additions in two buckets, all additions (including proposed projects) and high probability additions (projects that are further along the development cycle and very likely to be approved and constructed).

For high probability additions, solar leads the way with 88,195 MW expected. This is followed by wind with 23,919 MW, and natural gas with 13,280 MW. All other generation sources are expected to add 400 MW or less, with zero nuclear energy capacity additions expected.

As for retired capacity over the next three years, about 20,177 MW of coal, among most emitting source of electricity, is expected to be retired. Additionally, 17,103 MW of natural gas capacity is expected to come offline, leading to a net decline of 3,823 MW. About 2,043 MW of oil capacity is expected to be retired.

FERC reported that 128.2 miles of transmission lines with voltages from 230 V to 500 V was constructed thus far this year. Through September 2026, FERC expects 2,056.2 miles of high-probability transmission lines to be added.

Below are highlights of project additions as reported by FERC:

• FGE Goodnight I LLC’s 258.1 MW Goodnight Wind Energy Project in Armstrong County, TX is online.
• AES Clean Energy Development LLC’s 216.0 MW wind powered Chevelon Butte Phase 2 in Coconino County, AZ is online.
• Ranchland Wind Project II LLC’s 148.0 MW Anchor Storage & Wind I – II Expansion in Callahan County, TX is online.
• Ranchland Wind Project LLC’s 114.9 MW Anchor Storage & Wind I – II Expansion in Callahan County, TX is online.
• Sparta Solar LLC’s 250.0 MW Sparta Solar (TX) Project in Bee County, TX is online.
• Hardy Hills Solar Energy LLC’s 195.0 MW Hardy Hills Solar Project in Clinton County, IN.•Sky Ranch Solar LLC’s 190.0 MW Sky Ranch Solar & Storage Project in Valencia County, NM is online.
• Zier Solar LLC’s 163.0 MW Zier Solar & Storage Project in Kinney County, TX is online. •South Cheyenne Solar LLC’s 150.0 MW South Cheyenne Solar Project in Laramie County, WY is online.
• Cane Creek Solar LLC’s 78.5 MW Cane Creek Solar LLC in Clarke County, MS is online.
• Misenheimer Solar LLC’s 74.4 MW Misenheimer Solar Project in Stanly County, NC is online. The power generated is sold to Duke Energy Carolinas under long-term contract.
• Foxhound Solar LLC’s 71.0 MW Foxhound Solar Project in Halifax County, VA is online.
• Castle Solar LLC’s 40.0 MW Castle Solar LLC in Emery County, UT is online. The power generated is sold to the University of Utah under long-term contract.
• Hayhurst Texas Solar LLC’s 24.8 MW Hayhurst Texas Solar Project in Culberson County, TX is online.
• Cottontail Solar 8 LLC’s 20.0 MW Cottontail Solar 8 Project in York County, PA is online.
• Spectrum Solar LLC’s 8.6 MW Spectrum Solar (MD) Project in Prince Georges County, MD is online.
• ASA DeKalb NY Solar III LLC’s 7.4 MW ASA DeKalb NY Solar III LLC in Saint Lawrence County, NY is online.
• Casco Standish Solar LLC’s 6.7 MW Casco Standish Solar LLC in Cumberland County, ME is online.
• Beaver Dam Solar 1 LLC’s 6.2 MW solar powered Beaver Dam (NY) Project in Albany County, NY is online. The power generated is sold to Southern Co Services Inc under long-term contract.
• Elk Solar LLC’s 5.0 MW solar powered Elk Project in Hoke County, NC is online.

kWh Analytics, a climate insurance provider, released its 6th annual Solar Risk Assessment report, providing a data-driven overview of risks to solar assets. The report included contributions from solar industry leaders in technology, financing, and insurance. 

“To meet renewable energy deployment goals, the focus needs to be on smart growth – relying on data to inform decisions and utilizing resilience measures to protect assets,” said kWh Analytics chief executive officer Jason Kaminsky. 

The report identified 14 risks to be aware of in the solar industry, including risks related to extreme weather and operational risks. For the first time this year, battery energy storage related risks were included. This news covers the extreme weather risks, with subsequent articles reviewing operational and storage related risks. 

Find coverage of the weather-related risks to solar assets here. This report will focus on solar asset operational risks, with a subsequent article focusing on energy storage risk assessment. 

Aggregating portfolios of 4 or more projects cuts extreme risk scenarios 

kWh Analytics found a trend that most financial forecasts underestimate the risk of extreme downside scenarios, known as P99 level events. These events are expected to occur once every 100 years, but the company’s data has shown that catastrophic damage P99 events have occurred as frequently as every 6 years. 

“One possible way to mitigate the risk of extreme downside scenarios is to aggregate portfolios of projects for financing – the distribution of risk increases the likelihood that a poorly performing site will be balanced by a better one in the portfolio,” said kWh Analytics. 

The company found that median performance across 301 utility-scale solar sites, covering 935 years of production for 2017 to 2022. It found that by aggregating at least four projects into a portfolio, the risk of all assets performing below 80% of initial forecasts is cut in half. 

However, kWh Analytics said that benefit of portfolio aggregation is dwarfed compared to using more accurate production and risk forecasts. It said that improving P50 forecast accuracy with realistic, data-driven availability estimates has the potential to decrease the occurrence of extreme downside scenarios by as much as a factor of 10.

Voltage collapse can reduce production by more than 20% 

Voltage collapse is a significant decline in voltage levels within the DC field. Solarlytics said that voltage collapse is a fast-growing problem in solar assets. 

“As voltage the voltage collapses below the inverter operating range, it hinders the inverter’s ability to match DC field voltage, resulting in energy losses. In advanced cases, the collapse causes the inverters to frequently trip, leading to energy losses that exceed 20%,” said Solarlytics. 

Voltage collapse can be caused by a variety of factors. For example, projects designed for cold weather climates require shorter strings to perform on cold days. When these systems faces warmer weather in the summer, the string voltage can drop below the inverter range. 

Solarlytics estimates that more than 30% of all utility-scale solar plants suffer from voltage collapse. The company recommends using advanced string-level monitoring and optimization, proper inverter sizing and configuration, and continuous monitoring for early detection of voltage sagging to take corrective actions. 

Operations and maintenance corrective actions on the rise 

Solar Advanced Analytics, Univers found that operation and maintenance (O&M) corrective actions continue to rise as more solar assets go online. This past winter, the firm found a 14% increase in corrective actions taken when compared to summer 2023. It analyzed data from over 11 GW of assets across over 300 sites. 

It found that 50% of corrective actions were attributed to the health of DC-level components in the system. This was followed by inverter corrective actions and repairs, which represented 15% of all corrective actions. Data availability actions ranked third, representing 13% of actions taken. 

About 43% of DC corrective actions occur during winter, said Solar Advanced Analytics, indicating the influence of winter conditions like low temperatures, reduced irradiance, and snow cover on DC inputs and strings. Conversely, inverters are prone to corrective action in warmer seasons, as elevated system temperatures can lead to cooling system failures and decreased inverter efficiency. 

The seasonal differences highlight the need for O&M operators to strategize seasonally, planning for DC issues in the winter and inverter issues in the summer. By targeting O&M schedules, providers can limit truck rolls and properly allocate inventory resources and workforce. 

Safety problems require partial or total de-energization in 11% audited systems 

SolarGrade found that critical issues were found in 11% of U.S. solar projects in a series of inspections conducted from January 2023 to March 2024. This critical level designation is placed on assets likely to have catastrophic failure before the next maintenance event. 

About 11% of U.S. solar assets analyzed were found to have critical issues that require the system to be partially or totally de-energized until the problem is fixed. 

The most common critical issue by a large margin was problems with PV connectors, which was the cause of 46% of projects in need of de-energization. Unsafe connectors are often due to complex installation requirements and cooling, pervasive myths about MC4 compatibility, and a lack of field training, said SolarGrade. The company provides a solar connector safety guide. 

Unmitigated soiling can reduce annual production by up to 50% 

Soiling is the accumulation of dust, dirt, and particulates on solar panels. According to data from the National Renewable Energy Laboratory, soiling can cause up to 50% production losses in soiling-prone regions. 

Clean Power Research provides modeling to understand regional differences for soiling risk, which vary widely based on location. The risk is particularly high in regions with low annual rainfall totals, highlighting a need for regularly scheduled soiling cleaning in these regions. 

“By employing various soiling loss models, coupled with accurate model inputs and reliable irradiance data from SolarAnywhere, industry experts can establish effective strategies to minimize performance uncertainty when modeling PV systems in complex climate conditions,” said Clean Power Research. 

Inverters cause 59% of lost energy 

While PV systems are designed to last for 35 years or more, various components fail much sooner. An analysis of O&M logs revealed that the most frequent cause of corrective maintenance issues in response to a significant loss were caused by inverters (51%). This was followed by DC distribution equipment maintenance, including connectors, combiners, and wiring, which represented 21% of actions taken. 

kWh Analytics found that inverter failures cause the highest time-to-resolution and lead to the highest energy lost, about 59% of energy lost due to corrective actions. The most common inverter O&M tickets were related to issues with the controller, fan, and logic board. This data may be useful when determining procurement priorities for spare parts, said kWh Analytics.

The upcoming third article on kWh Analytics Solar Risk Assessment will focus on battery energy storage systems operational risks, marking the first time storage was included in its annual report. For more energy storage news, check out pv magazine’s new Energy Storage News website. 

A gas station in Crandall, Texas is among the first in the state to install solar panels on the roof of its pumping station.

DynamicSLR installed the 49 kW array for the Tri Gaz 5 station, The project is equipped with Enphase IQ8-3P microinverters. Microinverters are placed under each solar module, ensuring optimized production for each individual module.

The project is estimated to offset 17% of the station’s electricity needs, producing approximately 66,359 kWh per year. The project is interconnected with utility Oncor’s transmission grid.

The on-site solar array is expected to offset 1,920 lbs of carbon dioxide emissions per year, equivalent to 4,365,231 miles driven by cars, or 28,799 trees planted. 

“Our commitment to sustainability drives us to be pioneers in our field,” said Zak Kassem, president, Tri Gaz 5. “We take pride in being the first gas station in Texas to embrace solar energy, thereby reducing our carbon footprint.”

Ahmed Barakat, head of operations for commercial and industrial solar, DyanmicSLR said the installer was concerned about the potential risks of arc faults and selected a solution that made safety a top priority.

“We choose Enphase microinverters to provide clients with the safest solution, and the Enphase App allows us to implement module-level monitoring,” said Barakat. “This not only addresses their safety concerns, but also enhances their overall experience by providing detailed monitoring and analysis at the individual module level.”

Enphase IQ8 3P inverters were selected to provide the station a three-phase solution. The high-powered microinverter is designed for 208Y VAC three-phase small commercial solution. It has a peak power output of 480 W and comes equipped with a limited warranty of up to 25 years.

The gas station is expected to save about $3,752 per year, or about $154,685 over the expected life of the system.

Lazard released its annual report analyzing levelized cost of electricity (LCOE), a critical measure of cost-efficiency of generation sources across technology types. The report found that onshore wind and utility-scale solar have the lowest LCOE by a large margin.

LCOE measures lifetime costs divided by energy production and calculates the present value of the total cost of building and operating a power plant over an assumed lifetime.

“Despite high end LCOE declines for selected renewable energy technologies, the low ends of our LCOE have increased for the first time ever, driven by the persistence of certain cost pressures (e.g., high interest rates, etc.),” said Lazard. “These two phenomena result in tighter LCOE ranges (offsetting the significant range expansion observed last year) and relatively stable LCOE averages year-over-year.”

Onshore wind ranked as the lowest source of new-build electricity generation, ranging from $27 to $73 per MWh. Utility-scale solar was a close second, ranging $29 to $92 per MWh.

Utility-scale solar has had the most aggressive cost reduction curve of all technologies, falling about 83% since 2009, when new build solar generation had an LCOE of over $350 per MWh.

Solar at the utility-scale is far lower in cost than the LCOE of coal, the least-expensive source of fossil fuel generation. Coal LCOE ranges $69 to $169 per MWh, making it nearly double the average LCOE of utility-scale solar assets.

Meanwhile, natural gas peaker plants are highly inefficient in LCOE, ranging from $110 to $228 per MWh. Nuclear energy had the highest utility-scale LCOE with an average of $182 per MWh.

LCOE is a powerful measure to compare technology cost efficacy, but it does not tell the whole story. For instance, research from the Lawrence Berkeley National Laboratory found that wind and solar generation provided $249 billion dollars of climate and air quality health benefits from 2019 through 2022, or over $62 billion annually.

While utility-scale solar had the lowest LCOE, costs for smaller-scale distributed solar projects have fallen as well. Community, commercial, and industrial scale projects ranged $54 to $191 per MWh. Residential solar ranged $122 to $284 per MWh, making it a more expensive source of generation.

However, LCOE does not consider cost benefits like the lessened need for long-distance transmission buildout that occurs from distributed rooftop solar buildout. Environment America released a report assessing the co-benefits of rooftop solar, which can be found here.

Lazard also analyzed the cost impacts of the Inflation Reduction Act, which includes both generation-based Production Tax Credits, and project-based Investment Tax credits for renewable energy assets. The chart below models the cost impact on these technologies, as seen below.

Energy storage saw cost improvements from the IRA as well. Levelized cost of storage (LCOS) for a utility-scale, 100 MW, 4-hour storage system ranged $170 to $296 per MWh pre-IRA. Post-IRA, the low-end of the LCOS range landed at $124 per MWh. 

Find the full ninth annual report from Lazard here.

A report from kWh Analytics, a climate insurance provider, released its 6th annual Solar Risk Assessment report, providing a data-driven overview of risks to solar assets. The report included contributions from solar industry leaders in technology, financing, and insurance.

“To meet renewable energy deployment goals, the focus needs to be on smart growth – relying on data to inform decisions and utilizing resilience measures to protect assets,” said kWh Analytics chief executive officer Jason Kaminsky.

The report identified 14 risks to be aware of in the solar industry, including risks related to extreme weather and operational risks. For the first time this year, battery energy storage related risks were included. This news covers the extreme weather risks, with subsequent articles reviewing operational and storage related risks.

Modeling assumptions underestimate losses from weather damage by 300% or more

Data from kWh Analytics found that risk modeling for damage from weather events has been heavily overlooked. Particularly in large solar markets like California, Texas and Arizona, actual ground-up losses from weather events have been as much as 300% or more than what has been modeled by asset owners.

kWh Analytics said that as PV is a relatively new asset class, natural catastrophe models typically used to size insurance premiums often rely on proxy structures to estimate losses. The company said more accurate PV-specific modeling is needed, and differences in technology used (like trackers with hail-stow protection) should be considered in risk modeling.

The insurance provider has developed new models leveraging locational-specific risks, backed by data from the National Renewable Energy Laboratory (NREL), significant loss data and satellite imagery to provide a more accurate risk assessment.

Modules perform well after significant cell damage

Reliability testing from Kiwa PVEL found that broken cells from impacts like hail are less catastrophic to solar module performance than one may expect. No module tested by PVEL lost more than 3% production after undergoing a hail stress sequence.

The testing lab said that rather than relying on expensive electroluminescent (EL) testing, it would recommend that asset owners perform annual aerial thermal scans to identify cracked modules that have developed hotspots and are at risk for fires and in need of replacement. Fire risks are most severe in a rare case that a module with a failed bypass diode has cracked cells.

Modules protected by hail stow post only 0.8% power loss

Waaree found that lab-tested solar modules that tilt to a stowed position to protect from direct hail impacts only lose 0.8% of their production from being in a sub-optimal angle during hail events. In turn, the modules were able to avoid damage altogether by stowing. The losses perform far better than the IEC standard of 5% losses from stowing.

Solar project insurance costs can be reduced by up to 50% by investing in resilient design and maintenance

Data from Alliant Power found that assets in high-risks areas can reduce insurance costs by up to 50% by investing in resilience measures like selecting heat-tempered panels and trackers that enable hail stowing.

“It pays to take time to differentiate your project and select highly qualified partners when it comes to risk and insurance,” said Alliant Insurance Services.

Natural catastrophe events are on the rise, with billion-dollar weather events increasing from an average of 13 per year in the 2010s to an average of 22 per year in the 2020s, with 28 billion-dollar damage weather events occurring in 2023 alone, said Alliant.

Asset damage probability is 87% lower with a 75 degree hail stow tilt

Solar developer Longroad Energy shared a case study under which different tilt angles and their impact on module protection from hail impacts were assessed. The report was based on data from RETC and tracker provider Nextracker.

It found that a 50 degree stow led to a 33% estimated module breakage probability, while 60 degree stow had an 8% probability, and 75 degree stow led to only a 1% risk of breakage from hail.

The next report in this series will review the kWh Analytics assessment of solar asset operational risks.

For more on quality issues in utility-scale solar, sign up for a free webinar on Racking and trackers: quality issues in the factory and design considerations for utility-scale solar installations, June 11 at 11 a.m. ET. Register here.

Utility-scale solar developer Arevia Power it has signed a power purchase agreement (PPA) with Nevada utility NV Energy for one of the largest solar and energy storage projects in the state.

Under the PPA, the utility will purchase power generated by the 700 MW Libra solar project, 20 miles south of the Fort Churchill substation in Yerington, Nevada.

The project will include 700 MW of solar and a 700 MW / 2800 MWh battery energy storage system. The battery storage system is designed provide reliable power year-round, particularly for rural Nevada. Once complete, the project will span 5,141 acres, with most of the generation ties to the grid located in Lyon County.

The project is planned to reach commercial operations in 2027 and will employ 1,100 people during development and construction, providing $250 million in direct wages.

The International Brotherhood of Electrical Workers (IBEW) will provide labor for the project and is also serving as an investor through GCM Grosvenor’s Infrastructure Advantage Strategy. 

“With the Libra project we are taking another step toward a sustainable future that also delivers the type of high-paying middle-class jobs the people of Nevada deserve,” said IBEW president Kenneth Cooper.

Over its lifecycle, the project is expected to generate $170 million in personal property and sales taxes.

The project is set to be approved through the Integrated Resource Plan (IRP) submitted by NV Energy. Key components of the IRP include three solar and battery power purchase agreements (PPAs), totaling over 1,000 MW of solar energy and more than 1,000 MW of battery storage.

The PPAs under the IRP will be built, owned, and operated by third parties, which sell their projects’ output to NV Energy. The projects are expected to help the utility meet state renewable energy standards while creating fixed-cost energy pricing for customers.

Arevia was advised by Patrick Groomes and Brenda Hanzl, who also advised Arevia in its prior negotiations with NV Energy on the 690 MW Gemini solar and energy storage project.

The U.S. Department of Energy announced a $38 million funding opportunity via its Solar Energy Technologies Office (SETO), supporting research, development, and demonstration projects related to the solar energy supply chain. 

The funds are intended to support projects that de-risk solar hardware, manufacturing processes, and software products. The funding opportunities also seeks projects that provide outreach, education, or technology development for software that delivers an automated permit review and approval process for rooftop solar and/or energy storage. 

“These investments will help accelerate the growth of the solar industry, identify emerging opportunities, and drive down costs for our domestic energy market, positioning the United States on the leading edge of solar industry advances,” said DOE. 

Eligible technologies include PV, systems integration, concentrating solar-thermal power, technologies that connect solar with storage or electric vehicles. It also considers dual-use projects like agrivoltaics and vehicle-integrated photovoltaics. 

Topic areas: 

1. Solar Research and Technology Development 

DOE will support five to ten projects receiving $1 million to $2 million each. The topic area focuses on R&D projects for for-profit companies improving and de-risking solar components and/or manufacturing processes. Successful project submissions will develop and validate realistic pathways to commercial success. 

2. Solar Energy Demonstration 

Five to ten research, development, and demonstration projects will receive between $1 million and $5 million for established companies or startups to develop pilot-scale or prototype demonstration of solar products. Successful applicants for this topic area will have an existing prototype that requires further testing, engineering work, or demonstration in a controlled environment. 

3. Solar Permitting, Outreach, Education 

One to three projects receive between $1 million to $5 million for outreach, education, and software development activities for automated code-compliant rooftop solar permitting software. The projects are designed for use by solar installers to submit permit applications to local governments and to automate review and approval. 

DOE will hold an informational webinar on the funding opportunity on June 13, 2024. 

Link to Apply: Apply on EERE Exchange 

From pv magazine Global

Market activity quieted down in the Chinese cell market as most market participants stood on the sidelines unsure if prices had bottomed out. Demand remained tepid as most market participants were not in an urgency to replenish cargoes.

The majority of cell manufacturers are facing cash flow problems and although wafer prices have reached an all-time low, these cash-strapped cell manufacturers were unable to take advantage of the lower wafer prices to build up their wafer inventories, a market veteran said.

Integrated manufacturers who had previously produced their own solar cells were more inclined to acquire cells from the market now as buying cells was cheaper compared to in-house production, the source added.

Some cell manufacturers have turned to OEM manufacturing to maintain operating rates despite production losses. The fee of M10 TOPCon cells OEM cell manufacturing had fallen to CNY1.4 ($0.19)/pc which is below the production costs of CNY1.6/pc, a market veteran said.

OPIS assessed the FOB China Mono PERC M10 prices stable at $0.0390/W,  FOB China Mono PERC G12 prices are unchanged at $0.0414/W while FOB China TOPCon M10 prices were assessed lower by 1.73% at $0.0398/W, week-to-week.

High inventories are expected to exert further downward pressure on cell prices in the coming weeks even if cell manufacturers reduce operating rates in a bid to restore supply and demand balance. Moreover, module manufacturers are expected to reduce their operating rates further in June and this would result in less demand for cells.

China cell production in May stood at 62 GW, according to the Silicon Industry of China Nonferrous Metals Industry Association.

In the Chinese domestic market, Mono PERC M10 cells were priced at about CNY 0.313/W while TOPCon M10 cells stood at about CNY0.320/W, according to OPIS market survey.

OPIS, a Dow Jones company, provides energy prices, news, data, and analysis on gasoline, diesel, jet fuel, LPG/NGL, coal, metals, and chemicals, as well as renewable fuels and environmental commodities. It acquired pricing data assets from Singapore Solar Exchange in 2022 and now publishes the OPIS APAC Solar Weekly Report.

California has made numerous cuts to solar incentives and programs in its state, including reductions in the valuation and crediting of exported solar generation, cuts to its emerging community solar program, and imposing a monthly fixed charge that erodes the potential savings brought on by rooftop solar.

However, the California legislature has recently moved forward a bill that would undo a decision that would negatively affect the value of rooftop solar for renters in multifamily housing, and for farms, and schools.

The decision sets hard limits on how much electricity produced by rooftop solar can be self-consumed by multi-meter properties. The policy effectively forces customers to first sell their solar production to the utility, and then buy it back at higher rates.

“It would force customers in multi-meter properties—such as renters, small farmers, schools, and colleges—to sell all of their generation to the utility at low rates and buy it back at full retail rates,” said the California Solar and Storage Association (CALSSA).

California’s Virtual Net Metering and Net Energy Metering Aggregation programs allow properties with multiple meters to install a single solar array for the entire property, sharing one system’s electricity and associated net metering credits with all customers and meters on the property. 

The decision would require multi-meter properties to sell solar to the grid at a low “avoided cost” rate and then purchased back at a full retail rate. This would be required even if the electricity generated on the school’s roof was used directly by the school.

A new bill, Senate Bill 1374, sponsored by Senator Josh Becker, would reverse the decision. The bill passed the Senate 28-7 and now awaits approval from the Assembly Utilities and Energy Committee.

“SB 1374 removes a burdensome barrier and restores the ability for customers to self-consume the energy they produce on their property,” Becker said in a statement. “This bill is simply a matter of fairness. Multiple-metered customers should get the same treatment as everyone else — not have to sell their power to the utility at low prices and immediately buy it back at much higher retail prices.”

The state’s three investor-owned utilities PG&E, SCE, and SDG&E oppose the decision. In a joint statement the three said Becker’s bill “subsidizes solar for all non-residential customers, not just schools.” However, public schools would essentially be performing energy arbitrage for the utility companies under their vision.

Utilities have justified cuts to rooftop solar programs based on an argument that non-solar customers subsidize those with solar. The utilities alleged the bill “is likely to trigger grid upgrades, which results in high cost for all, but for the benefit of only a few customers.” However. analysis from the California Public Utilities Commission (CPUC) has determined that non-residential solar programs have not caused a cost shift.

Supporters of Senate Bill 1374 say it would help schools with the electricity affordability crisis. Oakland Public Schools have seen their utility bill increase $1.5 million over the last year alone.

“Public schools have one general fund that everything comes out of: teachers’ salaries, textbooks, mental health counselors, utility bills-–it all comes out of the same bucket,” said Sam Davis, Oakland Unified School District board president. In previous years, we used solar energy to offset these rising costs and invest the savings in programs that improve educational equity. Restoring and protecting these incentives is critical to ensuring all students receive the education they need to thrive.”

Nearly 2,500 schools have installed solar in California according to Generation 180. Read about rooftop solar success stories for schools in the U.S. here.

The U.S. Department of Energy (DOE) announced its first proposed projects under its Cleanup to Clean Energy initiative, which seeks to repurpose DOE-owned lands into clean energy generation centers. 

The proposed projects include development on former nuclear weapons testing sites operated by the Idaho National Laboratory. DOE will enter lease negotiations for solar projects within the 890-square-mile site. 

DOE plans to support the development of 400 MW of solar capacity at the site, or enough to power about 70,000 homes. 

“Tens of thousands of acres of DOE-owned land across the nation are being transformed into thriving centers of carbon-free power generation,” said U.S. Energy of Secretary Jennifer M. Granholm. “Working closely with community leaders and private sector partners, we’re cleaning up land once used in our nuclear deterrence programs and deploying the clean energy solutions we need to help save the planet and strengthen our energy independence.”  

The Cleanup to Clean Energy initiative was launched in July 2023. The program dovetails with President Biden’s climate goals and responds to the directive in Executive Order 14057  and the accompanying Federal Sustainability Plan. 

Executive Order 14057 calls for federal agencies to achieve 100% clean energy by 2030 and authorizes them to use land for development of clean energy generation via leases, grants, permits, and other mechanisms. 

For the two developers with selected proposals Idaho National Laboratory site, NorthRenew Energy Partners proposed to install more than 300 MW of solar along with battery energy storage on approximately 2,000 acres. Spitfire proposed to install 100 MW of solar plus battery energy storage on about 500 acres of the site.  

DOE said it plans to open subsequent opportunities for the Idaho National Laboratory site. 

DOE has also issued requests for qualifications (RFQs) to lease land at four additional sites, including the Hanford site in Washington; the Waste Isolation Pilot Plant in New Mexico; the Nevada National Security Site in Nevada; and the Savannah River Site in South Carolina. DOE plans to announce additional selections this year. 

More information on the Cleanup to Clean Energy initiative can be found here.

Recom Technologies, a European PV module manufacturer, has partnered with Solar Optimum to supply solar panels for a solar carport project at the Six Flags amusement park in California.

The 12.37 MW solar carport system will be constructed over the main guest and employee parking lots. It is expected to offset 100% of the park’s electricity usage.

The project is the largest solar carport in California, and the “largest single-interconnection commercial and industrial development in the world,” said Ara Krikorian, executive vice president of commercial development, Solar Optimum.

Once operational, the project is expected to produce 20.8 million kWh annually, equivalent to the power demand of nearly 3,000 homes. It is expected to offset the carbon emissions equivalent to taking over 3,100 cars off the road each year.

The park will purchase electricity produced by the system over a 25-year period, leading to an estimated 517 million kWh produced over the period.

The project includes a 1.96 MW / 7.89 MWh battery energy storage system.

The carport will make use of Recom Panther bifacial half-cut solar panels. The bifacial panels produce electricity from sunlight above as well as reflected up from the ground to the backside of the panel.

Recom’s Panther series of solar modules is offered in various formats including G1: 158.75mm; M6: 166mm; M10: 182mm; G12: 210mm. Wattage ratings range from 360 W to 665 W, and the company offers both monofacial and bifacial panels with varied frame and backsheet options.

Recom offers a 25-year product warranty for its panels. The panels offer a first year output of 98% of initial rating, less than 0.54 % annual degradation, and a 25-year output of over 85%.

Six Flags’ latest project adds to Six Flags Discovery Kingdom in Northern California and Six Flags Great Adventure in New Jersey, which have also developed on-site solar facilities with over 30 MW of operational solar capacity.

Once the Los Angeles carport is complete, Six Flags will have a combined total of 42.37 MW of solar assets, ranking it among the largest investors of on-site commercial solar.

“Here in California, innovation and climate action go hand-in-hand – our success as America’s economic powerhouse and the world’s fourth largest economy is built on our ambitious transition to a cleaner, greener future. Six Flags’ commitment to clean energy is the type of work that will power our future and ensure our kids have a healthy planet to call home,” said California Governor Gavin Newsom

ABB has launched a new smart electric panel for home energy management, called the ReliaHome Smart Panel. The product, intended for residential projects in the United States and Canada, was developed in partnership with Lumin, a responsive load management device and software provider.

The smart panel coordinates home energy assets, enabling energy optimization, circuit scheduling, and real-time control. Homeowners can control their energy use informed by insights from platform, which can be controlled via an app, saving on energy and costs.

“Users can make informed decisions on energy consumption, prioritizing appliances during an outage to extend battery storage runtime and optimizing circuits to avoid paying high electricity rates at peak times,” said ABB. “The platform ensures seamless functionality during power and network outages through a local-first network backup, enabling consistent customer connectivity independent of a cloud connection.”

The ReliaHome energy management system is designed and assembled in the United States. It has wide compatibility with third-party batteries, solar inverters, EV chargers, standby generators, and more. ABB said the product is suitable for both retrofits and new installations.

ABB provides customer support and resources for implementation and maintenance, as well as cybersecurity systems that are validated and ISO 27001:2013 and IEC 62443-4-1:2018 certified.

Technical specifications for the ReliaHome panel:

• AC voltage: 120/240 VAC Split phase, 50-60HZ
• Supply Breaker rating: 15-20 A (non-GFCI)
• Connection options: Wi-Fi or Ethernet

Find the full spec sheet here.

Residential energy consumption accounts for about 20% of U.S. total energy use, said the U.S. Office of Energy Efficiency and Renewable Energy. As such, energy retrofits and a shift towards distributed low-carbon energy sources are an important step towards meeting decarbonization goals. The ABB smart panel helps homeowners coordinate and manage power as they electrify their homes.

“This latest collaboration marks a significant stride in ABB’s focus on the residential sector,” said Adam Mease, NEMA global product group leader, ABB. “We’re committed to accelerating the energy transition through innovation and the evolution of traditional home electrical distribution, offering homebuilders, homeowners, and communities’ powerful tools to optimize energy usage and save costs.”

Tandem PV, a perovskite solar panel developer, announced it has secured a $4.7 million award from the U.S. Department of Energy (DOE) Solar Energy Technologies Office to advance commercialization of its thin-film solar technology.

The award is part of a larger $71 million investment by DOE in projects that support bolstering the U.S. solar supply chain.

The company develops solar panels that pair conventional silicon cells with perovskite materials for panels, giving them the potential to produce up to 40% more power than traditional solar modules used today, said Tandem PV.

Tandem PV’s design stacks a thin-film perovskite layer on top of the crystalline PV layer, with the two materials absorbing different wavelengths of sunlight. The company is currently producing tandem perovskite panels with about 26% efficiency, which is roughly 25% more powerful than a conventional silicon solar panel today.

Solar panel efficiency is an important metric for solar facility developers. More power at a similar price per watt leads to lower labor costs for installation, lower land-acquisition costs, and a lower total cost of ownership for customers, said the company.

“This is Tandem PV’s 10th award from the Department of Energy and we are grateful for its consistent, long-term investment and validation,” said Tandem PV co-founder and chief technology officer Colin Bailie.

The company said its has demonstrated “the equivalent of decades of projected durability” in the lab. Durability has been a key issue to solve for perovskites, which show high efficiencies, but degrade rapidly in the field.

Tandem PV said it plans to obtain independent industry-standard validations of the durability and efficiency of its perovskites during 2024. The company said plans are underway for a first manufacturing facility as research and development efforts advance.

“Thanks to historic funding and actions from the president’s clean energy agenda, we’re able to deploy more solar power – the cheapest form of energy – to millions more Americans with panels stamped ‘made in the U.S.A.’,” said Jennifer M. Granholm, U.S. Secretary of Energy.

Tandem PV, founded in 2016 in Silicon Valley, has raised a total of $33 million in venture capital and government funds including from the DOE, the National Science Foundation and the California Energy Commission.

Tandem PV was selected for the $4.7 million award as part of SETO’s Advancing U.S. Thin-Film Solar Photovoltaics Funding Program.

Fronius has announced the release of the Gen24 inverter, an inverter designed to support rooftop residential solar installations and home battery energy storage.

The string inverter is widely used in the rooftop solar industry in Europe and has now been developed for installation in North America. The Fronius Gen24 single phase inverter ranges 3 kW to 10 kW. The standard Gen24 model comes with integrated basic backup power functionality, called PV Point.

Fronius string inverters use a Dynamic Peak Manager, a maximum power point tracking (MPPT) system that maximizes the yield of each solar panel under varied shading conditions across the array. The MPPT algorithm negates the need for DC optimizers under each panel, lowering the amount of components needed for the solar installation, while also lowering the cost, said Fronius.

The inverter is designed around flexibility in layouts and design, able to maximize output on complex roofs. It has a broad input voltage range, which Fronius said leads to efficient solar power generation even with differing roof orientations. The inverters also have flexibility in hardware and software compatibility with third-party devices. The inverter comes with open interfaces to manage and integrate components like solar, batteries, backup loads and more.

Fronius inverters have active cooling fans built-in, supporting long term use. The inverters are rated for both indoor and outdoor use.

“Our inverter delivers unbeatable energy yields even on the most complex roofs and, thanks to the Dynamic Peak Manager that doesn’t require DC optimizers, even when shade comes into play,” said Martin Hackl, global director sales & marketing at Fronius International.

Currently, the inverter, when combined with battery energy storage, can support basic backup power supply, supporting the most important electrical loads in the home during an outage. Homeowners can select a designated backup power outlet to support phone chargers, Wi-Fi routers, and more during the outage. Fronius said Gen24 will later support whole-home energy storage backup during outages, once it releases its UP.storage software upgrade. Fronius said Gen24 customers can purchase the whole-home backup service without replacing any hardware once the service is available.

Fronius  will launch the inverter via a product roadshow and accompanying trainings. More information on the launch here.

Fronius products are developed in produced in Europe, mainly in Austria. It has supported a total output of more than 35 GW of installer inverters to date.

Alliant Energy announced it has completed construction of the Grant County Solar project, a 200 MW facility in Potosi, Wisconsin that is large enough to generate the equivalent electricity demand of 50,000 homes annually.

The Grant County project covers 1,400 acres and is comprised of more than 430,000 solar panels. Alliant developed 350 acres of the site to host native pollinator habitats.

The company expects more than $30 million in shared revenues to be generated for the county and town over the life of the project.

“Solar lease payments help local landowners like me diversify our income and preserve our land’s value for the future,” said Dave Fritz, local business owner and participating landowner. “In terms of economic impact, the Grant County Solar Project delivered on its promise of jobs and will benefit local taxpayers for decades thanks to the added shared revenue payments.”

Alliant Energy contracted with a subsidiary of NextEra Energy Resources for construction of the solar facility. Construction began in September 2022, employing more than 700 people.

The project is part of Alliant’s 12-project portfolio in Wisconsin totaling 1,089 MW. The project portfolio is expected to create more than 2,700 construction jobs and generate enough power for nearly 300,000 Wisconsin homes annually.

Alliant also plans to develop nearly 275 MW of energy storage capacity alongside its Wisconsin solar portfolio. This includes the 100 MW Grant County battery storage project that will be co-located with the 200 MW solar facility. The battery project is a four-hour duration facility. FlexGen was selected as the equipment provider for the batteries and energy management systems.

Alliant Energy provides regulated energy service to 1 million electric customers and 425,000 natural gas customers in Wisconsin and Iowa. Interstate Power and Light Company (IPL) and Wisconsin Power and Light Company (WPL) are Alliant Energy’s two public energy companies.

FOB China prices for M10 wafers continued their downward trend this week. Prices for Mono PERC M10 and n-type M10 wafers declined by 5.37% and 7.95% week-to-week, reaching $0.141 per piece (pc) and $0.139/pc, respectively.

FOB China prices for G12 wafers stayed relatively steady this week, with both Mono PERC G12 and N-type G12 wafer prices remaining flat at $0.236/pc and $0.238/pc, respectively.

According to OPIS’ market survey, the average transaction prices of Mono PERC M10 and N-type M10 wafers in the Chinese domestic market have descended to around CNY1.13 ($0.16)/pc and CNY1.12/pc, respectively. Even at this price point, the volume of transactions remains minimal, according to an upstream source. Another industry insider even cited an offer of CNY1.05/pc for n-type M10 wafers, suggesting the potential direction of n-type wafer prices in the immediate future.

The current wafer selling price has notably diverged from production cost considerations, with the main emphasis being on securing sales, according to a market participant.

The wafer inventory remains high at more than 5 billion pieces, equivalent to about 40 GW and twenty days’ production, according to multiple market sources. Against the backdrop of high wafer inventories, reports emerged this week of certain manufacturers reducing their operating rates. Consequently, the overall operating rates of wafer producers have decreased to between 50% and 60%, with a monthly output expected to range between 55 GW and 62 GW.

Recent discussions have emerged about cell manufacturers stockpiling wafers, suggesting that a bottom price for wafers may have been reached. However, a source from the cell market suspects this could be a deliberate attempt by wafer manufacturers to spread misinformation. The source considers this move “unnecessary”, noting that “even if they do hit rock bottom, there’s no basis for a price rebound.”

As a result of shifts in international trade policies, there’s an expectation that orders for cells and modules exported from Southeast Asia to the U.S. will face obstacles in the near future. This development has prompted discussions within the industry regarding the digestion of Southeast Asian wafers and the potential source of wafers for the U.S.’ future cell production.

“It is anticipated that until local cell production capacity is established in the U.S., policies will not completely block the import of Southeast Asian cells. Consequently, the impact on Southeast Asian wafers is not expected to be too significant in the near future,” a source from the global polysilicon market disclosed to OPIS during the China Polysilicon Development Forum (CPDF) held in Leshan, Sichuan, China on May 23 and 24.

In the global market, market insiders have disclosed that a vertically integrated manufacturer’s initial phase 3.3 GW wafer project in the U.S. is slated for completion this year. The factory has already secured the necessary amount of polysilicon for its annual production capacity. Additionally, other wafer manufacturers are exploring the viability of establishing factories outside Southeast Asia, such as in the United Arab Emirates, to navigate the complexities of the international trade environment, sources disclosed to OPIS during the CPDF.

OPIS, a Dow Jones company, provides energy prices, news, data, and analysis on gasoline, diesel, jet fuel, LPG/NGL, coal, metals, and chemicals, as well as renewable fuels and environmental commodities. It acquired pricing data assets from Singapore Solar Exchange in 2022 and now publishes the OPIS APAC Solar Weekly Report.

A strong polar jet stream and a record-breaking heat dome in May resulted in a stark contrast in irradiance patterns across North America. The western and central USA, along with Mexico, experienced higher than normal irradiance, while the Gulf and East Coast regions faced lower irradiance, according to analysis using the Solcast API.

The persistent heat dome over the Gulf of Mexico has led to hot conditions across Mexico, with irradiance levels reaching nearly 130% of climatological averages. Most of Mexico and many Central American states are undergoing a record-breaking heat wave, exacerbated by
clear skies due to a weak subtropical jet stream. This situation is aggravating existing conditions that followed from the dry winter Mexico has experienced. The heat dome is expected to persist into June, shifting its influence towards the southern USA.

In the southeastern USA, wind and stormy weather has led to irradiance levels being almost 20% below average. The East Coast has also seen a drop of around 10% in irradiance from long term May averages. Southerly winds from the tropics brought warm and moist air
northward, contributing to the unusually warm conditions and lower than normal irradiance in Gulf states like Texas, Mississippi, Georgia, and Alabama. This is a preview of the anticipated stronger-than-normal hurricane season, which will not bode well for solar energy production due to the risk of damage, increased cloudiness and temperature-induced losses. The moist, hot air has also resulted in severe storms, such as those that hit Texas earlier this week and adjacent states over the weekend. These storms put pressure on the grid, leading to numerous outages and leaving many without power in the above average temperatures.

In contrast, the strong polar jet stream has created favorable conditions for asset and grid operators in the western USA. The jet stream over the North Pacific caused unseasonably cool temperatures in the Northwest, bringing chilly temperatures and higher than normal
irradiance. Solar irradiance in this region is up by almost 20% compared to long-term averages. This cool weather, coupled with long daylight hours, has provided optimal conditions for solar energy generation before the anticipated hot and dry summer.

Solcast produces these figures by tracking clouds and aerosols at 1-2km resolution globally, using satellite data and proprietary AI/ML algorithms. This data is used to drive irradiance models, enabling Solcast to calculate irradiance at high resolution, with typical bias of less than 2%, and also cloud-tracking forecasts. This data is used by more than 300 companies managing over 150GW of solar assets globally.

Researchers at the University of Illinois Chicago (UIC) have developed a new method to make hydrogen gas from water using solar power and agricultural waste like manure or husks. The researchers said the method reduces the amount of energy needed to create hydrogen fuel by 600%. The results are published in  Cell Reports Physical Science.

The method uses a carbon-rich substance called biochar to decrease the amount of electricity needed to convert water to hydrogen. Combined with using solar power or wind to power the water-splitting process known as electrolysis.

“We are the first group to show that you can produce hydrogen utilizing biomass at a fraction of a volt,” said Singh, associate professor in the department of chemical engineering. “This is a transformative technology.”

Electrolysis represents the most expensive step in the hydrogen fuel lifecycle, representing about 80% of the cost. Recent advancements in producing hydrogen fuel have decreased the voltage required for water splitting by introducing a carbon source to the reaction. However, this process often uses coal or expensive refined chemicals and releases carbon emissions as a byproduct.

The UIC researchers modified the process to instead use biomass from common waste products as the carbon source. By mixing sulfuric acid with agricultural waste, animal waste, and sewage, they produced a slurry of biochar to be used in the reaction.

The team trialed several different inputs for biochar, including sugarcane husks, hemp waste, paper waste, and cow manure. All five inputs reduced the power needed to perform electrolysis, but the best performer, cow manure, decreased the electrical requirement by 600%, to roughly a fifth of a volt.

With reduced voltage requirements, the UIC researchers were able to produce an electrolysis reaction with one silicon solar cell generating about 15 milliamps of current at 0.5 volt, or less than the amount of power produced by a AA battery.

“It’s very efficient, with almost 35% conversion of the biochar and solar energy into hydrogen” said Rohit Chauhan, the report’s co-author. Chauhan said the utilization rate of biochar represents a world record.

The research team said this utilization for biochar represents a new revenue stream potential for farmers, or an opportunity to become self-sustainable for energy needs.

Orochem Technologies Inc. sponsored the research and has filed for patents on the biochar-hydrogen process. The UIC team plans to test the methods at a larger scale. Stanford University, Texas Tech University, Indian Institute of Technology Roorkee, Korea University also participated in this study.

REC Group announced it has released a new solar module for commercial and industrial rooftop and ground mount solar projects in the United States. The series of solar panels is named the REC Alpha Pro M Series.

The Alpha Pro M Series has 610 W to 640 W peak power output modules with heterojunction cell technology (HJT). Find the full specification sheet here.

REC has been developing HJT technology since 2019. HJT competes with TOPCon solar cells, which are another leading innovation in the global solar module market. TOPCon cells make use of a single material for its solar cells, while HJT cells layer both crystalline silicon and amorphous thin-film silicon.

“While the majority of solar panel manufacturers have moved to TOPCon as a quick and simple successor to PERC technology to offer some incremental efficiency gains, HJT is considered a real pioneering technology, presenting the biggest potential for efficiency leaps in the near future,” said REC Group. “In fact, all recently achieved world records for cell efficiency in the lab are based on HJT.”

REC’s new Alpha Pro M Series is produced in Singapore. The modules sport 22.5% efficiency and come with a performance warranty of at least 92% in year 25. Each module is made of 120 half-cut bifacial HJT cells.

“For almost 30 years, REC has strived to combine high-efficiency technology with sustainable business practices,” said Cary Hayes, president of REC Americas. “While high efficiencies will remain the number one criterion for choosing solar panels, longevity and sustainability should be considered if companies are serious about their environmental and social footprint.”

The company reports a temperature coefficient of -0.24%/K, ensuring stable energy output even in high-temperature conditions. The module has a 1.2 inch thin frame, which the company said enables convenient transportation, reducing costs and improving logistics efficiency.

The U.S. Department of Energy (DOE) Solar Energy Technologies Office (SETO) announced a new $31 million funding opportunity called the Solar Technologies’ Rapid Integration and Validation for Energy Systems (STRIVES) program.

The program is intended to fund research, development and demonstration of projects that simulate distribution-level power system operations and demonstrate new business models for coordinating inverter-based resources like solar generation, wind generation and battery energy storage, and other resources like buildings and electric vehicles.

“The large-scale deployment of clean energy technologies is driving a transition to a digitally controlled, decentralized, and distributed electric grid that will require coordination of large numbers of diverse and geographically dispersed assets,” said DOE.

The funds come as part of a collaborative effort with the DOE Office of Energy Efficiency and Renewable Energy (EERE), which has earmarked more than $100 million for field demonstration projects supporting improved planning and operations of the grid.

Topic areas for the $31 million STRIVES program include:

Robust Experimentation and Advanced Learning for Distribution System Operators

8-10 projects, $2.5-3 million each

Projects in this topic area will design and perform field demonstrations of distribution system operator models that consider technology development and the roles of non-traditional stakeholders in potential distribution electricity services and markets.

Improved Simulation Tools for Large-Scale IBR Transient and Dynamic Studies

4-5 projects, $1-2.5 million each

Projects in this topic area will develop and demonstrate software tools and methodologies to improve the ability of power systems engineers to accurately and efficiently model the dynamics of power systems with large amounts of geographically dispersed inverter-based resources.

DOE Solar Energy Technologies Office will hold a webinar June 10, 1:00 p.m. EST to address questions about the funding opportunities. Webinar registration link here.

Submissions for concept papers are due July 25, 2024, while full applications are due October 17, 2024. Awards would be negotiated between March and June of 2025. More information on how to get started can be found here.

Texas has a unique electric grid. Its grid operation organization, ERCOT, is independent of other states and deregulated, making the state open for business for a market-based approach toward energy generation and transmission. 

Texas has been a favorite among utility-scale solar PV developers for a long time, thanks to its business-friendly environment and its lack of substantial local permitting regimes. The state is also operating as a proving ground for the buildout of a more nascent industry: virtual power plants (VPP). 

VPPs are defined by their distributed and connected nature. Rather than transmitting power over long distances from a centralized power plant, VPPs use smart software to control a variety of connected energy assets like rooftop residential solar, battery energy storage, smart heating and cooling, and appliances. Homeowners with eligible VPP assets are compensated for exporting power or reducing use at electricity demand events throughout the year. 

A panel of experts at the RE+ Texas conference in Houston, spoke on VPP progress in the state. The discussion opened with Stuart Page, senior consultant, Department of Energy (DOE) Loans Program Office asking the audience whether they were currently enrolled in a VPP program. Only two people in a room of hundreds raised their hands. Page then asked how many in the audience had heard of VPP, and most conference attendees raised their hands. 

“I bet every single one of you has an energy resource or utilization than can be controlled by an app,” said Page. “Yet none of you are enrolled, despite the fact that there are discounts with your electric bill associated with it.”

Page said that part of the issue with VPP participation is the complexity of programs. Often, they require an opt-in, where the customer must choose to join the VPP program. Page said that VPP providers should instead choose an opt-out model, where customers are automatically enrolled in the program when they buy a smart device like a thermostat or a home battery. He cited a DOE experiment where an automatic enrollment model with an opt-out option increased participation by 400%. 

So why are virtual power plants important? VPPs enable intelligent, local distribution of power, sending what is needed when it is needed. VPPs typically support reducing electricity use during times of peak demand, providing a critical service that may be one of the most important low-hanging fruits to pick in the nation’s progress towards decarbonizing energy and lowering energy costs. 

VPP technology has shown immediate promise in replacing natural gas “peaker plants” on grids, replacing or preventing the buildout of new resources that are among the dirtiest, most expensive, and least efficient on the grid today. 

The virtual power plant commercial liftoff report released by the Department of Energy said that between 2023 and 2030, coincident peak demand on the grid will rise by about 60 GW, from roughly 740 GW to 800 GW of demand. 

“At the same time, fossil assets are retiring,” said the report. “Roughly 200 GW of peak-coincident demand must be served with new resources coming online by 2030. Tripling the current scale of VPPs could address 10-20% of this peak demand. This could avoid about $10 billion in annual grid costs, and much of the money that is spent on VPPs would flow back to participating consumers.” 

Texas proving ground 

Even in a room full of energy industry members and experts, almost nobody attending the RE+ Texas panel session admitted to being enrolled in a VPP. The biggest barrier to adoption has been the creation and implementation of a standardized VPP program, which many states lack. 

To automatically enroll customers at the point of purchase as Page suggested, a program needs to be in place to enable it. Sterling Clifford, director of government affairs, Sunnova Energy, a VPP provider shared that many state utility regulators have said VPP technology is a “long way off.” 

“But it doesn’t have to be,” said Clifford. “The beginning of the process to the launch of the product was 12 months (in Texas).” 

Texas already has 16 MW of energy resources and 7 MW of non-spin flexible demand enrolled in VPP programs. 

Part of what enabled such a quick launch of the program was necessity. Ryan King, manager, market design, for the ERCOT said the catastrophic Winter Storm Uri in early 2021 forced the grid operator to look for new sources of reliable, dispatchable supply at the distribution level, while reducing transmission and distribution costs and increasing grid resiliency. ERCOT landed on VPPs as a solution. 

Another aspect of Texas’ readiness to adopt VPP programs are its electricity-savvy customers. Texas homeowners and renters are already used to making energy decisions at home, as frequently have to shop for new electricity contracts via a Retail Electricity Provider (REP). Contracts typically last a year or two, similar to how a VPP program enables short-term enrollment. 

Texas was also already uniquely well-suited to integrate a VPP program, said King, as ERCOT is already able to value an avoided kWh of electricity, or a dispatched one. This type of valuation is enabled by Texas’ deregulated market, which allow various resources to participate in the market more freely than utilities in other major markets. 

Texas has only just begun its VPP enrollment and already has a combined 23 MW of flexible capacity online. King said that VPP compensation for homeowners is “the closest thing to a free lunch,” and that once further program requirements are ironed out, growth will be “exponential.” 

As for other states, it may prove more difficult to roll out VPPs. While ERCOT has a transparent market where avoided costs of demand reduction and the value of distributed electricity can be directly understood, other states, like California, have a highly vertical electricity market, where cost allocation reporting is murky. 

“A vertically integrated utility – we should just call it a monopoly because that is what they are – don’t always tell the truth about what the exact costs are,” said Clifford. 

For Texas, a highly competitive free market have opened the door for adoption of new technologies like VPP. In vertical markets like California, “perverse incentives” may close that door. 

DOE’s Stuart Page explained how VPPs lower costs both for grid operators and for ratepayers, but that investor-owned utilities have a disincentive to properly manage their spending habits. 

“We have a rate-based system, which means, instead of shaving the peak of my load, we can just build out new stuff,” said Page. “If I can spend $10 billion on that, I get a rate-based profit margin on it. So, I want to spend tons of money. If I use a VPP approach or any other ‘smart’ approach, I don’t get an increase in my profits. So, there’s a perverse incentive for utilities to participate, and we have to change that.”

The United States federal government recently made a rapid series of international trade policy changes and updates to incentives for clean energy projects and manufactured components.

Clean Energy Associates (CEA), a clean energy advisory company, issued a report with reactions to this recent series of policy changes, including expected market impacts on energy storage. Find a report on the market impacts for the solar supply chain here.

Tariffs tripled

On May 14, 2024, the Biden Administration announced changes to section 301 tariffs on Chinese products.

For energy storage, Chinese lithium-ion batteries for non-EV applications from 7.5% to 25%, more than tripling the tariff rate. This increase goes into effect in 2026.

There is also a general 3.4% tariff applied lithium-ion battery imports. Altogether, the full tariff paid by importers will increase from 10.9% to 28.4%.

Lithium-ion battery modules, packs, and container blocks are generally categorized under import code 8507.6020, and it said the tariff change will likely apply to imports under this code. CEA said further clarity is needed for the correct import code for lithium-ion cells.

CEA said it expects the tariff increase to raise total costs for U.S. integrators by about 11% to 16%.

“The delay to 2026 for the rate change on non-EV batteries gives the market time to adapt and for more non-China LFP facilities to come online to serve U.S. customers,” said CEA.

CEA said this includes LG’s LFP cell factory which is currently under construction in Arizona.

The report said the cost increases due to the new tariff rates may affect some projects with marginal economics, but overall CEA expects demand contraction due to the 301 tariff change to be “limited.”

Domestic content

On May 16, 2024 the U.S. Treasury Department updated its guidance for accessing the 10% domestic content tax credit adder made available through the Inflation Reduction Act (IRA). This relates to both the Section 48/48E Investment Tax Credit (ITC) and the Section 45/45Y Production Tax Credit (PTC).

IRS requires that structural construction components like steel and rebar foundation posts for solar projects are 100% U.S. manufactured. The rest of the materials, listed as “manufactured products,” must include domestic content for 40% of the cost, increasing to 55% over time.

The new guidance provides simplified calculations for assuming cost inputs to achieve the required threshold of domestic content to achieve the bonus. Find more information on how to calculate domestic content bonus eligibility here.

“Many project owners who CEA has spoken with have had difficulty getting direct cost information from their suppliers,” said the report from CEA. “Because this new method allows project owners to access the Domestic Content Bonus without this information, it makes the bonus easier to access.”

Read the related story: “Market impacts from the recent flurry of solar policy actions“

Renewable energy developer Ørsted announced it has secured a $680 million tax equity financing for a portfolio of solar and storage assets in Texas and Arizona.

The project portfolio includes Eleven Mile Solar Center, a 300 MW solar and 300 MW /1200 MWh storage project in Pinal County, Arizona and Sparta Solar, a 250 MW solar project in Mineral, Texas.

J.P. Morgan made the tax equity investment, comprised of production tax credit (PTC) and investment tax credit (ITC) assets available through the Inflation Reduction Act (IRA). Over 1.8 GW of Ørsted’s 5.7 GW portfolio is now supported by the investment bank.

The Eleven Mile Solar Center will receive a one-time investment tax credit for its battery storage system while the solar farm will generate production tax credits over a ten-year period.

The tax equity partnership includes options for tax credit transferability, a new option created by IRA. Tax credit transfers opened a new market for any corporate buyer to support clean energy projects and optimize their federal tax bill through purchasing tax credits.

“With this new market unlocked by the IRA, we’re excited to continue our tax equity partnership with J.P. Morgan and bring on new entities looking to advance the U.S. renewable energy industry, support job growth, and promote local economic development,” said James Giamarino, chief commercial officer for the Americas, Ørsted.

Latham & Watkins LLP served as legal counsel for Ørsted and Milbank LLP served as legal counsel for J.P. Morgan.

The tax equity investment is expected to help complete the two projects which total 550 MW solar capacity and 300 MW, 4-hour duration energy storage. Commercial operations for both projects are expected for 2024. The solar projects are expected to contribute a combined $125 million in tax revenue over the life of the projects for public services in the local communities.

The powerful solar storms of May 2024 were a sign of the sun’s increasing activity as it nears the peak of its 11-year cycle. These events can disrupt satellites and power grids, highlighting the importance of solar weather monitoring and preparedness.

Predicting solar flares and geomagnetic storms is challenging. Current technology struggles due to the sun’s constantly changing magnetic field, making it difficult to pinpoint the exact location and intensity of an eruption. However, agencies like the National Oceanic and Atmospheric Administration (NOAA) in the US and the European Space Agency collaborate to monitor solar activity and issue forecasts based on past observations and real-time data, helping us prepare for potential impacts.

Whilst solar storms are difficult to predict accurately ahead of time, we do know this solar cycle is expected to reach its maximum in 2025, meaning that there are more intense solar flares and geomagnetic storms on the way in the coming months and years.

For solar energy, for strong solar events the potential impacts on power grids, and the impacts on solar’s enabling technologies like GPS are very real. Solcast is sometimes asked about the impacts on solar irradiance and PV power production. Do we see an increase in irradiance at the peak of the 11-year cycle?

The answer is yes, but only slightly. The peak of the solar cycle does tend to increase the earth’s average annual extra-terrestrial irradiance, but only by a very small amount. Extra-terrestrial irradiance refers to the intensity of sunlight reaching the Earth’s upper atmosphere, essentially the amount of solar energy we would receive without any atmospheric interference. This value is often represented by the “solar constant,” which has a traditionally accepted average of around 1361 W/m². However, this isn’t a truly constant value. The Earth’s orbit around the Sun isn’t perfectly circular, but slightly elliptical. This means the distance between Earth and the Sun varies throughout the year. When Earth is closer to the Sun (perihelion in January), the extra-terrestrial irradiance can reach highs of about 1410 W/m². Conversely, when Earth is farthest from the Sun (aphelion in July), the irradiance dips to around 1320 W/m². This variation amounts to roughly a 3.5% fluctuation in the intensity of sunlight reaching the top of the atmosphere. This fluctuation is very accurately modeled in the irradiance modeling used by the Solcast API, DNV and other leading solar resource agencies.

Whilst the annual cycle of extra-terrestrial irradiance causes a steady, predictable and significant 3.5% change through the seasonal cycle, the peak of the 11-year cycle of solar activity causes a smaller, more sporadic and unpredictable set of fluctuations.

The net result of these increased fluctuations is an increase in extra-terrestrial irradiance (and therefore also the irradiance we receive at the ground) of only around 1 W/m² (i.e. only about one-tenth of one percent) when averaged over a year! The very small size of this effect, along with the random nature of the fluctuations, means there is very little value in attempting to even include the effect in solar irradiance modeling calculations.

Solcast produces these figures by tracking clouds and aerosols at 1-2km resolution globally, using satellite data and proprietary AI/ML algorithms. This data is used to drive irradiance models, enabling Solcast to calculate irradiance at high resolution, with typical bias of less than 2%, and also cloud-tracking forecasts. This data is used by more than 300 companies managing over 150GW of solar assets globally.

California transitioned its rooftop solar policy on April 15, 2023, eliminated net energy metering (NEM) and moving toward a net billing tariff (NBT) structure. The change essentially cut the rate paid to customers for exporting their excess solar production to the grid by about 80%. On year later, Lawerence Berkeley National Laboratory (LBNL) has released a report evaluating changes in the state’s rooftop solar market.

LNBL found that rooftop solar installations in California were roughly equal in 2023 to 2022. However, 80% of the systems installed were NEM 2.0 installations rushing into interconnection queues before the April 15, 2023 deadline to secure the more lucrative rate structure. To date, about 50,000 systems have been interconnected under the new NBT structure, in addition to 200,000 NEM systems interconnected over the same period.

Data from EnergySage, operator of the largest residential solar quote site in the U.S., are “suggestive of a more sustained downturn,” said the report.

Quote requests spiked during the December 2022-April 2023 window between announcement and implementation of NBT. Since then, monthly quote requests have averaged roughly 60% of historical (2019-2021) levels.

A 40% drop in historical quote requests is a “leading indicator” for market activity and “is perhaps the clearest signal yet of a substantial and sustained market contraction,” said LBNL.

A significant contraction of the rooftop solar market is not an ideal outcome for California, a state with ambitious clean energy goals and an electricity affordability crisis. Trade association leaders have warned that California is unlikely to reach its clean energy targets without robust contributions from the rooftop solar industry.

(Read the opinion piece: “We must push back on net billing“)

However, the transition to NBT has created some outcomes in California that may be desirable. The profile of an installed system has changed considerably. Pre-NBT, customers attached battery energy storage with their rooftop array in roughly 10% of installations. Now, post-NBT installations include batteries 60% of the time.

This is important for California’s grid operators, that seek to smooth out the mismatch between solar generated electricity supply and demands on the grid. This mismatch, often represented by the “duck curve,” has been deepening in California, causing pricing and grid maintenance issues, and creating a need for inefficient natural gas “peaker” plants to serve times of high demand and low generation.

The high battery attachment rate offers customers some benefits, too. While the overall sticker price goes up with a battery-attached system, the return on investment has improved relative to a solar-only installation.

Installers report a median payback period of eight years for solar systems with a battery, while standalone solar systems have a longer median payback period of about 10 years. Battery storage enables customers to store their solar production and use it when grid prices are at their highest, rather than selling it to the grid at pennies on the dollar on sunny afternoons. Solar-battery owners also have the option to be compensated for exporting power during peak demand events or emergencies, potentially creating a new stream of revenue.

Customers with batteries also benefit from having backup power during grid outages, which remains the number one reason for including batteries nationwide, according to an installer survey by SolarReviews.

“Since November 2023, residential storage installs have averaged roughly 5,000 systems per month, more than double the monthly pace over the preceding three years,” said the report from LBNL.

The Berkeley Labs report noted a change in financing options for residential solar customers. Over the final 12-months of NEM, third party ownership rates, including leased and power purchase agreement systems, averaged 26% for stand-alone solar and 11% for solar and storage systems. This jumped up to 39% for standalone solar and 52% for solar plus storage under the NBT system. Some of this change may be attributed to increased interest rates creating loan terms for customers that are more difficult to digest.

Finally, the Berkeley Labs report noted an increase in consolidation in the California rooftop solar market. The market share of the top five installers in the state rose from 40% during the last year of NEM to 51% during the first year of NBT.

One year in, it is clear that the change to NBT has drastically altered the California rooftop solar industry. However, the backlog of NEM orders being served in 2023 has made it unclear what the total effect of this policy change will bring. This sets the stage for 2024 being a critical proving ground for the health of this industry.

“These trends, and others, will no doubt come into sharper focus over the next year or so, once the NEM backlog is fully cleared and a ‘new normal’ under NBT sets in,” concluded Galen Barbose, staff scientist, LBNL.

A new bladeless wind energy unit, patented by Aeromine Technologies, has secured $9 million in Series A funding to accelerate the roll-out of its innovative technology. The scalable, “motionless” wind energy unit can produce 50% more energy than rooftop solar at the same cost, said the company.

Aeromine’s technology is primarily designed for installation on the edge of a large rooftop like an apartment building, a big box store, factory or warehouse, facing the predominant wind direction. The technology leverages aerodynamics like airfoils in a race car to capture and amplify each building’s airflow. The unit requires about 10% of the space required by solar panels and generates round-the-clock energy, as long as the wind is blowing.

Veriten, an energy research, investing, and strategy firm led the funding round, with participation from Thornton Tomasetti. The company said it has received nearly 11,000 inquiries from more than 6,500 companies and currently has a pipeline of 400 qualified projects. Its customers are primarily in industrial, logistics, automotive, commercial, and government sectors.

Aeromine said unlike conventional wind turbines that are noisy, visually intrusive and dangerous to migratory birds, the patented system is visually motionless and virtually silent. And unlike large centralized onshore and offshore wind farms, the space efficient systems are mounted on roofs, bringing power closer to where it is needed, and lessening the need for expensive long-distance transmission infrastructure.

“Distributed power is a key and increasingly strategic element to an evolving ‘all the above’ energy mix,” said Maynard Holt, founder & chief executive officer of Veriten. “We believe that distributed power innovation will play a vital role in helping companies fulfill their need for reliable, reasonably priced electricity and desire for low-impact power.

Each unit weighs just over 1,000 lbs., can withstand winds of 120 mph and can be upgraded to hurricane-resistant models that withstand winds up to 158 mph. The Aeromine generator system is a state-of-the-art rotor / stator system with a 5 kW permanent magnet generator. Product specifications can be found here.

A typical installation would connect 10 units or more, adding 50 kW of capacity to a roof. A ten-unit 50 kW system’s electricity generation varies widely. Aeromine said a roof height of 16 feet and 4.5 meters per second average wind speed would produce about 20,000 kWh per year, while the same 10-unit system on a 50-foot-high roof with 8 meters per second average wind speed would produce over 150,000 kWh per year.

Aeromine told pv magazine USA that “pricing is in line with comparatively rated roof top commercial solar power systems.” The company expects to introduce a commercial solution into the European and North American markets in 2025.

“Aeromine’s proprietary technology brings the performance of wind energy to the onsite generation market, mitigating legacy constraints posed by spinning wind turbines,” said Aeromine chief executive officer David Asarnow.

U.S. electric vehicle manufacturer Rivian announced it has entered a deal with Pivot Energy to purchase renewable energy certificates (RECs) as well as subscribe to a portion of a community solar project.

The agreement includes a subscription to 10 MW of off-site community solar to support Rivian’s Illinois manufacturing capacity. Rivian will also purchase RECs generated from 50 MW of operational solar assets.

The REC impact agreement is designed to support the development of projects where emissions reductions are needed the most. The REC-tied projects are designed to be installed in locations with few solar resources.

“According to the EPA, the region of the electric grid where the solar projects will be located is 67% dirtier than the U.S. grid as a whole, meaning that the region emits two-thirds more greenhouse gases from fossil fuels than other areas,” said Pivot Energy.

The new-build REC projects are expected to generated 79,000 megawatt-hours of electricity per year, equivalent to powering nearly 11,000 homes annually.

The two companies will invest $5,000 per MW built in local community organizations. The donations tied to each MW constructed will go to support local community-based organizations working to reduce energy burden for low-income families, developing workforce development pathways into the solar industry for local residents and groups working at the intersection of agriculture and energy production.

“Our partnership with Pivot shows how we go one step further by investing in projects that not only deliver additional clean energy to the grid, but also drive positive benefits for communities, conservation and the climate,” said Andrew Peterman, director of advanced energy solutions, Rivian.

Rivian’s decarbonization strategy includes plans to support 2 GW of renewable energy each year to support emissions-free EV charging. This is enough to power 7 billion miles of renewable driving with its R1 truck each year.

Rivian said its manufacturing facility in Normal, Illinois, aims to operate with greater than 90% carbon free energy on an hourly basis and will run on 100% renewable energy annually by 2030.

The United States federal government recently made a rapid series of international trade policy changes and updates to incentives for clean energy projects. The following is a roundup of these changes, along with insights on market impact.

AD/CVD initiated

On May 15, the Department of Commerce initiated its investigation for alleged antidumping and countervailing duty (AD/CVD) infractions in Vietnam, Malaysia, Thailand, and Cambodia. Historically, tariffs have ranged as high as 50% to 250% of the cost of shipped goods.

The International Trade Commission (ITC) must now make a preliminary determination on the investigation by June 10, 2024. ITC will determine whether the domestic industry has suffered injury from import of dumped goods.

Solar supply chain expert group Clean Energy Associates (CEA) said there is “no direct market impact” from the decision. However, the threat of AD/CVD is causing prices to increase, contracts to be re-negotiated, and is delaying procurement decisions, said CEA. It said project timelines are being pushed back as a result, particularly for projects planned for construction in 2025.

Domestic content bonus guidance

On May 16, the U.S. Treasury updated guidance on access the domestic content bonus under the Section 48/48E Investment Tax Credit and Section 45/45Y Production Tax Credit, tax credits made available via the Inflation Reduction Act. The bonus is a 10% adder to the base 30% tax credit for clean energy projects.

IRS requires that structural construction components like steel and rebar foundation posts for solar projects are 100% U.S. manufactured. The rest of the materials, listed as “manufactured products,” must include domestic content for 40% of the cost, increasing to 55% over time. 

Developers must collect three “direct costs” from equipment providers to calculate the manufactured product portion. The direct costs are the wages paid to factory workers, payroll taxes on those wages and the amount paid to component suppliers for parts supplied directly to the factory.

Clean energy developers now have the option to rely on Department of Energy provided data on default cost percentages for an exhaustive list of manufactured products and their components. This safe harbor data can be used in lieu of obtaining direct cost information from suppliers. The updates are expected to make the bonus easier for project developers to access. 

“However, even for those solar projects utilizing trackers with a high portion of domestic content, most projects will still need a domestic cell or a First Solar module to qualify, and these are in limited supply,” said CEA. “Therefore, while CEA expects more projects to now qualify for the Domestic Content Bonus (particularly in 2026 and thereafter), the number of projects will still be limited.”

Bifacial exemption removed

Also on May 16, the Biden Administration reinstated tariffs on bifacial solar modules, which generate electricity on both sides of the panel. Bifacial solar modules were previously exempt from tariffs, and the removal of the exemption reinstates a 15% tariff.

The reinstatement of this tariff is expected to increase the cost of commercial, industrial and utility-scale solar projects by 1% to 2%.

With the removal of this exemption, the cost of imported bifacial solar panels, typically ranging from $0.10 to 0.25 per watt, will increase by $0.015 to $0.0375 per watt. For commercial projects with installation costs between $1.50 and $2.75 per watt, these increases will result in system price hikes of about 1-2%. Bifacial panels now represent 98% of all solar panels imported into these sectors.

The Administration also maintained a tariff-rate quota, a volume of solar cells that can be imported without paying the 201 tariff. This will be set at 5 GW, though Biden said if the total volume of cell imports reaches 5 GW in a year, he has the power to raise the tariff-exempt cells by 7.5 GW to a total of 12.5 GW.

CEA said the removal of the bifacial exemption is expected to have a limited impact on module prices, as around half the tariff cost is expected to be absorbed by suppliers. However, combined with AD/CVD duties, 201 tariffs could “significantly disadvantage products from Southeast Asia in the U.S. market,” said CEA.

Section 301 tariffs raised

On May 14, the Biden Administration announced changes to Section 301 tariffs on imports of electric vehicles, solar, battery energy storage, and related components.

Tariffs on solar cells and modules shipped from China were raised from 25% to 50%. A range of exemptions were provided for solar cell and module manufacturing equipment, which were previously exposed to 25% tariffs.

Clean Energy Associates said the tariffs on Chinese solar cells and modules “are largely performative” as the U.S. only imports about 1% of its solar cells and modules directly from China.

“The removal of tariffs on solar manufacturing equipment will reduce capital expenditure costs for U.S. cell and module factories, making it easier to set up these factories and making U.S. cell and module production marginally less expensive and more competitive with imports,” said CEA.

In a follow-up report, pv magazine USA will review recent policy change effects on the energy storage market.